Unit (UNTC) 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	798,949
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		51,022,722
Entity Well-known Seasoned Issuer	No
Entity Public Float			$ 726,406,732
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 835	$ 1,049
Accounts receivable (less allowance for doubtful accounts of $5,199 and $5,039 at December 31, 2015 and 2014, respectively)	79,941	189,812
Materials and supplies	3,565	5,590
Current derivative asset (Note 12)	10,186	31,139
Current income tax receivable	21,002	0
Current deferred tax asset (Note 8)	14,206	11,527
Assets held for sale (Note 2)	615	0
Prepaid expenses and other	9,908	13,374
Total current assets	140,258	252,491
Oil and natural gas properties, on the full cost method:
Proved properties	5,401,618	4,990,753
Unproved properties not being amortized	337,099	485,568
Drilling equipment	1,567,560	1,620,692
Gas gathering and processing equipment	689,063	628,689
Saltwater disposal systems	60,316	56,702
Corporate land and building	49,890	16,104
Transportation equipment	40,072	40,693
Other	45,489	41,602
Property, plant and equipment, gross, total	8,191,107	7,880,803
Less accumulated depreciation, depletion, amortization, and impairment	5,609,980	3,747,412
Net property and equipment	2,581,127	4,133,391
Debt issuance cost	8,667	10,255
Goodwill (Note 2)	62,808	62,808
Non-current derivative asset (Note 12)	968	0
Other assets	14,681	14,783
Total assets	2,808,509	4,473,728
Current liabilities:
Accounts payable	87,413	218,500
Accrued liabilities (Note 5)	46,918	70,171
Income taxes payable	0	481
Current portion of other long-term liabilities (Note 6)	16,560	15,019
Total current liabilities	150,891	304,171
Long-term debt (Note 6)	927,662	812,163
Non-current derivative liabilities (Note 12)	285	0
Other long-term liabilities (Note 6)	140,341	148,785
Deferred income taxes (Note 8)	275,750	876,215
Commitments and contingencies (Note 15)	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, 50,413,101 and 49,593,812 shares issued as of December 31, 2015 and 2014, respectively	9,831	9,732
Capital in excess of par value	486,571	468,123
Retained earnings	817,178	1,854,539
Total shareholders' equity	1,313,580	2,332,394
Total liabilities and shareholders' equity	$ 2,808,509	$ 4,473,728

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 5,199	$ 5,039
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	$ 0.2	$ 0.2
Common stock, shares authorized	175,000,000	175,000,000
Common stock, shares issued	50,413,101	49,593,812

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Oil and natural gas	$ 385,774	$ 740,079	$ 649,718
Contract drilling	265,668	476,517	414,778
Gas gathering and processing	202,789	356,348	287,354
Total revenues	854,231	1,572,944	1,351,850
Oil and natural gas
Operating costs	166,046	187,916	184,001
Depreciation, depletion, and amortization	251,944	276,088	226,498
Impairment of oil and natural gas properties (Note 2)	1,599,348	76,683	0
Contract drilling
Operating costs	156,408	274,933	247,280
Depreciation	56,135	85,370	71,194
Impairment of contract drilling equipment (Note 2)	8,314	74,318	0
Gas gathering and processing
Operating costs	161,556	306,831	243,406
Depreciation and amortization	43,676	40,434	33,191
Impairment of gas gathering and processing systems (Note 2)	26,966	7,068	0
General and administrative	35,345	42,023	38,323
(Gain) loss on disposition of assets	7,229	(8,953)	(17,076)
Total expenses	2,512,967	1,362,711	1,026,817
Income (loss) from operations	(1,658,736)	210,233	325,033
Other income (expense):
Interest, net	(31,963)	(17,371)	(15,015)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	26,345	30,147	(8,374)
Other	45	(70)	(175)
Total other income (expense)	(5,573)	12,706	(23,564)
Income (loss) before income taxes	(1,664,309)	222,939	301,469
Income tax expense (benefit):
Current	(20,616)	9,378	15,991
Deferred	(606,332)	77,285	100,732
Income tax expense (benefit)	(626,948)	86,663	116,723
Net income (loss)	$ (1,037,361)	$ 136,276	$ 184,746
Net income (loss) per common share:
Basic	$ (21.12)	$ 2.80	$ 3.83
Diluted	$ (21.12)	$ 2.78	$ 3.80

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income (loss)	$ (1,037,361)	$ 136,276	$ 184,746
Other comprehensive income (loss), net of taxes:
Change in value of derivative instruments used as cash flow hedges, net of tax of $0, $0, and ($4,717)	0	0	(7,349)
Reclassification - derivative settlements, net of tax of $0, $0, and ($249)	0	0	(354)
Ineffective portion of derivatives, net of tax of $0, $0, and $74	0	0	116
Comprehensive income (loss)	$ (1,037,361)	$ 136,276	$ 177,159

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Loss) Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in value of derivative instruments used as cash flow hedges, tax	$ 0	$ 0	$ (4,717)
Reclassification - derivative settlements, tax	0	0	(249)
Ineffective portion of derivatives, tax	$ 0	$ 0	$ 74

Consolidated Statements of Chan

Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Capital In Excess of Par Value	Accumulated Other Comprehensive Income	Retained Earnings
Beginning balances at Dec. 31, 2012	$ 1,974,301	$ 9,594	$ 423,603	$ 7,587	$ 1,533,517
Comprehensive income:
Net income (loss)	184,746	0	0	0	184,746
Other comprehensive loss, net of tax	(7,587)	0	0	(7,587)	0
Comprehensive income (loss)	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 (loss)	136,276	0	0	0	136,276
Other comprehensive loss, net of tax				0
Comprehensive income (loss)	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
Comprehensive income:
Net income (loss)	(1,037,361)	0	0	0	(1,037,361)
Other comprehensive loss, net of tax				0
Comprehensive income (loss)	(1,037,361)
Activity in employee compensation plans	18,547	99	18,448	0	0
Ending balances at Dec. 31, 2015	$ 1,313,580	$ 9,831	$ 486,571	$ 0	$ 817,178

Consolidated Statements of Cha8

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Activity in employee compensation plans (shares)	819,289	486,808	525,056
Other comprehensive income, tax	$ 0	$ 0	$ (4,892)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES:
Net income (loss)	$ (1,037,361)	$ 136,276	$ 184,746
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	354,830	404,943	333,907
Impairment of properties (Note 2)	1,634,628	158,069	0
(Gain) loss on derivatives	(26,345)	(30,147)	7,771
Cash (payments) receipts on derivatives settled	46,615	(6,038)	(1,161)
(Gain) loss on disposition of assets	7,229	(8,953)	(17,076)
Deferred tax expense (benefit)	(606,332)	77,285	100,732
Employee stock compensation plans	21,468	24,320	21,317
Bad debt expense	1,191	3,562	0
ARO liability accretion	3,453	4,599	5,450
Other, net	(1,517)	1,068	2,250
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	105,426	(60,800)	2,967
Materials and supplies	1,507	2,602	(2,435)
Prepaid expenses and other	(14,348)	(444)	1,813
Accounts payable	(20,306)	4,715	15,715
Accrued liabilities	(22,920)	(1,297)	17,198
Contract advances	(274)	(767)	1,137
Net cash provided by operating activities	446,944	708,993	674,331
INVESTING ACTIVITIES:
Capital expeditures	(561,453)	(981,374)	(703,984)
Producing property and other acquisitions	(179)	(5,723)	0
Proceeds from disposition of property and equipment	11,854	66,197	120,910
Other	0	303	3,894
Net cash used in investing activities	(549,778)	(920,597)	(579,180)
FINANCING ACTIVITIES:
Borrowings under line of credit	618,500	725,800	222,500
Payments under line of credit	(503,500)	(559,800)	(293,600)
Payments on capitalized leases	(3,549)	(2,392)	0
Proceeds from exercise of stock options	0	1,083	574
Excess Tax Benefit from Share-based Compensation, Financing Activities	(3,207)	1,614	8
Increase (decrease) in book overdrafts (Note 2)	(5,624)	27,755	(7,014)
Net cash provided by (used in) financing activities	102,620	194,060	(77,532)
Net increase (decrease) in cash and cash equivalents	(214)	(17,544)	17,619
Cash and cash equivalents, beginning of year	1,049	18,593	974
Cash and cash equivalents, end of year	835	1,049	18,593
Supplemental disclosure of cash flow information:
Interest paid (net of capitalization)	30,910	13,620	12,485
Income taxes	3,540	15,898	9,100
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	105,157	(31,968)	(6,550)
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	5,694	37,689	17,952
Non-cash additions to property, plant, and equipment acquired under capital leases	$ 0	$ (28,202)	$ 0

Organization

Organization	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	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. Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, 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, Wyoming, North Dakota, and to a lesser extent in Louisiana and Kansas. Historically, our contract drilling segment experienced more demand for natural gas drilling as opposed to drilling for oil and NGLs. Since 2008, operators have been focusing more on drilling for oil and NGLs. 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 Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	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 10 to 90 days. At December 31, 2015 , all of our contracts were daywork contracts of which nine were multi-well and had durations which ranged from six months to three years , five of which expire in 2016 and four expiring in 2017. 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, 2015 and 2014 , book overdrafts were $22.1 million and $27.8 million , respectively. 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: 2015 2014 2013 Oil and Natural Gas: Sunoco Logistics Partners L.P. 19 % 14 % 8 % Valero Energy Corporation 15 % 24 % 25 % Drilling: QEP Resources, Inc. 25 % 19 % 18 % Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) 7 % 9 % 10 % Mid-Stream: ONEOK Partners, L.P. 29 % 44 % 57 % Tenaska Resources, LLC 18 % 22 % 16 % Laclede Group, Inc. 12 % 16 % 7 % We had a concentration of cash of $2.3 million and $18.4 million at December 31, 2015 and 2014 , 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, 2015 and determined there was no material risk at that time. At December 31, 2015 , the fair values of the net assets we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: December 31, 2015 (In millions) Canadian Imperial Bank of Commerce $ 8.7 Bank of Montreal 1.1 Scotiabank 0.7 Bank of America Merrill Lynch 0.4 Total assets $ 10.9 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 drilling 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. As of December 31, 2015, with continuing declines to commodity prices and an outlook that commodity prices may be lower for longer, we lowered our expectations about future utilization of our drilling rigs and associated cash flows. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling segment. With respect to these assets, future cash flows were estimated over the expected remaining life of the assets. Management determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets within our contract drilling segment by 99% , and there was no impairment at December 31, 2015. 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 environment and based on the estimated market value from third-party assessments, we recorded a write-down of approximately $74.3 million , pre-tax. During the first quarter of 2015, we sold one of these drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig resulting in a gain of $7,900 . During the second quarter, we recorded an additional write-down on the remaining drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During the third quarter, we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. Some of the equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held for sale. The net book value of those assets is $0.6 million . 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 2015, our mid-stream segment incurred a $27.0 million , pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. In 2014, our mid-stream segment incurred 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 not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. 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 2015 , 2014 , and 2013 , interest of approximately $21.7 million , $32.2 million , and $33.7 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 drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2015 , 2014 , or 2013 . There were no additions to goodwill in 2015 , 2014 , or 2013 . Based on our impairment test performed as of December 31, 2015, the fair value of our drilling segment exceeded its carrying value by 19% . Goodwill of $2.2 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, 2015 , 2014 , or 2013 . Amortization of $0.7 million was recorded 2013 . Accumulated amortization for 2013 was $18.0 million . Our intangible assets became fully amortized in 2013, so no amortization was recorded in 2014 or 2015. 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 $19.2 million , $23.7 million , and $21.5 million were capitalized in 2015 , 2014 , and 2013 , respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $12.30 , $14.82 , and $13.32 per Boe in 2015 , 2014 , and 2013 , 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 $337.1 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. 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. Those determinations resulted in $73.7 million (in 2014) and $114.4 million (in 2015) of costs being added to the total of our capitalized costs being amortized. We incurred a $76.7 million pre-tax ( $47.7 million net of tax) non-cash ceiling test write-down of our oil and natural gas properties in 2014. In 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion pre-tax ( $1.0 billion net of tax) in 2015 due to the inclusion of the impaired value of those unproved properties and a reduction of the 12-month average commodity prices during the year. 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 statement of operations, 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 $22.1 million , $89.5 million , and $64.3 million for 2015 , 2014 , and 2013 , respectively from our contract drilling segment and eliminated the associated operating expense of $18.3 million , $62.4 million , and $46.9 million during 2015 , 2014 , and 2013 , respectively, yielding $3.8 million , $27.1 million , and $17.4 million during 2015 , 2014 , and 2013 , 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 $1.0 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 coverages we have will adequately protect us against liability from all potential consequences. Unit Texas Drilling, L.L.C. was merged into its parent company, Unit Drilling Company, effective October 31, 2015, at which time the ERISA governed occupational injury benefit program was closed. All new claims after this date are processed under an existing insured workers’ compensation program. 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 Operations. 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, 2015 balancing position to be approximately 4.7 Bcf on under-produced properties and approximately 4.8 Bcf on over-produced properties. We have recorded a receivable of $2.5 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 $5.0 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. Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact it will have on our financial statements. Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We do not expect the adoption of this guidance will have a material impact on our financial statements. 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 FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are in the process of evaluating the impact it will have on our financial statements.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2015
Acquisitions and divestitures [Abstract]
Divestitures	DIVESTITURES Oil and Natural Gas 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 , $33.1 million , and $1.9 million in 2013, 2014, and 2015, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized. Contract Drilling 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. These four drilling rigs 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 . During the first quarter of 2015, we sold one drilling rig to an unaffiliated third party for $0.3 million resulting in a gain of $7,900 . During the third quarter, we sold 30 drilling rigs, some old top drive equipment, and drill pipe in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	EARNINGS (LOSS) PER SHARE The following data shows the amounts used in computing earnings (loss) per share: Income (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) 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 $ 3.80 For the year ended December 31, 2014: Basic earnings per common share $ 136,276 48,611 $ 2.80 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, 2015: Basic earnings (loss) per common share $ (1,037,361 ) 49,110 $ (21.12 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted earnings (loss) per common share $ (1,037,361 ) 49,110 $ (21.12 ) Due to the net loss for the year ended December 31, 2015, approximately 186,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share calculation above. 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: 2015 2014 2013 Options and SARs 261,270 73,500 149,665 Average exercise price $ 50.34 $ 64.43 $ 58.41

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2015
Accrued Liabilities [Abstract]
Accrued Liabilities [Text Block]	ACCRUED LIABILITIES Accrued liabilities consisted of the following as of December 31: 2015 2014 (In thousands) Lease operating expenses $ 17,220 $ 20,709 Employee costs 12,641 31,451 Interest payable 6,321 6,654 Taxes 3,767 3,284 Third-party credits 3,326 2,825 Other 3,643 5,248 Total accrued liabilities $ 46,918 $ 70,171

Long-Term Debt And Other Long-T

Long-Term Debt And Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2015
Long-term debt and other long-term liabilites [Abstract]
Long-term Debt	LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES Long-Term Debt Long-term debt consisted of the following as of December 31: 2015 2014 (In thousands) Credit agreement with an average interest rates of 2.6% and 2.9% at December 31, 2015 and 2014, respectively $ 281,000 $ 166,000 6.625% senior subordinated notes due 2021, net of unamortized discount of $3.3 million and $3.8 million at December 31, 2015 and 2014, respectively 646,662 646,163 Total long-term debt $ 927,662 $ 812,163 Credit Agreement. On April 10, 2015, we amended our Senior Credit Agreement (credit agreement) to extend the maturity date from September 13, 2016 to April 10, 2020 . 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 $550.0 million . We are charged a commitment fee ranging from 0.375% to 0.50% 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. To date, for this new amendment, we paid $2.6 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. Effective with the October 2015 redetermination, the lenders under our credit agreement decreased our borrowing base from $725.0 million to $550.0 million . 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, 2015 , we had $281.0 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, 2015 , we were in compliance with the covenants contained in the credit agreement. 6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million , 6.625% senior subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021 . 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 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, 2015 . Other Long-Term Liabilities Other long-term liabilities consisted of the following as of December 31: 2015 2014 (In thousands) ARO liability $ 98,297 $ 100,567 Capital lease obligations 22,466 25,876 Workers’ compensation 16,551 17,997 Separation benefit plans 9,886 11,276 Gas balancing liability 5,047 3,623 Deferred compensation plan 4,244 4,055 Other 410 410 156,901 163,804 Less current portion 16,560 15,019 Total other long-term liabilities $ 140,341 $ 148,785 Estimated annual principal payments under the terms of debt and other long-term liabilities from 2016 through 2020 are $16.6 million , $5.7 million , $59.9 million , $9.5 million , and $290.0 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 $3.5 million is included in current portion of other long-term liabilities and the non-current portion of $18.9 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2015 . These capital leases are discounted using annual rates of 4.0% . Total maintenance and interest remaining related to these leases are $9.4 million and $2.7 million , respectively at December 31, 2015 . Annual payments, net of maintenance and interest, average $4.0 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, 2015 are as follows: Amount Ending December 31, (In thousands) 2016 $ 6,168 2017 6,168 2018 6,168 2019 6,168 2020 6,168 2021 3,769 Total future payments 34,609 Less payments related to: Maintenance 9,445 Interest 2,698 Present value of future minimum payments $ 22,466

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets (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: 2015 2014 (In thousands) ARO liability, January 1: $ 100,567 $ 133,657 Accretion of discount 3,453 4,599 Liability incurred 6,754 6,246 Liability settled (2,893 ) (4,490 ) Liability sold (421 ) (1,206 ) Revision of estimates (1) (9,163 ) (38,239 ) ARO liability, December 31: 98,297 100,567 Less current portion 3,965 3,204 Total long-term ARO liability $ 94,332 $ 97,363 _________________________ (1) Plugging liability estimates were revised in both 2015 and 2014 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, 2015
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows: 2015 2014 2013 (In thousands) Income tax expense (benefit) computed by applying the statutory rate $ (582,508 ) $ 78,029 $ 105,514 State income tax, net of federal benefit (45,768 ) 6,131 8,290 Statutory depletion and other 1,328 2,503 2,919 Income tax expense (benefit) $ (626,948 ) $ 86,663 $ 116,723 For the periods indicated, the total provision for income taxes consisted of the following: 2015 2014 2013 (In thousands) Current taxes: Federal $ (20,612 ) $ 8,594 $ 15,845 State (4 ) 784 146 (20,616 ) 9,378 15,991 Deferred taxes: Federal (535,691 ) 68,360 87,839 State (70,641 ) 8,925 12,893 (606,332 ) 77,285 100,732 Total provision $ (626,948 ) $ 86,663 $ 116,723 Deferred tax assets and liabilities are comprised of the following at December 31: 2015 2014 (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 56,479 $ 55,231 Net operating loss carryforward 140,863 54,901 Alternative minimum tax and research and development tax credit carryforward 5,409 25,991 202,751 136,123 Deferred tax liability: Depreciation, depletion, amortization, and impairment (464,295 ) (1,000,811 ) Net deferred tax liability (261,544 ) (864,688 ) Current deferred tax asset 14,206 11,527 Non-current—deferred tax liability $ (275,750 ) $ (876,215 ) 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, 2015 , we have federal net operating loss carryforwards of approximately $351.4 million which expire from 2021 to 2035 . 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 2012. 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: 2015 2014 2013 (In thousands) Balance at January 1: $ 410 $ — $ — 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 $ 410 $ — At December 31, 2015 and 2014, there was $0.4 million of unrecognized tax benefits that if recognized would affect the annual effective tax rate. We did no t have any unrecognized tax benefits in 2013.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
Employee benefit plans [Abstract]
Employee Benefit Plans	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 235,104 , 120,333 , and 111,995 shares of common stock and recognized expense of $6.2 million , $5.2 million , and $6.0 million in 2015 , 2014 , and 2013 , 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, 2015 and 2014 was $4.2 million and $4.1 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. On December 8, 2015, we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $3.0 million , $2.7 million , and $2.4 million in 2015 , 2014 , and 2013 , 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 Parti

Transactions With Related Parties	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Transactions With Related Parties	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 non-employee partnerships were formed in 1984 and two in 1986. Effective December 31, 2014, the 1984 partnership was dissolved. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. 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: 2015 2014 2013 (In thousands) Contract drilling $ — $ 4 $ 16 Well supervision and other fees 423 435 470 General and administrative expense reimbursement 18 39 36 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 25.8% owner of Rampart Holdings, Inc. which owns 100% 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 20.0% of the company. In 2014, there were two wells drilled for Toklan, one of which was completed in 2014 and one of which was completed in 2015 with no activity in 2013. 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 recognized revenue from Toklan of approximately $0.5 million in 2015 and $1.5 million in 2014. During 2014, we received payments of $1.1 million and had an accounts receivable balance of $0.4 million at December 31, 2014. During 2015, we received payments of $0.9 million with no accounts receivable balance at December 31, 2015. The Company also paid royalties in 2014, in the ordinary course of business, of approximately $0.2 million to Toklan. There were no material royalties to disclose for 2013 or 2015. Also in 2015, Toklan paid $0.5 million for the North Custer Gathering System, an inactive (since 2009) gathering system owned by our mid-stream segment. We determined that the capital required to re-activate that system would not provide adequate returns based on future cash flow potential. If the system had not been sold to Toklan, it would have been included in a multi-system asset sales package in which little value would have been assigned to it. Toklan operates the North Custer Gathering System under its affiliate, West Thomas Field Services, LLC (West Thomas), a company in which Mr. John Nikkel holds an approximate 25.0% ownership interest and in which Mr. Robert Nikkel has an ownership interest of approximately 20.0% . West Thomas entered into a gas purchase agreement with our exploration and production segment in November of 2015. Payments from West Thomas under that contract amounted to $0.1 million for 2015 volumes purchased. One of our directors, G. Bailey Peyton IV, also serves as Manager of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. The Company in the ordinary course of business, paid royalties or lease bonuses, 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 $0.8 million , $1.3 million , and $1.4 million during 2015, 2014, and 2013, 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.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	STOCK-BASED COMPENSATION For restricted stock awards, we had: 2015 (1) 2014 2013 (In millions) Recognized stock compensation expense $ 15.3 $ 17.4 $ 16.1 Capitalized stock compensation cost for our oil and natural gas properties 3.5 3.7 3.5 Tax benefit on stock based compensation 5.8 6.7 6.2 _________________________ (1) Recognized stock compensation was reduced by $3.2 million , capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million , and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares. The remaining unrecognized compensation cost related to unvested awards at December 31, 2015 is approximately $13.8 million of which $2.4 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of a year. The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors. A total of 4,500,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan 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 amended plan is as follows: Number of Shares Weighted Average Price Outstanding at January 1, 2013 145,901 $ 46.59 Granted — — Exercised — — Forfeited — — Outstanding at December 31, 2013 145,901 46.59 Granted — — Exercised (14,131 ) 46.50 Forfeited — — Outstanding at December 31, 2014 131,770 46.60 Granted — — Exercised — — Forfeited — — Outstanding at December 31, 2015 131,770 $ 46.60 There were no SARs granted or vested during 2015 , 2014 , or 2013 . Outstanding and Exercisable SARs at December 31, 2015 Exercise Prices Number of Shares Weighted Average Remaining Weighted Average $44.31 91,255 2.0 years $44.31 $51.76 40,515 0.9 years $51.76 There were no SARs exercised in 2015 . 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, 2015 . The remaining weighted average contractual term is 1.6 years . Restricted Stock Activity pertaining to restricted stock awards granted under the amended plan is as follows: Employees Number of Time Vested Shares Number of Performance Vested Shares Total Number of Shares Weighted Average Price Nonvested at January 1, 2013 523,024 66,503 589,527 $ 48.11 Granted 396,144 57,405 453,549 48.20 Vested (248,003 ) — (248,003 ) 46.46 Forfeited (18,330 ) — (18,330 ) 47.85 Nonvested at December 31, 2013 652,835 123,908 776,743 48.70 Granted 383,448 71,674 455,122 53.72 Vested (291,712 ) (13,092 ) (304,804 ) 49.68 Forfeited (19,805 ) (6,970 ) (26,775 ) 51.92 Nonvested at December 31, 2014 724,766 175,520 900,286 50.81 Granted 576,361 148,081 724,442 34.06 Vested (343,657 ) (39,245 ) (382,902 ) 49.69 Forfeited (20,808 ) (7,196 ) (28,004 ) 45.33 Nonvested at December 31, 2015 936,662 277,160 1,213,822 $ 41.29 Non-Employee Directors Number of Shares Weighted Average Price Nonvested at January 1, 2013 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 Granted 25,848 34.04 Vested (18,920 ) 46.51 Forfeited — — Nonvested at December 31, 2015 42,064 $ 41.83 The time vested restricted stock awards granted are being recognized over a three year vesting period. The performance vested restricted stock awards, granted to certain executive officers, will cliff vest three years from the grant date 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 a probability assessment of the selected performance criteria at December 31, 2015, the participants are estimated to receive 2% of the 2015, 57% of the 2014, and 10% of the 2013 performance based shares. The fair value of the restricted stock granted in 2015 , 2014 , and 2013 at the grant date was $24.5 million , $24.1 million , and $21.3 million , respectively. The aggregate intrinsic value of the 401,822 shares of restricted stock that vested in 2015 on their vesting date was $11.2 million . The aggregate intrinsic value of the 1,255,886 shares of restricted stock outstanding subject to vesting at December 31, 2015 was $15.3 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. During 2015, the remaining options expired. Activity pertaining to the Stock Option Plan is as follows: Number of Shares Weighted Average Exercise Price Outstanding at January 1, 2013 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 Granted — — Exercised — — Forfeited (9,500 ) 37.69 Outstanding at December 31, 2015 — $ — There were no shares that vested in 2015 , 2014 , or 2013 . There were no options exercised in 2015 and no options outstanding or exercisable in this plan at December 31, 2015. 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. 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 Shares Weighted Average Exercise Price Outstanding at January 1, 2013 192,500 $ 49.39 Granted — — Exercised (17,500 ) 32.53 Forfeited (3,500 ) 20.46 Outstanding at December 31, 2013 171,500 51.70 Granted — — Exercised (21,000 ) 33.94 Forfeited — — Outstanding at December 31, 2014 150,500 54.18 Granted — — Exercised — — Forfeited (21,000 ) 54.35 Outstanding at December 31, 2015 129,500 $ 54.15 There were no options exercised in 2015 . Outstanding and Exercisable Weighted Average Exercise Price Number of Shares Weighted Average Remaining Weighted Average $31.30 - $41.21 38,500 3.9 years $ 37.58 $53.81 - $73.26 91,000 2.6 years $ 61.16 There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2015 . The remaining weighted average remaining contractual term is 3.0 years .

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	DERIVATIVES Commodity Derivatives We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract is based, in part, on our view of current and future market conditions. As of December 31, 2015 , 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. • Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put) and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price. 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 statement of operations and not in accumulated other comprehensive income (OCI). As of December 31, 2013, all cash flow hedges had expired. At December 31, 2015 , the following non-designated hedges were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Jan’16 – Dec’16 Natural gas – swap 35,000 MMBtu/day $2.625 IF – NYMEX (HH) Jan’16 – Dec'16 Natural gas – collar 42,000 MMBtu/day $2.40 - $2.88 IF – NYMEX (HH) Jan’16 – Dec'16 Natural gas – three-way collar 13,500 MMBtu/day $2.70 - $2.20 - $3.26 IF – NYMEX (HH) Jan’17 – Dec'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH) Jan’16 – Jun'16 Crude oil – collar 2,150 Bbl/day $46.36 - $55.62 WTI – NYMEX Jul’16 – Dec'16 Crude oil – collar 1,450 Bbl/day $47.50 - $56.40 WTI – NYMEX Jan’16 – Dec'16 Crude oil – three-way collar 700 Bbl/day $46.50 - $35.00 - $57.00 WTI – NYMEX Jul’16 – Dec'16 Crude oil – three-way collar (1) 700 Bbl/day $47.50 - $35.00 - $63.50 WTI – NYMEX Jan’17 – Dec'17 Crude oil – three-way collar 750 Bbl/day $50.00 - $37.50 - $63.90 WTI – NYMEX _________________________ (1) We pay our counterparty a premium, which can be and is being deferred until settlement. Subsequent to December 31, 2015 , the following non-designated hedges were entered into: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Feb’16 – Dec'16 Natural gas – swap 10,000 MMBtu/day $2.495 IF – NYMEX (HH) Jan’17 – Dec'17 Natural gas – swap 10,000 MMBtu/day $2.795 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 2015 2014 (In thousands) Commodity derivatives: Current Current derivative assets $ 10,186 $ 31,139 Long-term Non-current derivative assets 968 — Total derivative assets $ 11,154 $ 31,139 Derivative Liabilities Fair Value Balance Sheet Location 2015 2014 (In thousands) Commodity derivatives: Current Current derivative liabilities $ — $ — Long-term Non-current derivative liabilities 285 — Total derivative liabilities $ 285 $ — 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, 2015 or 2014 . Effect of Derivative Instruments on the Consolidated Statements of Operations (derivatives not designated as hedging instruments) for the year ended December 31: Derivatives Not Designated as Hedging Instruments Location of Gain or (Loss) Recognized in Income on Derivative Amount of Gain or (Loss) Recognized in Income on Derivative 2015 2014 (In thousands) Commodity derivatives Gain on derivatives not designated as hedges and hedge ineffectiveness, net (1) $ 26,345 $ 30,147 Total $ 26,345 $ 30,147 _________________________ (1) Amount settled during the period is a gain of $46,615 and a loss of $6,038 , respectively.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value 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: December 31, 2015 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 2,794 $ 10,145 $ (1,785 ) $ 11,154 Liabilities (1,019 ) (1,051 ) 1,785 (285 ) $ 1,775 $ 9,094 $ — $ 10,869 December 31, 2014 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 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, 2015. 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, December 31, 2015 December 31, 2014 (In thousands) Beginning of period $ 3,355 $ (2,595 ) Total gains or losses: Included in earnings (1) 15,260 6,108 Settlements (9,521 ) (158 ) End of period $ 9,094 $ 3,355 Total gains for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period $ 5,739 $ 5,950 _________________________ (1) Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2015 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil collars $ 3,893 Discounted cash flow Forward commodity price curve $0.40 - $55.05 Oil three-way collar 3,470 Discounted cash flow Forward commodity price curve $0.40 - $71.66 Natural gas collar 1,000 Discounted cash flow Forward commodity price curve $0.40 - $1.26 Natural gas three-way collar 731 Discounted cash flow Forward commodity price curve $0.40 - $1.93 _________________________ (1) The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way 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, 2015 , 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, 2015 , 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, 2015 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, 2015 and December 31, 2014 were $646.7 million and $646.2 million , respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2015 and December 31, 2014 were $455.5 million and $605.5 million , respectively. These Notes would be classified as Level 2. Fair Value of Non-Financial Instruments The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented in Note 7 – Asset Retirement Obligations. Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2015 and 2014, we recorded non-cash impairment charges discussed further in Note 2 – Summary of Significant Accounting Policies. The valuation of these assets require the use of significant unobservable inputs classified as Level 3.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Accumulated other comprehensive income	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 2015 2014 2013 (In thousands) Balance at January 1: $ — $ — $ 7,587 Other comprehensive income before reclassification — — (7,349 ) Amounts reclassified from accumulated other comprehensive income — — (238 ) New current-period other comprehensive income — — (7,587 ) Balance at December 31: $ — $ — $ — Amounts reclassified from accumulated other comprehensive income (loss) into the Consolidated Statements of Operations for the year ended December 31: 2015 2014 2013 Affected Line Item in the Statement Where Net Income is Presented (In thousands) Net gains (loss) on cash flow hedges Commodity derivatives $ — $ — $ 603 Oil and natural gas revenues Commodity derivatives — — (190 ) Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net — — 413 Total before tax — — (175 ) Tax expense Total reclassification for the period $ — $ — $ 238 Net of tax

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	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 December 2021 . 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 $6.4 million , $1.0 million , and $0.7 million , in 2016 through 2018, respectively and less than $0.1 million each in 2019 and 2020. Total rent expense incurred was $12.9 million , $13.6 million , and $16.9 million in 2015 , 2014 , and 2013 , 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 2020 and approximately $3.8 million in 2021. Total maintenance and interest remaining related to these leases are $9.4 million and $2.7 million , respectively at December 31, 2015 . Annual payments, net of maintenance and interest, average $4.0 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 $118,000 , $45,000 , $16,000 in 2015 , 2014 , and 2013 , 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 2016, we have committed to purchase approximately $6.7 million 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. 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, 2015
Segment Reporting [Abstract]
Industry Segment Information	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: 2015 2014 2013 (In thousands) Revenues : Oil and natural gas $ 385,774 $ 740,079 $ 649,718 Contract drilling 287,767 566,012 479,091 Elimination of inter-segment revenue (22,099 ) (89,495 ) (64,313 ) Contract drilling net of inter-segment revenue 265,668 476,517 414,778 Gas gathering and processing 268,012 445,934 378,397 Elimination of inter-segment revenue (65,223 ) (89,586 ) (91,043 ) Gas gathering and processing net of inter-segment revenue 202,789 356,348 287,354 Total revenues $ 854,231 $ 1,572,944 $ 1,351,850 Operating income (loss): Oil and natural gas $ (1,631,564 ) (4) $ 199,392 (4) $ 239,219 Contract drilling 44,811 (5) 41,896 (5) 96,304 Gas gathering and processing (29,409 ) (6) 2,015 (6) 10,757 Total operating income (loss) (1) (1,616,162 ) 243,303 346,280 General and administrative (35,345 ) (42,023 ) (38,323 ) Gain (loss) on disposition of assets (7,229 ) 8,953 17,076 Interest expense, net (31,963 ) (17,371 ) (15,015 ) Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net 26,345 30,147 (8,374 ) Other 45 (70 ) (175 ) Income (loss) before income taxes $ (1,664,309 ) $ 222,939 $ 301,469 Identifiable assets: Oil and natural gas $ 1,218,036 $ 2,856,833 $ 2,441,792 Contract drilling 993,015 1,059,980 1,042,661 Gas gathering and processing 478,661 500,255 473,717 Total identifiable assets (2) 2,689,712 4,417,068 3,958,170 Corporate assets 118,797 56,660 64,220 Total assets $ 2,808,509 $ 4,473,728 $ 4,022,390 Capital expenditures: Oil and natural gas $ 267,944 $ 740,262 $ 531,233 Contract drilling 84,802 176,683 64,325 Gas gathering and processing 63,476 79,268 (3) 96,085 Other 38,065 17,067 4,483 Total capital expenditures $ 454,287 $ 1,013,280 $ 696,126 Depreciation, depletion, amortization, and impairment: Oil and natural gas: Depreciation, depletion, and amortization $ 251,944 $ 276,088 $ 226,498 Impairment of oil and natural gas properties 1,599,348 (4) 76,683 (4) — Contract drilling: Depreciation 56,135 85,370 71,194 Impairment of contract drilling equipment 8,314 (5) 74,318 (5) — Gas gathering and processing: Depreciation and amortization 43,676 40,434 33,191 Impairment of gas gathering and processing systems 26,966 (6) 7,068 (6) — Other 3,075 3,051 3,024 Total depreciation, depletion, amortization, and impairment $ 1,989,458 $ 563,012 $ 333,907 _______________________ (1) Operating income (loss) 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, net, 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 2014, we entered into capital leases for $28.2 million . (4) In 2015 and 2014, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion and $76.7 million pre-tax ($ 1.0 billion and $47.7 million , net of tax), respectively. (5) Impairment for contract drilling equipment for 2015 includes a $8.3 million pre-tax write-down and 2014 includes a $74.3 million pre-tax write-down for 31 drilling rigs, some older top drives, and certain drill pipe removed from service. (6) Impairment for gas gathering and processing systems for 2015 includes a $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek. For 2014, it includes a $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek.

Selected Quarterly Financial In

Selected Quarterly Financial Information	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Selected Quarterly Financial Information	SELECTED QUARTERLY FINANCIAL INFORMATION Summarized unaudited quarterly financial information is as follows: Three Months Ended March 31 June 30 September 30 December 31 (In thousands except per share amounts) 2014 Revenues $ 387,988 $ 405,431 $ 400,974 $ 378,551 Gross profit (loss) (1) $ 115,143 $ 113,973 $ 103,983 $ (89,796 ) 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 (2) $ 1.17 $ 1.11 $ 1.37 $ (0.88 ) 2015 Revenues $ 255,099 $ 214,447 $ 212,393 $ 172,292 Gross loss (1) $ (389,451 ) $ (419,666 ) $ (314,409 ) $ (492,636 ) Net loss $ (248,354 ) $ (274,389 ) $ (205,281 ) $ (309,337 ) Net loss per common share: Basic $ (5.07 ) $ (5.58 ) $ (4.18 ) $ (6.29 ) Diluted $ (5.07 ) $ (5.58 ) $ (4.18 ) $ (6.29 ) _________________________ (1) Gross profit (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, net, 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 Disclo

Supplemental Oil And Gas Disclosures	12 Months Ended
	Dec. 31, 2015
Supplemental Oil and Gas Disclosures [Abstract]
Supplemental Oil And Gas Disclosures	SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED) 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: 2015 2014 2013 (In thousands) Capitalized costs: Proved properties $ 5,401,618 $ 4,990,753 $ 4,235,712 Unproved properties 337,099 485,568 545,588 5,738,717 5,476,321 4,781,300 Accumulated depreciation, depletion, amortization, and impairment (4,631,404 ) (2,786,678 ) (2,439,458 ) Net capitalized costs $ 1,107,313 $ 2,689,643 $ 2,341,842 Cost incurred: Unproved properties acquired $ 41,777 $ 76,041 $ 76,304 Proved properties acquired 179 5,723 — Exploration 19,222 68,811 33,373 Development 208,845 615,252 424,314 Asset retirement obligation (5,693 ) (37,687 ) (17,951 ) Total costs incurred $ 264,330 $ 728,140 $ 516,040 The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2015 , by the year in which such costs were incurred: 2015 2014 2013 2012 and Prior Total (In thousands) Unproved properties acquired and wells in progress $ 49,283 $ 65,970 $ 44,607 $ 177,239 $ 337,099 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: 2015 2014 2013 (In thousands) Revenues $ 371,335 $ 723,566 $ 633,792 Production costs (152,560 ) (165,315 ) (162,822 ) Depreciation, depletion, amortization, and impairment (1,844,726 ) (347,220 ) (222,672 ) (1,625,951 ) 211,031 248,298 Income tax (expense) benefit 612,496 (82,028 ) (96,091 ) Results of operations for producing activities (excluding corporate overhead and financing costs) $ (1,013,455 ) $ 129,003 $ 152,207 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 Bbls NGLs Bbls Natural Gas Mcf (In thousands) 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 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 2015 Proved developed and undeveloped reserves: Beginning of year 22,667 48,529 646,961 Revision of previous estimates (1) (3,954 ) (9,367 ) (139,514 ) Extensions and discoveries 1,208 1,948 20,974 Infill reserves in existing proved fields 670 1,861 22,641 Purchases of minerals in place — — — Production (3,783 ) (5,274 ) (65,546 ) Sales (73 ) (10 ) (648 ) End of year 16,735 37,687 484,868 Proved developed reserves: Beginning of year 17,448 35,850 500,950 End of year 14,679 31,218 416,395 Proved undeveloped reserves: Beginning of year 5,219 12,679 146,011 End of year 2,056 6,469 68,473 _________________________ (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: 2015 2014 2013 (In thousands) Future cash flows $ 2,475,898 $ 6,398,236 $ 5,573,119 Future production costs (1,017,777 ) (2,069,636 ) (1,734,985 ) Future development costs (228,445 ) (560,102 ) (571,170 ) Future income tax expenses (230,544 ) (1,228,533 ) (1,044,608 ) Future net cash flows 999,132 2,539,965 2,222,356 10% annual discount for estimated timing of cash flows (409,646 ) (1,104,221 ) (996,380 ) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 589,486 $ 1,435,744 $ 1,225,976 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: 2015 2014 2013 (In thousands) Sales and transfers of oil and natural gas produced, net of production costs $ (218,115 ) $ (558,252 ) $ (470,970 ) Net changes in prices and production costs (1,356,333 ) (33,259 ) 188,826 Revisions in quantity estimates and changes in production timing (213,945 ) (135,125 ) (10,650 ) Extensions, discoveries, and improved recovery, less related costs 95,671 635,752 426,377 Changes in estimated future development costs 227,857 96,339 26,629 Previously estimated cost incurred during the period 59,117 164,430 96,457 Purchases of minerals in place — 8,395 9 Sales of minerals in place (3,338 ) (19,135 ) (43,435 ) Accretion of discount 209,979 179,190 147,579 Net change in income taxes 562,838 (98,119 ) (170,091 ) Other—net (209,989 ) (30,448 ) (44,711 ) Net change (846,258 ) 209,768 146,020 Beginning of year 1,435,744 1,225,976 1,079,956 End of year $ 589,486 $ 1,435,744 $ 1,225,976 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, 2015 , future cash flows were computed by applying the unescalated 12-month average prices of $50.28 per barrel for oil, $19.47 per barrel for NGLs, and $2.59 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 Qua

Schedule II - Valuation And Qualifying Accounts And Reserves	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts [Abstract]
Valuation And Qualifying Accounts And Reserves	Allowance for Doubtful Accounts: Description Balance at Beginning of Period Additions Deductions & Net Write-Offs Balance at End of Period (In thousands) Year ended December 31, 2015 $ 5,039 $ 1,191 $ (1,031 ) $ 5,199 Year ended December 31, 2014 $ 5,342 $ 3,562 $ (3,865 ) $ 5,039 Year ended December 31, 2013 $ 5,343 $ — $ (1 ) $ 5,342

Summary Of Significant Accoun29

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
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 10 to 90 days. At December 31, 2015 , all of our contracts were daywork contracts of which nine were multi-well and had durations which ranged from six months to three years , five of which expire in 2016 and four expiring in 2017. 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, 2015 and 2014 , book overdrafts were $22.1 million and $27.8 million , respectively.
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: 2015 2014 2013 Oil and Natural Gas: Sunoco Logistics Partners L.P. 19 % 14 % 8 % Valero Energy Corporation 15 % 24 % 25 % Drilling: QEP Resources, Inc. 25 % 19 % 18 % Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) 7 % 9 % 10 % Mid-Stream: ONEOK Partners, L.P. 29 % 44 % 57 % Tenaska Resources, LLC 18 % 22 % 16 % Laclede Group, Inc. 12 % 16 % 7 % We had a concentration of cash of $2.3 million and $18.4 million at December 31, 2015 and 2014 , 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, 2015 and determined there was no material risk at that time. At December 31, 2015 , the fair values of the net assets we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: December 31, 2015 (In millions) Canadian Imperial Bank of Commerce $ 8.7 Bank of Montreal 1.1 Scotiabank 0.7 Bank of America Merrill Lynch 0.4 Total assets $ 10.9
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 drilling 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. As of December 31, 2015, with continuing declines to commodity prices and an outlook that commodity prices may be lower for longer, we lowered our expectations about future utilization of our drilling rigs and associated cash flows. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling segment. With respect to these assets, future cash flows were estimated over the expected remaining life of the assets. Management determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets within our contract drilling segment by 99% , and there was no impairment at December 31, 2015. 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 environment and based on the estimated market value from third-party assessments, we recorded a write-down of approximately $74.3 million , pre-tax. During the first quarter of 2015, we sold one of these drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig resulting in a gain of $7,900 . During the second quarter, we recorded an additional write-down on the remaining drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During the third quarter, we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. Some of the equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held for sale. The net book value of those assets is $0.6 million . 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 2015, our mid-stream segment incurred a $27.0 million , pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. In 2014, our mid-stream segment incurred 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 not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. 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 2015 , 2014 , and 2013 , interest of approximately $21.7 million , $32.2 million , and $33.7 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 drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2015 , 2014 , or 2013 . There were no additions to goodwill in 2015 , 2014 , or 2013 . Based on our impairment test performed as of December 31, 2015, the fair value of our drilling segment exceeded its carrying value by 19% . Goodwill of $2.2 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, 2015 , 2014 , or 2013 . Amortization of $0.7 million was recorded 2013 . Accumulated amortization for 2013 was $18.0 million . Our intangible assets became fully amortized in 2013, so no amortization was recorded in 2014 or 2015.
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 $19.2 million , $23.7 million , and $21.5 million were capitalized in 2015 , 2014 , and 2013 , respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $12.30 , $14.82 , and $13.32 per Boe in 2015 , 2014 , and 2013 , 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 $337.1 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. 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. Those determinations resulted in $73.7 million (in 2014) and $114.4 million (in 2015) of costs being added to the total of our capitalized costs being amortized. We incurred a $76.7 million pre-tax ( $47.7 million net of tax) non-cash ceiling test write-down of our oil and natural gas properties in 2014. In 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion pre-tax ( $1.0 billion net of tax) in 2015 due to the inclusion of the impaired value of those unproved properties and a reduction of the 12-month average commodity prices during the year. 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 statement of operations, 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 $22.1 million , $89.5 million , and $64.3 million for 2015 , 2014 , and 2013 , respectively from our contract drilling segment and eliminated the associated operating expense of $18.3 million , $62.4 million , and $46.9 million during 2015 , 2014 , and 2013 , respectively, yielding $3.8 million , $27.1 million , and $17.4 million during 2015 , 2014 , and 2013 , 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 $1.0 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 coverages we have will adequately protect us against liability from all potential consequences. Unit Texas Drilling, L.L.C. was merged into its parent company, Unit Drilling Company, effective October 31, 2015, at which time the ERISA governed occupational injury benefit program was closed. All new claims after this date are processed under an existing insured workers’ compensation program. 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 Operations. 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, 2015 balancing position to be approximately 4.7 Bcf on under-produced properties and approximately 4.8 Bcf on over-produced properties. We have recorded a receivable of $2.5 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 $5.0 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	Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact it will have on our financial statements. Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We do not expect the adoption of this guidance will have a material impact on our financial statements. 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 FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are in the process of evaluating the impact it will have on our financial statements.

Summary Of Significant Accoun30

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 Oil and Natural Gas: Sunoco Logistics Partners L.P. 19 % 14 % 8 % Valero Energy Corporation 15 % 24 % 25 % Drilling: QEP Resources, Inc. 25 % 19 % 18 % Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) 7 % 9 % 10 % Mid-Stream: ONEOK Partners, L.P. 29 % 44 % 57 % Tenaska Resources, LLC 18 % 22 % 16 % Laclede Group, Inc. 12 % 16 % 7 %
Schedule Of Fair Values Of The Net Assets [Table Text Block]	At December 31, 2015 , the fair values of the net assets we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: December 31, 2015 (In millions) Canadian Imperial Bank of Commerce $ 8.7 Bank of Montreal 1.1 Scotiabank 0.7 Bank of America Merrill Lynch 0.4 Total assets $ 10.9

Earnings (Loss) Per Share Earni

Earnings (Loss) Per Share Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings (Loss) Per Share [Table Text Block]	The following data shows the amounts used in computing earnings (loss) per share: Income (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) 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 $ 3.80 For the year ended December 31, 2014: Basic earnings per common share $ 136,276 48,611 $ 2.80 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, 2015: Basic earnings (loss) per common share $ (1,037,361 ) 49,110 $ (21.12 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted earnings (loss) per common share $ (1,037,361 ) 49,110 $ (21.12 )
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: 2015 2014 2013 Options and SARs 261,270 73,500 149,665 Average exercise price $ 50.34 $ 64.43 $ 58.41

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Accrued Liabilities [Abstract]
Accrued Liabilities [Table Text Block]	Accrued liabilities consisted of the following as of December 31: 2015 2014 (In thousands) Lease operating expenses $ 17,220 $ 20,709 Employee costs 12,641 31,451 Interest payable 6,321 6,654 Taxes 3,767 3,284 Third-party credits 3,326 2,825 Other 3,643 5,248 Total accrued liabilities $ 46,918 $ 70,171

Long-Term Debt And Other Long33

Long-Term Debt And Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (In thousands) Credit agreement with an average interest rates of 2.6% and 2.9% at December 31, 2015 and 2014, respectively $ 281,000 $ 166,000 6.625% senior subordinated notes due 2021, net of unamortized discount of $3.3 million and $3.8 million at December 31, 2015 and 2014, respectively 646,662 646,163 Total long-term debt $ 927,662 $ 812,163
Other Long Term Liabilities [Table Text Block]	Other long-term liabilities consisted of the following as of December 31: 2015 2014 (In thousands) ARO liability $ 98,297 $ 100,567 Capital lease obligations 22,466 25,876 Workers’ compensation 16,551 17,997 Separation benefit plans 9,886 11,276 Gas balancing liability 5,047 3,623 Deferred compensation plan 4,244 4,055 Other 410 410 156,901 163,804 Less current portion 16,560 15,019 Total other long-term liabilities $ 140,341 $ 148,785
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future payments required under the capital leases at December 31, 2015 are as follows: Amount Ending December 31, (In thousands) 2016 $ 6,168 2017 6,168 2018 6,168 2019 6,168 2020 6,168 2021 3,769 Total future payments 34,609 Less payments related to: Maintenance 9,445 Interest 2,698 Present value of future minimum payments $ 22,466

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (In thousands) ARO liability, January 1: $ 100,567 $ 133,657 Accretion of discount 3,453 4,599 Liability incurred 6,754 6,246 Liability settled (2,893 ) (4,490 ) Liability sold (421 ) (1,206 ) Revision of estimates (1) (9,163 ) (38,239 ) ARO liability, December 31: 98,297 100,567 Less current portion 3,965 3,204 Total long-term ARO liability $ 94,332 $ 97,363 _________________________ (1) Plugging liability estimates were revised in both 2015 and 2014 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, 2015
Income Tax Disclosure [Abstract]
Reconciliation Of Income Tax Expense (Benefit) [Table Text Block]	A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows: 2015 2014 2013 (In thousands) Income tax expense (benefit) computed by applying the statutory rate $ (582,508 ) $ 78,029 $ 105,514 State income tax, net of federal benefit (45,768 ) 6,131 8,290 Statutory depletion and other 1,328 2,503 2,919 Income tax expense (benefit) $ (626,948 ) $ 86,663 $ 116,723
Schedule Of Total Provision For Income Taxes [Table Text Block]	For the periods indicated, the total provision for income taxes consisted of the following: 2015 2014 2013 (In thousands) Current taxes: Federal $ (20,612 ) $ 8,594 $ 15,845 State (4 ) 784 146 (20,616 ) 9,378 15,991 Deferred taxes: Federal (535,691 ) 68,360 87,839 State (70,641 ) 8,925 12,893 (606,332 ) 77,285 100,732 Total provision $ (626,948 ) $ 86,663 $ 116,723
Schedule Of Deferred Tax Assets And Liabilities [Table Text Block]	Deferred tax assets and liabilities are comprised of the following at December 31: 2015 2014 (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 56,479 $ 55,231 Net operating loss carryforward 140,863 54,901 Alternative minimum tax and research and development tax credit carryforward 5,409 25,991 202,751 136,123 Deferred tax liability: Depreciation, depletion, amortization, and impairment (464,295 ) (1,000,811 ) Net deferred tax liability (261,544 ) (864,688 ) Current deferred tax asset 14,206 11,527 Non-current—deferred tax liability $ (275,750 ) $ (876,215 )
Schedule of Unrecognized Tax Benefits [Table Text Block]	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2015 2014 2013 (In thousands) Balance at January 1: $ 410 $ — $ — 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 $ 410 $ —

Transactions With Related Par36

Transactions With Related Parties (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 (In thousands) Contract drilling $ — $ 4 $ 16 Well supervision and other fees 423 435 470 General and administrative expense reimbursement 18 39 36

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
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, we had: 2015 (1) 2014 2013 (In millions) Recognized stock compensation expense $ 15.3 $ 17.4 $ 16.1 Capitalized stock compensation cost for our oil and natural gas properties 3.5 3.7 3.5 Tax benefit on stock based compensation 5.8 6.7 6.2 _________________________ (1) Recognized stock compensation was reduced by $3.2 million , capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million , and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.
Activity Pertaining to Stock Appreciation Rights [Table Text Block]	Activity pertaining to SARs granted under the amended plan is as follows: Number of Shares Weighted Average Price Outstanding at January 1, 2013 145,901 $ 46.59 Granted — — Exercised — — Forfeited — — Outstanding at December 31, 2013 145,901 46.59 Granted — — Exercised (14,131 ) 46.50 Forfeited — — Outstanding at December 31, 2014 131,770 46.60 Granted — — Exercised — — Forfeited — — Outstanding at December 31, 2015 131,770 $ 46.60
Shares Authorized Under Stock Appreciation Rights By Exercise Price [Table Text Block]	Outstanding and Exercisable SARs at December 31, 2015 Exercise Prices Number of Shares Weighted Average Remaining Weighted Average $44.31 91,255 2.0 years $44.31 $51.76 40,515 0.9 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 Time Vested Shares Number of Performance Vested Shares Total Number of Shares Weighted Average Price Nonvested at January 1, 2013 523,024 66,503 589,527 $ 48.11 Granted 396,144 57,405 453,549 48.20 Vested (248,003 ) — (248,003 ) 46.46 Forfeited (18,330 ) — (18,330 ) 47.85 Nonvested at December 31, 2013 652,835 123,908 776,743 48.70 Granted 383,448 71,674 455,122 53.72 Vested (291,712 ) (13,092 ) (304,804 ) 49.68 Forfeited (19,805 ) (6,970 ) (26,775 ) 51.92 Nonvested at December 31, 2014 724,766 175,520 900,286 50.81 Granted 576,361 148,081 724,442 34.06 Vested (343,657 ) (39,245 ) (382,902 ) 49.69 Forfeited (20,808 ) (7,196 ) (28,004 ) 45.33 Nonvested at December 31, 2015 936,662 277,160 1,213,822 $ 41.29 Non-Employee Directors Number of Shares Weighted Average Price Nonvested at January 1, 2013 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 Granted 25,848 34.04 Vested (18,920 ) 46.51 Forfeited — — Nonvested at December 31, 2015 42,064 $ 41.83
Activity Pertaining to the Stock Option Plan [Table Text Block]	Activity pertaining to the Stock Option Plan is as follows: Number of Shares Weighted Average Exercise Price Outstanding at January 1, 2013 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 Granted — — Exercised — — Forfeited (9,500 ) 37.69 Outstanding at December 31, 2015 — $ —
Activity Pertaining to Nonemployee Director Stock Award Plan [Table Text Block]	Activity pertaining to the Directors’ Plan is as follows: Number of Shares Weighted Average Exercise Price Outstanding at January 1, 2013 192,500 $ 49.39 Granted — — Exercised (17,500 ) 32.53 Forfeited (3,500 ) 20.46 Outstanding at December 31, 2013 171,500 51.70 Granted — — Exercised (21,000 ) 33.94 Forfeited — — Outstanding at December 31, 2014 150,500 54.18 Granted — — Exercised — — Forfeited (21,000 ) 54.35 Outstanding at December 31, 2015 129,500 $ 54.15
Shares Authorized Under Nonemployee Director Option Plans By Exercise Price Range [Table Text Block]	Outstanding and Exercisable Weighted Average Exercise Price Number of Shares Weighted Average Remaining Weighted Average $31.30 - $41.21 38,500 3.9 years $ 37.58 $53.81 - $73.26 91,000 2.6 years $ 61.16

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Non-designated Hedges Outstanding [Table Text Block]	At December 31, 2015 , the following non-designated hedges were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Jan’16 – Dec’16 Natural gas – swap 35,000 MMBtu/day $2.625 IF – NYMEX (HH) Jan’16 – Dec'16 Natural gas – collar 42,000 MMBtu/day $2.40 - $2.88 IF – NYMEX (HH) Jan’16 – Dec'16 Natural gas – three-way collar 13,500 MMBtu/day $2.70 - $2.20 - $3.26 IF – NYMEX (HH) Jan’17 – Dec'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH) Jan’16 – Jun'16 Crude oil – collar 2,150 Bbl/day $46.36 - $55.62 WTI – NYMEX Jul’16 – Dec'16 Crude oil – collar 1,450 Bbl/day $47.50 - $56.40 WTI – NYMEX Jan’16 – Dec'16 Crude oil – three-way collar 700 Bbl/day $46.50 - $35.00 - $57.00 WTI – NYMEX Jul’16 – Dec'16 Crude oil – three-way collar (1) 700 Bbl/day $47.50 - $35.00 - $63.50 WTI – NYMEX Jan’17 – Dec'17 Crude oil – three-way collar 750 Bbl/day $50.00 - $37.50 - $63.90 WTI – NYMEX
Schedule Of Subsequent Non-designated Hedges [Table Text Block]	Subsequent to December 31, 2015 , the following non-designated hedges were entered into: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Feb’16 – Dec'16 Natural gas – swap 10,000 MMBtu/day $2.495 IF – NYMEX (HH) Jan’17 – Dec'17 Natural gas – swap 10,000 MMBtu/day $2.795 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 2015 2014 (In thousands) Commodity derivatives: Current Current derivative assets $ 10,186 $ 31,139 Long-term Non-current derivative assets 968 — Total derivative assets $ 11,154 $ 31,139 Derivative Liabilities Fair Value Balance Sheet Location 2015 2014 (In thousands) Commodity derivatives: Current Current derivative liabilities $ — $ — Long-term Non-current derivative liabilities 285 — Total derivative liabilities $ 285 $ —
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 Operations (derivatives not designated as hedging instruments) for the year ended December 31: Derivatives Not Designated as Hedging Instruments Location of Gain or (Loss) Recognized in Income on Derivative Amount of Gain or (Loss) Recognized in Income on Derivative 2015 2014 (In thousands) Commodity derivatives Gain on derivatives not designated as hedges and hedge ineffectiveness, net (1) $ 26,345 $ 30,147 Total $ 26,345 $ 30,147 _________________________ (1) Amount settled during the period is a gain of $46,615 and a loss of $6,038 , respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Recurring Fair Value Measurements [Table Text Block]	The following tables set forth our recurring fair value measurements: December 31, 2015 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 2,794 $ 10,145 $ (1,785 ) $ 11,154 Liabilities (1,019 ) (1,051 ) 1,785 (285 ) $ 1,775 $ 9,094 $ — $ 10,869 December 31, 2014 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
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, December 31, 2015 December 31, 2014 (In thousands) Beginning of period $ 3,355 $ (2,595 ) Total gains or losses: Included in earnings (1) 15,260 6,108 Settlements (9,521 ) (158 ) End of period $ 9,094 $ 3,355 Total gains for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period $ 5,739 $ 5,950 _________________________ (1) Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net.
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, 2015 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil collars $ 3,893 Discounted cash flow Forward commodity price curve $0.40 - $55.05 Oil three-way collar 3,470 Discounted cash flow Forward commodity price curve $0.40 - $71.66 Natural gas collar 1,000 Discounted cash flow Forward commodity price curve $0.40 - $1.26 Natural gas three-way collar 731 Discounted cash flow Forward commodity price curve $0.40 - $1.93 _________________________ (1) The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way 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 Comprehensi40

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
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 2015 2014 2013 (In thousands) Balance at January 1: $ — $ — $ 7,587 Other comprehensive income before reclassification — — (7,349 ) Amounts reclassified from accumulated other comprehensive income — — (238 ) New current-period other comprehensive income — — (7,587 ) Balance at December 31: $ — $ — $ —
Schedule of accumulated other comprehensive income [Table Text Block]	Amounts reclassified from accumulated other comprehensive income (loss) into the Consolidated Statements of Operations for the year ended December 31: 2015 2014 2013 Affected Line Item in the Statement Where Net Income is Presented (In thousands) Net gains (loss) on cash flow hedges Commodity derivatives $ — $ — $ 603 Oil and natural gas revenues Commodity derivatives — — (190 ) Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net — — 413 Total before tax — — (175 ) Tax expense Total reclassification for the period $ — $ — $ 238 Net of tax

Industry Segment Information (T

Industry Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Revenue From Different Segments [Table Text Block]	The following table provides certain information about the operations of each of our segments: 2015 2014 2013 (In thousands) Revenues : Oil and natural gas $ 385,774 $ 740,079 $ 649,718 Contract drilling 287,767 566,012 479,091 Elimination of inter-segment revenue (22,099 ) (89,495 ) (64,313 ) Contract drilling net of inter-segment revenue 265,668 476,517 414,778 Gas gathering and processing 268,012 445,934 378,397 Elimination of inter-segment revenue (65,223 ) (89,586 ) (91,043 ) Gas gathering and processing net of inter-segment revenue 202,789 356,348 287,354 Total revenues $ 854,231 $ 1,572,944 $ 1,351,850 Operating income (loss): Oil and natural gas $ (1,631,564 ) (4) $ 199,392 (4) $ 239,219 Contract drilling 44,811 (5) 41,896 (5) 96,304 Gas gathering and processing (29,409 ) (6) 2,015 (6) 10,757 Total operating income (loss) (1) (1,616,162 ) 243,303 346,280 General and administrative (35,345 ) (42,023 ) (38,323 ) Gain (loss) on disposition of assets (7,229 ) 8,953 17,076 Interest expense, net (31,963 ) (17,371 ) (15,015 ) Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net 26,345 30,147 (8,374 ) Other 45 (70 ) (175 ) Income (loss) before income taxes $ (1,664,309 ) $ 222,939 $ 301,469 Identifiable assets: Oil and natural gas $ 1,218,036 $ 2,856,833 $ 2,441,792 Contract drilling 993,015 1,059,980 1,042,661 Gas gathering and processing 478,661 500,255 473,717 Total identifiable assets (2) 2,689,712 4,417,068 3,958,170 Corporate assets 118,797 56,660 64,220 Total assets $ 2,808,509 $ 4,473,728 $ 4,022,390 Capital expenditures: Oil and natural gas $ 267,944 $ 740,262 $ 531,233 Contract drilling 84,802 176,683 64,325 Gas gathering and processing 63,476 79,268 (3) 96,085 Other 38,065 17,067 4,483 Total capital expenditures $ 454,287 $ 1,013,280 $ 696,126 Depreciation, depletion, amortization, and impairment: Oil and natural gas: Depreciation, depletion, and amortization $ 251,944 $ 276,088 $ 226,498 Impairment of oil and natural gas properties 1,599,348 (4) 76,683 (4) — Contract drilling: Depreciation 56,135 85,370 71,194 Impairment of contract drilling equipment 8,314 (5) 74,318 (5) — Gas gathering and processing: Depreciation and amortization 43,676 40,434 33,191 Impairment of gas gathering and processing systems 26,966 (6) 7,068 (6) — Other 3,075 3,051 3,024 Total depreciation, depletion, amortization, and impairment $ 1,989,458 $ 563,012 $ 333,907 _______________________ (1) Operating income (loss) 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, net, 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 2014, we entered into capital leases for $28.2 million . (4) In 2015 and 2014, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion and $76.7 million pre-tax ($ 1.0 billion and $47.7 million , net of tax), respectively. (5) Impairment for contract drilling equipment for 2015 includes a $8.3 million pre-tax write-down and 2014 includes a $74.3 million pre-tax write-down for 31 drilling rigs, some older top drives, and certain drill pipe removed from service. (6) Impairment for gas gathering and processing systems for 2015 includes a $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek. For 2014, it includes a $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek.

Selected Quarterly Financial 42

Selected Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Schedule Of Quarterly Financial Information [Table Text Block]	Summarized unaudited quarterly financial information is as follows: Three Months Ended March 31 June 30 September 30 December 31 (In thousands except per share amounts) 2014 Revenues $ 387,988 $ 405,431 $ 400,974 $ 378,551 Gross profit (loss) (1) $ 115,143 $ 113,973 $ 103,983 $ (89,796 ) 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 (2) $ 1.17 $ 1.11 $ 1.37 $ (0.88 ) 2015 Revenues $ 255,099 $ 214,447 $ 212,393 $ 172,292 Gross loss (1) $ (389,451 ) $ (419,666 ) $ (314,409 ) $ (492,636 ) Net loss $ (248,354 ) $ (274,389 ) $ (205,281 ) $ (309,337 ) Net loss per common share: Basic $ (5.07 ) $ (5.58 ) $ (4.18 ) $ (6.29 ) Diluted $ (5.07 ) $ (5.58 ) $ (4.18 ) $ (6.29 ) _________________________ (1) Gross profit (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, net, 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 Disc43

Supplemental Oil And Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 (In thousands) Capitalized costs: Proved properties $ 5,401,618 $ 4,990,753 $ 4,235,712 Unproved properties 337,099 485,568 545,588 5,738,717 5,476,321 4,781,300 Accumulated depreciation, depletion, amortization, and impairment (4,631,404 ) (2,786,678 ) (2,439,458 ) Net capitalized costs $ 1,107,313 $ 2,689,643 $ 2,341,842 Cost incurred: Unproved properties acquired $ 41,777 $ 76,041 $ 76,304 Proved properties acquired 179 5,723 — Exploration 19,222 68,811 33,373 Development 208,845 615,252 424,314 Asset retirement obligation (5,693 ) (37,687 ) (17,951 ) Total costs incurred $ 264,330 $ 728,140 $ 516,040
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, 2015 , by the year in which such costs were incurred: 2015 2014 2013 2012 and Prior Total (In thousands) Unproved properties acquired and wells in progress $ 49,283 $ 65,970 $ 44,607 $ 177,239 $ 337,099
Results Of Operations For Producing Activities [Table Text Block]	The results of operations for producing activities are as follows: 2015 2014 2013 (In thousands) Revenues $ 371,335 $ 723,566 $ 633,792 Production costs (152,560 ) (165,315 ) (162,822 ) Depreciation, depletion, amortization, and impairment (1,844,726 ) (347,220 ) (222,672 ) (1,625,951 ) 211,031 248,298 Income tax (expense) benefit 612,496 (82,028 ) (96,091 ) Results of operations for producing activities (excluding corporate overhead and financing costs) $ (1,013,455 ) $ 129,003 $ 152,207
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 Bbls NGLs Bbls Natural Gas Mcf (In thousands) 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 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 2015 Proved developed and undeveloped reserves: Beginning of year 22,667 48,529 646,961 Revision of previous estimates (1) (3,954 ) (9,367 ) (139,514 ) Extensions and discoveries 1,208 1,948 20,974 Infill reserves in existing proved fields 670 1,861 22,641 Purchases of minerals in place — — — Production (3,783 ) (5,274 ) (65,546 ) Sales (73 ) (10 ) (648 ) End of year 16,735 37,687 484,868 Proved developed reserves: Beginning of year 17,448 35,850 500,950 End of year 14,679 31,218 416,395 Proved undeveloped reserves: Beginning of year 5,219 12,679 146,011 End of year 2,056 6,469 68,473 _________________________ (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: 2015 2014 2013 (In thousands) Future cash flows $ 2,475,898 $ 6,398,236 $ 5,573,119 Future production costs (1,017,777 ) (2,069,636 ) (1,734,985 ) Future development costs (228,445 ) (560,102 ) (571,170 ) Future income tax expenses (230,544 ) (1,228,533 ) (1,044,608 ) Future net cash flows 999,132 2,539,965 2,222,356 10% annual discount for estimated timing of cash flows (409,646 ) (1,104,221 ) (996,380 ) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 589,486 $ 1,435,744 $ 1,225,976
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: 2015 2014 2013 (In thousands) Sales and transfers of oil and natural gas produced, net of production costs $ (218,115 ) $ (558,252 ) $ (470,970 ) Net changes in prices and production costs (1,356,333 ) (33,259 ) 188,826 Revisions in quantity estimates and changes in production timing (213,945 ) (135,125 ) (10,650 ) Extensions, discoveries, and improved recovery, less related costs 95,671 635,752 426,377 Changes in estimated future development costs 227,857 96,339 26,629 Previously estimated cost incurred during the period 59,117 164,430 96,457 Purchases of minerals in place — 8,395 9 Sales of minerals in place (3,338 ) (19,135 ) (43,435 ) Accretion of discount 209,979 179,190 147,579 Net change in income taxes 562,838 (98,119 ) (170,091 ) Other—net (209,989 ) (30,448 ) (44,711 ) Net change (846,258 ) 209,768 146,020 Beginning of year 1,435,744 1,225,976 1,079,956 End of year $ 589,486 $ 1,435,744 $ 1,225,976

Summary Of Significant Accoun44

Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Sunoco Logistics Partners L.P. | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	19.00%	14.00%	8.00%
Valero Energy Corporation | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	15.00%	24.00%	25.00%
QEP Resources, Inc. | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	25.00%	19.00%	18.00%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	7.00%	9.00%	10.00%
ONEOK Partners, L.P. | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	29.00%	44.00%	57.00%
Tenaska Resources, LLC | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	18.00%	22.00%	16.00%
Laclede Group, Inc. | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	12.00%	16.00%	7.00%

Summary Of Significant Accoun45

Summary Of Significant Accounting Policies (Schedule Of Fair Values Of The Net Assets) (Details) $ in Millions	Dec. 31, 2015USD ($)
Derivative Counterparty [Line Items]
Total assets	$ 10.9
Canadian Imperial Bank of Commerce
Derivative Counterparty [Line Items]
Total assets	8.7
Bank of Montreal
Derivative Counterparty [Line Items]
Total assets	1.1
Scotiabank
Derivative Counterparty [Line Items]
Total assets	0.7
Bank of America Merrill Lynch
Derivative Counterparty [Line Items]
Total assets	$ 0.4

Summary Of Significant Accoun46

Summary Of Significant Accounting Policies (Narrative) (Details)	3 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)rig	Mar. 31, 2015USD ($)rig	Dec. 31, 2015USD ($)contractsystemsUnitMMcf	Dec. 31, 2014USD ($)rigsystems	Dec. 31, 2013USD ($)rig	Dec. 31, 2012USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of daywork contracts | contract			9
Number of contracts, daywork expiring in one year | contract			5
Number of contracts, daywork expiring in two years | contract			4
Book Overdrafts			$ 22,100,000	$ 27,800,000
Concentration of cash			$ 2,300,000	18,400,000
Percentage of expected cash flows on undiscounted basis exceeding the carrying values of long-lived assets			99.00%
Impairment of contract drilling equipment			$ 8,314,000	74,318,000	$ 0
Assets held for sale			615,000	0
Impairment of gas gathering systems			26,966,000	7,068,000	0
Interest Costs Capitalized			21,700,000	32,200,000	33,700,000
Goodwill impairment			0	0	0
Additions to goodwill			$ 0	0	0
Percentage fair value exceeds carrying value for goodwill			19.00%
Goodwill deductible for tax purposes			$ 2,200,000
Intangible asset impairment			0	0	0
Amortization on intangible assets			0	0	700,000
Accumulated amortization on intangible assets			0	0	18,000,000
Directly related overhead costs capitalized			19,200,000	23,700,000	21,500,000
Average rates used for depreciation, depletion, and amortization per Boe			12.30	14.82	13.32
Unproved properties not being amortized			$ 337,099,000	485,568,000	545,588,000
Future discounted net cash flows discounted			10.00%
Unproved properties included in amortization			$ 114,400,000	73,700,000
Impairment of oil and natural gas properties			1,599,348,000	76,683,000	0
Non-cash ceiling test write-down net of tax			1,000,000,000	47,700,000
Revenues from transactions with operating segments of same entity			22,100,000	89,500,000	64,300,000
Eliminated associated operating expense			18,300,000	62,400,000	46,900,000
Eliminated yielding			$ 3,800,000	27,100,000	17,400,000
Number of partnerships | Unit			15
Unrecognized tax benefits			$ 410,000	$ 410,000	0	$ 0
Minimum
Summary Of Significant Accounting Policies [Line Items]
Number of days for drilling of one well			10 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			$ 1,000,000
Under-Produced Properties
Summary Of Significant Accounting Policies [Line Items]
Natural gas balancing (MMcf) | MMcf			4,700
Over-Produced Properties
Summary Of Significant Accounting Policies [Line Items]
Natural gas balancing (MMcf) | MMcf			4,800
Natural Gas Balancing
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable			$ 2,500,000
Liability recognized to under production			$ 5,000,000
Drilling Equipment
Summary Of Significant Accounting Policies [Line Items]
Minimum depreciation percentage for idle drilling rigs			20.00%
Number of drilling rigs removed from service | rig				31
Drilling Equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years			15 years
Gas Gathering and Processing Equipment
Summary Of Significant Accounting Policies [Line Items]
Number of gas gathering systems impaired | systems			3	3
Property, Plant and Equipment, Other Types | Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years			3 years
Property, Plant and Equipment, Other Types | Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years			15 years
Drilling
Summary Of Significant Accounting Policies [Line Items]
Impairment of long-lived assets held-for-use			$ 0	$ 0	$ 0
Drilling Equipment
Summary Of Significant Accounting Policies [Line Items]
Number of rigs sold | rig	30	1		4	5
Net book value of drilling rigs sold	11	0.3		16.3
Gain (loss) on sale of drilling rigs	$ (7,300,000)	$ 7,900		$ 9,600,000	$ 16,500,000

Divestitures - Narrative (Detai

Divestitures - Narrative (Details)	1 Months Ended	3 Months Ended		12 Months Ended
	Aug. 31, 2013USD ($)	Sep. 30, 2015USD ($)rig	Mar. 31, 2015USD ($)rig	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)rig	Dec. 31, 2013USD ($)rig
Oil and Natural Gas
Divestiture [Line Items]
Proceeds from divestiture of assets				$ 1,900,000	$ 33,100,000	$ 21,700,000
Oil and Natural Gas | Bakken Properties
Divestiture [Line Items]
Proceeds from divestiture of assets	$ 57,100,000
Drilling Equipment
Divestiture [Line Items]
Net book value of drilling rigs sold		11	0.3		16.3
Number of rigs sold | rig		30	1		4	5
Gain (loss) on sale of drilling rigs		$ (7,300,000)	$ 7,900		$ 9,600,000	$ 16,500,000
Number of rigs held for sale | rig						4

Earnings Per Share (Schedule Of

Earnings Per Share (Schedule Of Earnings (Loss) Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Income (loss) of basic earnings (loss) per common share	$ (309,337)	$ (205,281)	$ (274,389)	$ (248,354)	$ (42,551)		$ 67,522		$ 54,360		$ 56,945		$ (1,037,361)	$ 136,276	$ 184,746
Income (loss) of effect of dilutive stock options, restricted stock, and SARs													0	0	0
Income (loss) of diluted earnings (loss) per common share													$ (1,037,361)	$ 136,276	$ 184,746
Weighted shares of basic earnings (loss) per common share													49,110	48,611	48,218
Weighted shares of effect of dilutive stock options, restricted stock, and SARs													0	472	354
Weighted shares of diluted earnings (loss) per common share													49,110	49,083	48,572
Per share amount of basic earnings (loss) per common share	$ (6.29)	$ (4.18)	$ (5.58)	$ (5.07)	$ (0.88)		$ 1.39		$ 1.12		$ 1.17		$ (21.12)	$ 2.80	$ 3.83
Per share amount of effect of dilutive stock options, restricted stock, and SARs													0	(0.02)	(0.03)
Per share amount of diluted earnings (loss) per common share	$ (6.29)	$ (4.18)	$ (5.58)	$ (5.07)	$ (0.88)	[1]	$ 1.37	[1]	$ 1.11	[1]	$ 1.17	[1]	$ (21.12)	$ 2.78	$ 3.80
[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 (Loss) Per Share (Sche

Earnings (Loss) Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) - Stock options and SARs - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options and SARs	261,270	73,500	149,665
Average Exercise Price	$ 50.34	$ 64.43	$ 58.41

Earnings (Loss) Per Share Ear50

Earnings (Loss) Per Share Earnings (Loss) Per Share (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015shares
Stock options, restricted stock, and SARs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share due to net loss	186,000

Accrued Liabilities (Accrued Li

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities [Abstract]
Lease operating expenses	$ 17,220	$ 20,709
Employee costs	12,641	31,451
Interest payable	6,321	6,654
Taxes	3,767	3,284
Third-party credits	3,326	2,825
Other	3,643	5,248
Total accrued liabilities	$ 46,918	$ 70,171

Long-Term Debt And Other Long52

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-term debt and other long-term liabilites [Abstract]
Credit agreement with an average interest rates of 2.6% and 2.9% at December 31, 2015 and 2014, respectively	$ 281,000	$ 166,000
6.625% senior subordinated notes due 2021, net of unamortized discount of $3.3 million and $3.8 million at December 31, 2015 and 2014, respectively	646,662	646,163
Total long-term debt	$ 927,662	$ 812,163
Line of Credit Facility, Interest Rate at Period End	2.60%	2.90%
Debt Instrument, Unamortized Discount	$ 3,300	$ 3,800

Long-Term Debt And Other Long53

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term debt and other long-term liabilites [Abstract]
ARO liability	$ 98,297	$ 100,567	$ 133,657
Capital lease obligations	22,466	25,876
Workers' compensation	16,551	17,997
Separation benefit plans	9,886	11,276
Gas balancing liability	5,047	3,623
Deferred compensation plan	4,244	4,055
Other	410	410
Other liabilities	156,901	163,804
Less current portion	16,560	15,019
Total other long-term liabilities	$ 140,341	$ 148,785

Long-Term Debt And Other Long54

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt and Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Ending December 31, [Abstract]
2,016	$ 6,168
2,017	6,168
2,018	6,168
2,019	6,168
2,020	6,168
2,021	3,769
Total future payments	34,609
Less payments related to:
Maintenance	9,445
Interest	2,698
Present value of future minimum payments	$ 22,466	$ 25,876

Long-Term Debt And Other Long55

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Credit facility maturity date	4/10/2020
Credit Facility Maximum Credit Amount	$ 900,000
Origination, agency and syndication fees	$ 2,600
Debt instrument, variable interest rate, payable assessment period	90 days
LIBOR interest rate plus one percent	LIBOR plus 1.00%
Line of credit facility, amount borrowed	$ 281,000		$ 166,000
Current ratio of credit facility	1 to 1
Leverage ratio of long-term debt	4 to 1
Aggregate principal amount	$ 650,000
Interest percentage of senior subordinated notes	6.625%
Debt Instrument, Maturity Date	May 15, 2021
Deducting fees for debt issuance	$ 14,700
Equal redemption price percentage of principal amount of debt	100.00%
Senior notes repurchase price in percentage	101.00%
Year One	$ 16,600
Year Two	5,700
Year Three	59,900
Year Four	9,500
Year Five	$ 290,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,500
Capital Lease Obligations, Noncurrent	$ 18,900
Discount rate capital leases	4.00%
Maintenance	$ 9,445
Interest	2,698
Capital leases, future minimum payments, average annual payment	$ 4,000
Capital lease fair market value percentage for purchase	10.00%
Minimum
Debt Instrument [Line Items]
Commitment fee percentage under credit facility	0.375%
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%
Line Of Credit Facility Commitment Amount]
Debt Instrument [Line Items]
Credit facility current credit amount	$ 500,000
Line Of Credit Facility Lender Determined Amount
Debt Instrument [Line Items]
Credit facility current credit amount	$ 550,000	$ 725,000

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
ARO liability, January 1:		$ 100,567	$ 133,657
Accretion of discount		3,453	4,599
Liability incurred		6,754	6,246
Liability settled		(2,893)	(4,490)
Liability sold		(421)	(1,206)
Revision of estimates	[1]	(9,163)	(38,239)
ARO liability, December 31:		98,297	100,567
Less current portion		3,965	3,204
Total long-term ARO liability		$ 94,332	$ 97,363
[1]	Plugging liability estimates were revised in both 2015 and 2014 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 (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income tax expense (benefit) computed by applying the statutory rate	$ (582,508)	$ 78,029	$ 105,514
State income tax, net of federal benefit	(45,768)	6,131	8,290
Statutory depletion and other	1,328	2,503	2,919
Income tax expense (benefit)	$ (626,948)	$ 86,663	$ 116,723

Income Taxes (Schedule Of Total

Income Taxes (Schedule Of Total Provision For Income Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current taxes, Federal	$ (20,612)	$ 8,594	$ 15,845
Current taxes, State	(4)	784	146
Current taxes	(20,616)	9,378	15,991
Deferred taxes, Federal	(535,691)	68,360	87,839
Deferred taxes, State	(70,641)	8,925	12,893
Deferred taxes	(606,332)	77,285	100,732
Total provision	$ (626,948)	$ 86,663	$ 116,723

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Allowance for losses and nondeductible accruals	$ 56,479	$ 55,231
Net operating loss carryforward	140,863	54,901
Alternative minimum tax and research and development tax credit carryforward	5,409	25,991
Deferred tax assets, total	202,751	136,123
Depreciation, depletion, amortization, and impairment	(464,295)	(1,000,811)
Net deferred tax liability	(261,544)	(864,688)
Current deferred tax asset	14,206	11,527
Non-current-deferred tax liability	$ (275,750)	$ (876,215)

Income Taxes Income Taxes (Sche

Income Taxes Income Taxes (Schedule of Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Balance at January 1:	$ 410	$ 0	$ 0
Additions based on tax positions related to current year	0	410	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	$ 410	$ 0

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 351,400
Unrecognized tax benefits	$ 410	$ 410	$ 0	$ 0
Start
Operating Loss Carryforwards [Line Items]
Operating loss expiration period	Jan. 1, 2021
End
Operating Loss Carryforwards [Line Items]
Operating loss expiration period	Dec. 31, 2035

Employee Benefit Plans (Details

Employee Benefit Plans (Details) $ in Millions	May. 05, 2004yr	Jan. 01, 1997week	Dec. 31, 2015USD ($)yrshares		Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares
Defined Benefit Plan Disclosure [Line Items]
Recognized stock compensation expense			$ 15.3	[1]	$ 17.4	$ 16.1
Employment contract period extension, years			1 year
Grace period following the first anniversary			30 days
Employee Thrift Plan
Defined Benefit Plan Disclosure [Line Items]
Contribution of shares, common stock | shares			235,104		120,333	111,995
Recognized stock compensation expense			$ 6.2		$ 5.2	$ 6
Salary Deferral Plan
Defined Benefit Plan Disclosure [Line Items]
Liability recorded under deferral plan			4.2		4.1
Separation Plan
Defined Benefit Plan Disclosure [Line Items]
Service period, years		20 years
Maximum period benefit, weeks | week		104
Separation benefit plans expense			$ 3		$ 2.7	$ 2.4
Special Separation Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service period, years	20 years
Age limit | yr	65
Change Of Control Contracts
Defined Benefit Plan Disclosure [Line Items]
Employee contract period, years | yr			3
Multiple for determination compensation			2.9
Plan 401k
Defined Benefit Plan Disclosure [Line Items]
Additional period for 401k, years			3 years
[1]	Recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

Transactions With Related Par63

Transactions With Related Parties Transactions With Related Parties (Schedule of Amount Received in Public and Private Partnerships) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Contract drilling	$ 0	$ 4	$ 16
Well supervision and other fees	423	435	470
General and administrative expense reimbursement	$ 18	$ 39	$ 36

Transactions With Related Par64

Transactions With Related Parties (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Unitwells	Dec. 31, 2014USD ($)wells	Dec. 31, 2013USD ($)
Related Party Transaction [Line Items]
Number of oil and gas limited partnerships | Unit	15
Number of oil and gas limited partnerships for third party investment | Unit	2
Number of oil and gas limited partnerships for employee investment | Unit	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%
G. Bailey Peyton IV
Related Party Transaction [Line Items]
Payments for royalties	$ 800	$ 1,300	$ 1,400
Toklan Oil and Gas Company | John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage	25.80%
Number of wells drilled	0	2	0
Completed wells | wells	1	1
Revenue from related parties	$ 500	$ 1,500
Cash received from related parties	900	1,100
Related party accounts receivable balance	0	400
Payments for royalties	$ 0	$ 200	$ 0
Toklan Oil and Gas Company | Robert Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage	20.00%
West Thomas Field Services, LLC | John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage	25.00%
Revenue from related parties	$ 100
West Thomas Field Services, LLC | Robert Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage	20.00%
Gas Gathering and Processing Equipment | Toklan Oil and Gas Company | John Nikkel
Related Party Transaction [Line Items]
Amount received from Toklan for gathering system	$ 500

Stock-Based Compensation (Sched

Stock-Based Compensation (Schedule Of Restricted Stock Awards Stock Options And SAR) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognized stock compensation expense	$ 15.3	[1]	$ 17.4	$ 16.1
Capitalized stock compensation cost for our oil and natural gas properties	3.5	[1]	3.7	3.5
Tax benefit on stock based compensation	5.8	[1]	$ 6.7	$ 6.2
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reduction in recognized stock compensation expense related to performance shares	3.2
Reduction in capitalized stock compensation cost for our oil and natural gas properties related to performance shares	0.2
Reduction in tax benefit on stock based compensation related to performance shares	$ 1.2
[1]	Recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

Stock-Based Compensation Stock-

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Appreciation Rights) (Details) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	131,770	145,901	145,901
Weighted average price, beginning balance	$ 46.60	$ 46.59	$ 46.59
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0	$ 0	$ 0
Number of shares, exercised	0	(14,131)	0
Weighted average price, exercised	$ 0	$ 46.50	$ 0
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$ 0	$ 0	$ 0
Number of shares, ending balance	131,770	131,770	145,901
Weighted average price, ending balance	$ 46.60	$ 46.60	$ 46.59

Stock-Based Compensation Stoc67

Stock-Based Compensation Stock-Based Compensation (Shares Authorized Under Stock Appreciation Rights By Exercise Price) (Details) - Stock Appreciation Rights (SARs)	12 Months Ended
	Dec. 31, 2015$ / sharesshares
$ 44.31
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding and exercisable options, number of shares | shares	91,255
Outstanding and exercisable options weighted average remaining contractual life, years	2 years
Outstanding and exercisable options, weighted average exercise price | $ / shares	$ 44.31
$ 51.76
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding and exercisable options, number of shares | shares	40,515
Outstanding and exercisable options weighted average remaining contractual life, years	10 months 24 days
Outstanding and exercisable options, weighted average exercise price | $ / shares	$ 51.76

Stock-Based Compensation (Activ

Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	900,286	776,743	589,527
Weighted average price, beginning balance	$ 50.81	$ 48.70	$ 48.11
Number of shares, granted	724,442	455,122	453,549
Weighted average price, granted	$ 34.06	$ 53.72	$ 48.20
Number of shares, vested	(382,902)	(304,804)	(248,003)
Weighted average price, exercised	$ 49.69	$ 49.68	$ 46.46
Number of shares, forfeited	(28,004)	(26,775)	(18,330)
Weighted average price, forfeited	$ 45.33	$ 51.92	$ 47.85
Number of shares, ending balance	1,213,822	900,286	776,743
Weighted average price, ending balance	$ 41.29	$ 50.81	$ 48.70
Non-employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	35,136	35,704	24,606
Weighted average price, beginning balance	$ 50.08	$ 41.07	$ 40.23
Number of shares, granted	25,848	13,768	21,128
Weighted average price, granted	$ 34.04	$ 63.91	$ 41.65
Number of shares, vested	(18,920)	(14,336)	(10,030)
Weighted average price, exercised	$ 46.51	$ 40.93	$ 40.23
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$ 0	$ 0	$ 0
Number of shares, ending balance	42,064	35,136	35,704
Weighted average price, ending balance	$ 41.83	$ 50.08	$ 41.07
Time Vested | Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	724,766	652,835	523,024
Number of shares, granted	576,361	383,448	396,144
Number of shares, vested	(343,657)	(291,712)	(248,003)
Number of shares, forfeited	(20,808)	(19,805)	(18,330)
Number of shares, ending balance	936,662	724,766	652,835
Performance Shares | Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	175,520	123,908	66,503
Number of shares, granted	148,081	71,674	57,405
Number of shares, vested	(39,245)	(13,092)	0
Number of shares, forfeited	(7,196)	(6,970)	0
Number of shares, ending balance	277,160	175,520	123,908

Stock-Based Compensation Stoc69

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Options) (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	9,500	68,920	118,030
Weighted average price, beginning balance	$ 37.69	$ 37.81	$ 33.03
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0	$ 0	$ 0
Number of shares, exercised	0	(21,490)	(48,110)
Weighted average price, exercised	$ 0	$ 37.83	$ 26.09
Number of shares, forfeited	(9,500)	(37,930)	(1,000)
Weighted average price, forfeited	$ 37.69	$ 37.83	$ 37.83
Number of shares, ending balance	0	9,500	68,920
Weighted average price, ending balance	$ 0	$ 37.69	$ 37.81

Stock-Based Compensation Stoc70

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) - Directors Plan - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	150,500	171,500	192,500
Weighted average price, beginning balance	$ 54.18	$ 51.70	$ 49.39
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0	$ 0	$ 0
Number of shares, exercised	0	(21,000)	(17,500)
Weighted average price, exercised	$ 0	$ 33.94	$ 32.53
Number of shares, forfeited	(21,000)	0	(3,500)
Weighted average price, forfeited	$ 54.35	$ 0	$ 20.46
Number of shares, ending balance	129,500	150,500	171,500
Weighted average price, ending balance	$ 54.15	$ 54.18	$ 51.70

Stock-Based Compensation (Share

Stock-Based Compensation (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) - Directors Plan	12 Months Ended
	Dec. 31, 2015$ / sharesshares
$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 | shares	38,500
Outstanding and exercisable options weighted average remaining contractual life, years	3 years 10 months 12 days
Outstanding and exercisable options, weighted average exercise price	$ 37.58
$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 | shares	91,000
Outstanding and exercisable options weighted average remaining contractual life, years	2 years 7 months
Outstanding and exercisable options, weighted average exercise price	$ 61.16

Stock-Based Compensation (Narra

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 13.8
Unrecognized compensation cost, expect to be capitalized	$ 2.4
Weighted average years over which this cost will be recognized	8 months 12 days
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	131,770	145,901
Exercisable options intrinsic value	$ 0
Weighted average remaining contractual term, years	1 year 7 months 6 days
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance				4,500,000
Number of shares, ending balance	1,255,886
Exercisable options intrinsic value	$ 15.3
Grant date fair value	$ 24.5	$ 24.1	$ 21.3
Number of shares, vested	(401,822)
Exercised intrinsic value	$ 11.2
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]
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%
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Shares vested	0	0	0
Maximum Number of Shares of Common Stock Previously Allowed for the Issuance	2,700,000
Vesting rate of options	20.00%
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
Vesting Period	6 months
Director option awards	3,500
2015 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	2.00%
2014 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	57.00%
2013 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	10.00%

Derivatives Derivatives (Schedu

Derivatives Derivatives (Schedule of Non-designated Hedges Outstanding) (Details)	12 Months Ended
	Dec. 31, 2015$ / UnitMMBTUbbl
Natural gas | Swap | If Nymex | Jan'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	2.625
Hedged Volume (MMBtu/day) | MMBTU	35,000
Natural gas | Collar | If Nymex | Jan'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	2.88
Floor Price	2.40
Hedged Volume (MMBtu/day) | MMBTU	42,000
Natural gas | Three-way collar | If Nymex | Jan'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	3.26
Subfloor Price	2.20
Floor Price	2.70
Hedged Volume (MMBtu/day) | MMBTU	13,500
Natural gas | Three-way collar | If Nymex | Jan'17 - Dec'17
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	3.32
Subfloor Price	2
Floor Price	2.50
Hedged Volume (MMBtu/day) | MMBTU	15,000
Crude Oil | Collar | Wti Nymex | Jan'16 - Jun'16
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	55.62
Floor Price	46.36
Hedged Volume (Bbl/day) | bbl	2,150
Crude Oil | Collar | Wti Nymex | Jul'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	56.40
Floor Price	47.50
Hedged Volume (Bbl/day) | bbl	1,450
Crude Oil | Three-way collar | Wti Nymex | Jan'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	57
Subfloor Price	35
Floor Price	46.50
Hedged Volume (Bbl/day) | bbl	700
Crude Oil | Three-way collar | Wti Nymex | Jul'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	63.50	[1]
Subfloor Price	35	[1]
Floor Price	47.50	[1]
Hedged Volume (Bbl/day) | bbl	700	[1]
Crude Oil | Three-way collar | Wti Nymex | Jan'17 - Dec'17
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	63.90
Subfloor Price	37.50
Floor Price	50
Hedged Volume (Bbl/day) | bbl	750
[1]	We pay our counterparty a premium, which can be and is being deferred until settlement.

Derivatives (Schedule Of Subseq

Derivatives (Schedule Of Subsequent Non-designated Hedges) (Details) - Subsequent to December 31, 2015 - Natural gas - If Nymex - Swap	2 Months Ended
	Feb. 25, 2016$ / UnitMMBTU
Feb'16 - Dec'16
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps | $ / Unit	2.495
Hedged Volume (MMBtu/day) | MMBTU	10,000
Jan'17 - Dec'17
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps | $ / Unit	2.795
Hedged Volume (MMBtu/day) | MMBTU	10,000

Derivatives (Fair Value Of Deri

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 10,186	$ 31,139
Non-current derivative assets	968	0
Total derivatives assets	11,154	31,139
Non-current derivative liabilities	285	0
Total derivative liabilities	285	0
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Current derivative assets	10,186	31,139
Non-current derivative assets	968	0
Current derivative liabilities	0	0
Non-current derivative liabilities	$ 285	$ 0

Derivatives (Effect Of Derivati

Derivatives (Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain on derivatives not designated as hedges		$ 26,345	$ 30,147
Cash receipts (payments) on derivatives settled		46,615	(6,038)
Commodity Contract
Derivative Instruments, Gain (Loss) [Line Items]
Gain on derivatives not designated as hedges	[1]	$ 26,345	$ 30,147
[1]	Amount settled during the period is a gain of $46,615 and a loss of $6,038, respectively.

Derivatives (Narrative) (Detail

Derivatives (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Accumulated OCI gain net of tax	$ 0	$ 0

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	$ 10,900
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	11,154	$ 31,139
Liabilities	(285)	0
Financial assets (liabilities)	10,869	31,139
Commodity Contract | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	2,794	27,784
Liabilities	(1,019)	0
Financial assets (liabilities)	1,775	27,784
Commodity Contract | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	10,145	3,355
Liabilities	(1,051)	0
Financial assets (liabilities)	9,094	3,355
Commodity Contract | Effect of Netting
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	(1,785)	0
Liabilities	1,785	0
Financial assets (liabilities)	$ 0	$ 0

Fair Value Measurements (Reconc

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Beginning of period		$ 3,355	$ (2,595)
Included in earnings	[1]	15,260	6,108
Settlements		(9,521)	(158)
End of period		9,094	3,355
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period		$ 5,739	$ 5,950
[1]	Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net.

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) - Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / Unit
Crude Oil | Collar
Derivative assets, Fair Value | $	$ 3,893	[1]
Derivatives assets, Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Crude Oil | Three-way collar
Derivative assets, Fair Value | $	$ 3,470	[1]
Derivatives assets, Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Crude Oil | Minimum | Collar
Derivative, Forward Price	0.4
Crude Oil | Minimum | Three-way collar
Derivative, Forward Price	0.4
Crude Oil | Maximum | Collar
Derivative, Forward Price	55.05
Crude Oil | Maximum | Three-way collar
Derivative, Forward Price	71.66
Natural gas | Collar
Derivative assets, Fair Value | $	$ 1,000	[1]
Derivatives assets, Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Natural gas | Three-way collar
Derivative assets, Fair Value | $	$ 731	[1]
Derivatives assets, Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Natural gas | Minimum | Collar
Derivative, Forward Price	0.4
Natural gas | Minimum | Three-way collar
Derivative, Forward Price	0.4
Natural gas | Maximum | Collar
Derivative, Forward Price	1.26
Natural gas | Maximum | Three-way collar
Derivative, Forward Price	1.93
[1]	The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way 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 ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
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 $3.3 million and $3.8 million at December 31, 2015 and 2014, respectively	646,662	$ 646,163
Estimated fair value of long-term debt	$ 455,500	$ 605,500

Accumulated Other Comprehensi82

Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Balance at January 1:	$ 0	$ 0	$ 7,587
Other comprehensive income before reclassification	0	0	(7,349)
Amounts reclassified from accumulated other comprehensive income	0	0	(238)
New current-period other comprehensive income			(7,587)
Balance at December 31:	$ 0	$ 0	$ 0

Accumulated Other Comprehensi83

Accumulated Other Comprehensive Income (Schedule of accumulated other comprehensive income (loss)) (Details) - Commodity Contract - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	$ 0	$ 0	$ 413
Tax expense	0	0	(175)
Total reclassification for the period	0	0	238
Oil and natural gas revenue
Amounts reclassified from accumulated other comprehensive income	0	0	603
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness
Derivative Instruments, Gain (Loss) Recognized in Income	$ 0	$ 0	$ (190)

Commitments And Contingencies (

Commitments And Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Commitments [Line Items]
Lease expiration date	Dec. 31, 2021
Future minimum rental payments under leases, year one	$ 6,400,000
Future minimum rental payments under leases, year two	1,000,000
Future minimum rental payments under leases, year three	700,000
Future minimum rental payments under leases, year four	92,000
Future minimum rental payments under leases, year five	72,000
Rent expense incurred	$ 12,900,000	$ 13,600,000	$ 16,900,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
2,016	$ 6,168,000
2,017	6,168,000
2,018	6,168,000
2,019	6,168,000
2,020	6,168,000
2,021	3,769,000
Maintenance	9,445,000
Interest	2,698,000
Capital leases, future minimum payments, average annual payment	$ 4,000,000
Capital lease fair market value percentage for purchase	10.00%
Repurchase of limited units outstanding	20.00%
Repurchase of limited units outstanding amount	$ 118,000	$ 45,000	$ 16,000
Drilling Equipment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	6,700,000
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

Industry Segment Information (R

Industry Segment Information (Revenue From Different Segments) (Details) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)systems		Dec. 31, 2014USD ($)rigsystems		Dec. 31, 2013USD ($)
Revenues
Oil and natural gas										$ 385,774		$ 740,079		$ 649,718
Contract drilling										287,767		566,012		479,091
Elimination of inter-segment revenue										(22,099)		(89,495)		(64,313)
Contract drilling net of inter-segment revenue										265,668		476,517		414,778
Gas gathering and processing										268,012		445,934		378,397
Elimination of inter-segment revenue										(65,223)		(89,586)		(91,043)
Gas gathering and processing net of inter-segment revenue										202,789		356,348		287,354
Total revenues		$ 172,292	$ 212,393	$ 214,447	$ 255,099	$ 378,551	$ 400,974	$ 405,431	$ 387,988	854,231		1,572,944		1,351,850
Operating Income (Loss):
Oil and natural gas										(1,631,564)	[1]	199,392	[1]	239,219
Contract drilling										44,811	[2]	41,896	[2]	96,304
Gas gathering and processing										(29,409)	[3]	2,015	[3]	10,757
Total operating income (loss)	[4]									(1,616,162)		243,303		346,280
General and administrative										(35,345)		(42,023)		(38,323)
Gain (loss) on disposition of assets										(7,229)		8,953		17,076
Interest expense, net										(31,963)		(17,371)		(15,015)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net										26,345		30,147		(8,374)
Other										45		(70)		(175)
Income (loss) before income taxes										(1,664,309)		222,939		301,469
Identifiable assets:
Oil and natural gas		1,218,036				2,856,833				1,218,036		2,856,833		2,441,792
Contract drilling		993,015				1,059,980				993,015		1,059,980		1,042,661
Gas gathering and processing		478,661				500,255				478,661		500,255		473,717
Total identifiable assets	[5]	2,689,712				4,417,068				2,689,712		4,417,068		3,958,170
Corporate assets		118,797				56,660				118,797		56,660		64,220
Total assets		$ 2,808,509				$ 4,473,728				2,808,509		4,473,728		4,022,390
Capital expenditures:
Oil and natural gas										267,944		740,262		531,233
Contract drilling										84,802		176,683		64,325
Gas gathering and processing										63,476		79,268	[6]	96,085
Other										38,065		17,067		4,483
Total capital expenditures										454,287		1,013,280		696,126
Oil and natural gas:
Depreciation, depletion, and amortization										251,944		276,088		226,498
Impairment of oil and natural gas properties										1,599,348		76,683		0
Contract drilling:
Impairment of contract drilling equipment										8,314		74,318		0
Gas gathering and processing:
Depreciation and amortization										43,676		40,434		33,191
Impairment of gas gathering systems										26,966		7,068		0
Capital lease obligations incurred												28,200
Non-cash ceiling test write-down net of tax										1,000,000		47,700
Operating Segments
Oil and natural gas:
Depreciation, depletion, and amortization										251,944		276,088		226,498
Impairment of oil and natural gas properties										1,599,348	[1]	76,683	[1]	0
Contract drilling:
Depreciation										56,135		85,370		71,194
Impairment of contract drilling equipment										8,314	[2]	74,318	[2]	0
Gas gathering and processing:
Depreciation and amortization										43,676		40,434		33,191
Impairment of gas gathering systems										26,966	[3]	7,068	[3]	0
Other										3,075		3,051		3,024
Total depreciation, depletion, amortization and impairment										$ 1,989,458		$ 563,012		$ 333,907
Drilling Equipment
Gas gathering and processing:
Number of drilling rigs removed from service | rig												31
Gas Gathering and Processing Equipment
Gas gathering and processing:
Number of gas gathering systems impaired | systems										3		3
[1]	In 2015 and 2014, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion and $76.7 million pre-tax ($1.0 billion and $47.7 million, net of tax), respectively.
[2]	Impairment for contract drilling equipment for 2015 includes a $8.3 million pre-tax write-down and 2014 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]	Impairment for gas gathering and processing systems for 2015 includes a $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek. For 2014, it includes a $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek.
[4]	Operating income (loss) 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, net, interest expense, other income (loss), or income taxes.
[5]	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.
[6]	In 2014, we entered into capital leases for $28.2 million

Selected Quarterly Financial 86

Selected Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended												12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues		$ 172,292	$ 212,393	$ 214,447	$ 255,099	$ 378,551		$ 400,974		$ 405,431		$ 387,988		$ 854,231	$ 1,572,944	$ 1,351,850
Gross profit (loss)	[1]	(492,636)	(314,409)	(419,666)	(389,451)	(89,796)		103,983		113,973		115,143
Net income (loss)		$ (309,337)	$ (205,281)	$ (274,389)	$ (248,354)	$ (42,551)		$ 67,522		$ 54,360		$ 56,945		$ (1,037,361)	$ 136,276	$ 184,746
Net income (loss) per common share:
Basic		$ (6.29)	$ (4.18)	$ (5.58)	$ (5.07)	$ (0.88)		$ 1.39		$ 1.12		$ 1.17		$ (21.12)	$ 2.80	$ 3.83
Diluted		$ (6.29)	$ (4.18)	$ (5.58)	$ (5.07)	$ (0.88)	[2]	$ 1.37	[2]	$ 1.11	[2]	$ 1.17	[2]	$ (21.12)	$ 2.78	$ 3.80
[1]	Gross profit (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, net, 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 Disc87

Supplemental Oil And Gas Disclosures (Schedule Of Capitalized Costs And Costs Incurred On Oil And Gas Properties) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized costs:
Proved properties	$ 5,401,618	$ 4,990,753	$ 4,235,712
Unproved properties not being amortized	337,099	485,568	545,588
Capitalized costs gross	5,738,717	5,476,321	4,781,300
Accumulated depreciation, depletion, amortization, and impairment	(4,631,404)	(2,786,678)	(2,439,458)
Net capitalized costs	1,107,313	2,689,643	2,341,842
Costs incurred:
Unproved properties acquired	41,777	76,041	76,304
Proved properties acquired	179	5,723	0
Exploration	19,222	68,811	33,373
Development	208,845	615,252	424,314
Asset retirement obligation	(5,693)	(37,687)	(17,951)
Total costs incurred	$ 264,330	$ 728,140	$ 516,040

Supplemental Oil And Gas Disc88

Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unproved properties acquired and wells in progress	$ 337,099	$ 485,568	$ 545,588
2,015
Unproved properties acquired and wells in progress	49,283
2,014
Unproved properties acquired and wells in progress	65,970
2,013
Unproved properties acquired and wells in progress	44,607
2012 and prior
Unproved properties acquired and wells in progress	$ 177,239

Supplemental Oil And Gas Disc89

Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil and Gas Disclosures [Abstract]
Revenues	$ 371,335	$ 723,566	$ 633,792
Production costs	(152,560)	(165,315)	(162,822)
Depreciation, depletion, amortization, and impairment	(1,844,726)	(347,220)	(222,672)
Results of operations, income before income taxes	(1,625,951)	211,031	248,298
Income tax (expense) benefit	612,496	(82,028)	(96,091)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$ (1,013,455)	$ 129,003	$ 152,207

Supplemental Oil And Gas Disc90

Supplemental Oil And Gas Disclosures (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) bbl in Thousands, Mcf in Thousands		12 Months Ended
		Dec. 31, 2015bblMcf	Dec. 31, 2014bblMcf	Dec. 31, 2013bblMcf
Oil (bbls)
Proved developed and undeveloped reserves:
Beginning of year		22,667	21,765	21,998
Revision of previous estimates	[1]	(3,954)	(3,174)	(2,113)
Extensions and discoveries		1,208	5,327	4,678
Infill reserves in existing proved fields		670	2,775	2,299
Purchases of minerals in place		0	236	0
Production		(3,783)	(3,844)	(3,360)
Sales		(73)	(418)	(1,737)
End of year		16,735	22,667	21,765
Proved developed reserves:
Beginning of year		17,448	15,594	16,441
End of year		14,679	17,448	15,594
Proved undeveloped reserves
Beginning of year		5,219	6,171	5,557
End of year		2,056	5,219	6,171
Natural Gas Liquids (bbls)
Proved developed and undeveloped reserves:
Beginning of year		48,529	41,205	35,166
Revision of previous estimates	[1]	(9,367)	(2,266)	836
Extensions and discoveries		1,948	10,850	7,273
Infill reserves in existing proved fields		1,861	3,577	1,945
Purchases of minerals in place		0	88	0
Production		(5,274)	(4,629)	(3,914)
Sales		(10)	(296)	(101)
End of year		37,687	48,529	41,205
Proved developed reserves:
Beginning of year		35,850	30,437	25,657
End of year		31,218	35,850	30,437
Proved undeveloped reserves
Beginning of year		12,679	10,768	9,509
End of year		6,469	12,679	10,768
Natural gas (Mcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf		646,961	581,784	555,647
Revision of previous estimates | Mcf	[1]	(139,514)	(32,790)	2,421
Extensions and discoveries | Mcf		20,974	113,541	68,611
Infill reserves in existing proved fields | Mcf		22,641	47,189	21,573
Purchases of minerals in place | Mcf		0	368	11
Production | Mcf		(65,546)	(58,854)	(56,757)
Sales | Mcf		(648)	(4,277)	(9,722)
End of year | Mcf		484,868	646,961	581,784
Proved developed reserves:
Beginning of year | Mcf		500,950	464,234	452,844
End of year | Mcf		416,395	500,950	464,234
Proved undeveloped reserves
Beginning of year | Mcf		146,011	117,550	102,803
End of year | Mcf		68,473	146,011	117,550
[1]	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

Supplemental Oil And Gas Disc91

Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash flows	$ 2,475,898	$ 6,398,236	$ 5,573,119
Future production costs	(1,017,777)	(2,069,636)	(1,734,985)
Future development costs	(228,445)	(560,102)	(571,170)
Future income tax expenses	(230,544)	(1,228,533)	(1,044,608)
Future net cash flows	999,132	2,539,965	2,222,356
10% annual discount for estimated timing of cash flows	(409,646)	(1,104,221)	(996,380)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves	$ 589,486	$ 1,435,744	$ 1,225,976	$ 1,079,956
Percentage of annual discount for estimated timing of cash flows	10.00%	10.00%	10.00%

Supplemental Oil And Gas Disc92

Supplemental Oil And Gas Disclosures (Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reserve Quantities [Line Items]
Sales and transfers of oil and natural gas produced, net of production costs	$ (218,115)	$ (558,252)	$ (470,970)
Net changes in prices and production costs	(1,356,333)	(33,259)	188,826
Revisions in quantity estimates and changes in production timing	(213,945)	(135,125)	(10,650)
Extensions, discoveries, and improved recovery, less related costs	95,671	635,752	426,377
Changes in estimated future development costs	227,857	96,339	26,629
Previously estimated cost incurred during the period	59,117	164,430	96,457
Purchases of minerals in place	0	8,395	9
Sales of minerals in place	(3,338)	(19,135)	(43,435)
Accretion of discount	209,979	179,190	147,579
Net change in income taxes	562,838	(98,119)	(170,091)
Other-net	(209,989)	(30,448)	(44,711)
Net change	(846,258)	209,768	146,020
Beginning of year	1,435,744	1,225,976	1,079,956
End of year	$ 589,486	$ 1,435,744	$ 1,225,976

Supplemental Oil And Gas Disc93

Supplemental Oil And Gas Disclosures Supplemental Oil and Gas Disclosures (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015$ / Unit
Oil (bbls)
Average Sales Prices	50.28
Natural Gas Liquids (bbls)
Average Sales Prices	19.47
Natural gas (Mcf)
Average Sales Prices	2.59

Schedule II - Valuation And Q94

Schedule II - Valuation And Qualifying Accounts And Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]
Balance at beginning of period	$ 5,039	$ 5,342	$ 5,343
Additions charged to costs and expenses	1,191	3,562	0
Deductions and net write-offs	(1,031)	(3,865)	(1)
Balance at end of period	$ 5,199	$ 5,039	$ 5,342