Unit (UNTC) 10-K 26 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 12, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
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		54,366,397
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 1,322,944,221
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents		$ 6,452	$ 701
Accounts receivable (less allowance for doubtful accounts of $2,531 and $2,450 at December 31, 2018 and 2017, respectively)		119,397	111,512
Materials and supplies		473	505
Current derivative asset (Note 13)		12,870	721
Current income taxes receivable		2,054	61
Assets held for sale (Note 2)		22,511	0
Prepaid expenses and other		11,356	6,172
Total current assets		175,113	119,672
Oil and natural gas properties, on the full cost method:
Proved properties		6,018,568	5,712,813
Unproved properties not being amortized		330,216	296,764
Drilling equipment		1,284,419	1,593,611
Gas gathering and processing equipment		767,388	726,236
Saltwater disposal systems		68,339	62,618
Corporate land and building		59,081	59,080
Transportation equipment		29,524	29,631
Other		57,507	53,439
Property, plant and equipment, gross, total		8,615,042	8,534,192
Less accumulated depreciation, depletion, amortization, and impairment		6,182,726	6,151,450
Net property and equipment		2,432,316	2,382,742
Goodwill (Note 2)		62,808	62,808
Other assets		27,816	16,230
Total assets	[1]	2,698,053	2,581,452
Current liabilities:
Accounts payable		149,945	112,648
Accrued liabilities (Note 6)		49,664	48,523
Current derivative liabilities (Note 13)		0	7,763
Current portion of other long-term liabilities (Note 7)		14,250	13,002
Total current liabilities		213,859	181,936
Long-term debt less unamortized discount and debt issuance costs (Note 7)		644,475	820,276
Non-current derivative liabilities (Note 13)		293	0
Other long-term liabilities (Note 7)		101,234	100,203
Deferred income taxes (Note 9)		144,748	133,477
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, 54,055,600 and 52,880,134 shares issued as of December 31, 2018 and 2017, respectively		10,414	10,280
Capital in excess of par value		628,108	535,815
Accumulated other comprehensive income (loss) (net of tax ($155) and $39 at December 31, 2018 and 2017, respectively) (Note 17)		(481)	63
Retained earnings		752,840	799,402
Total shareholders' equity attributable to Unit Corporation		1,390,881	1,345,560
Non-controlling interests in consolidated subsidiaries		202,563	0
Total shareholders' equity		1,593,444	1,345,560
Total liabilities and shareholders' equity	[1]	$ 2,698,053	$ 2,581,452
[1]	Unit Corporation's consolidated total assets as of December 31, 2018 include current and long-term assets of its variable interest entity (VIE) (Superior) of $41.7 million and $421.6 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 16 – Variable Interest Entity Arrangements.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 2,531	$ 2,450
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	54,055,600	52,880,134
Other Comprehensive Income (Loss), Tax	$ (155)	$ 39
VIE Current assets pledged	41,700
VIE Non-current assets pledged	421,600
VIE Current liabilities, no recourse	42,800
VIE Non-current liabilities, no recourse	$ 14,700

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Oil and natural gas	$ 423,059	$ 357,744	$ 294,221
Contract drilling	196,492	174,720	122,086
Gas gathering and processing	223,730	207,176	185,870
Total revenues	843,281	739,640	602,177
Expenses:
Oil and natural gas	131,675	130,789	120,184
Contract drilling	131,385	122,600	88,154
Gas gathering and processing	167,836	155,483	137,609
Total operating costs	430,896	408,872	345,947
Depreciation, depletion, and amortization	243,605	209,257	208,353
Impairments (Note 2)	147,884	0	161,563
General and administrative	38,707	38,087	33,337
Gain on disposition of assets	(704)	(327)	(2,540)
Total operating expenses	860,388	655,889	746,660
Income (loss) from operations	(17,107)	83,751	(144,483)
Other income (expense):
Interest, net	(33,494)	(38,334)	(39,829)
Gain (loss) on derivatives	(3,184)	14,732	(22,813)
Other	22	21	307
Total other income (expense)	(36,656)	(23,581)	(62,335)
Income (loss) before income taxes	(53,763)	60,170	(206,818)
Income tax expense (benefit):
Current	(3,131)	5	15
Deferred	(10,865)	(57,683)	(71,209)
Total income taxes	(13,996)	(57,678)	(71,194)
Net income (loss)	(39,767)	117,848	(135,624)
Net income attributable to non-controlling interest	5,521	0	0
Net income (loss) attributable to Unit Corporation	$ (45,288)	$ 117,848	$ (135,624)
Net income (loss) attributable to Unit Corporation per share:
Basic	$ (0.87)	$ 2.31	$ (2.71)
Diluted	$ (0.87)	$ 2.28	$ (2.71)

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (39,767)	$ 117,848	$ (135,624)
Other comprehensive income (loss), net of taxes:
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39, and $0	(557)	63	0
Other comprehensive income (loss), tax	(181)	39	0
Comprehensive income (loss)	(40,324)	117,911	(135,624)
Less: Comprehensive income attributable to non-controlling interest	5,521	0	0
Comprehensive income (loss) attributable to Unit Corporation	$ (45,845)	$ 117,911	$ (135,624)

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	Non-controlling Interest in Consolidated Subsidiaries
Beginning balance at Dec. 31, 2015	$ 1,313,580	$ 9,831	$ 486,571	$ 0	$ 817,178	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(135,624)	0	0	0	(135,624)	0
Total comprehensive income (loss)	(135,624)
Activity in employee compensation plans	16,114	185	15,929	0	0	0
Ending balance at Dec. 31, 2016	1,194,070	10,016	502,500	0	681,554	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	117,848	0	0	0	117,848	0
Other comprehensive income (loss)	63	0	0	63	0	0
Total comprehensive income (loss)	117,911
Proceeds from sale of stock	18,623	158	18,465	0	0	0
Activity in employee compensation plans	14,956	106	14,850	0	0	0
Ending balance at Dec. 31, 2017	1,345,560	10,280	535,815	63	799,402	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect adjustment for adoption of ASUs	(1,261)	0	0	13	(1,274)	0
Net income (loss)	(39,767)	0	0	0	(45,288)	5,521
Other comprehensive income (loss)	(557)	0	0	(557)	0	0
Total comprehensive income (loss)	(40,324)
Contributions	300,000	0	102,958	0	0	197,042
Transaction costs associated with sale of non-controlling	(2,503)	0	(2,503)	0	0	0
Tax effect on sale of non-controlling interest	(27,453)	0	(27,453)	0	0	0
Activity in employee compensation plans	19,425	134	19,291	0	0	0
Ending balance at Dec. 31, 2018	$ 1,593,444	$ 10,414	$ 628,108	$ (481)	$ 752,840	$ 202,563

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock Issued During Period, Shares, New Issues	0	787,547	0
Activity in employee compensation plans (shares)	1,175,466	598,269	1,081,217
Other comprehensive income (loss), tax	$ (181)	$ 39	$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES:
Net income (loss)	$ (39,767)	$ 117,848	$ (135,624)
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	243,605	209,257	208,353
Impairments (Note 2)	147,884	0	161,563
Amortization of debt issuance costs and debt discount	2,198	2,159	2,122
(Gain) loss on derivatives	3,184	(14,732)	22,813
Cash receipts (payments) on derivatives settled	(22,803)	173	9,658
Gain on disposition of assets	(704)	(327)	(3,127)
Deferred tax benefit	(10,865)	(57,683)	(71,209)
Employee stock compensation plans	22,899	17,747	13,812
Bad debt expense	81	348	785
ARO liability accretion	2,393	2,886	2,779
Contract assets and liabilities, net (Note 3)	(4,970)	0	0
Other, net	2,032	(865)	(6,037)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(12,955)	(32,073)	(11,796)
Materials and supplies	32	2,835	225
Prepaid expenses and other	(4,950)	1,527	2,585
Accounts payable	26,272	8,192	27,400
Accrued liabilities	(3,724)	6,996	(4,388)
Income taxes	(1,993)	38	20,903
Contract advances	(90)	1,630	(687)
Net cash provided by operating activities	347,759	265,956	240,130
INVESTING ACTIVITIES:
Capital expeditures	(446,282)	(255,553)	(186,149)
Producing property and other acquisitions	(29,970)	(58,026)	(564)
Proceeds from disposition of property and equipment	25,910	21,713	74,823
Other	0	(1,500)	919
Net cash used in investing activities	(450,342)	(293,366)	(110,971)
FINANCING ACTIVITIES:
Borrowings under line of credit	99,100	343,900	251,398
Payments under line of credit	(277,100)	(326,700)	(371,600)
Payments on capitalized leases	(3,843)	(3,694)	(3,694)
Proceeds from common stock issued, net of issue costs (Note 17)	0	18,623	0
Tax expense from stock compensation	0	0	(376)
Proceeds from investments of non-contolling interests	300,000	0	0
Transaction costs associated with sale of non-controlling interest	(2,503)	0	0
Decrease in book overdrafts (Note 2)	(7,320)	(4,911)	(4,829)
Net cash provided by (used in) financing activities	108,334	27,218	(129,101)
Net increase (decrease) in cash and cash equivalents	5,751	(192)	58
Cash and cash equivalents, beginning of year	701	893	835
Cash and cash equivalents, end of year	6,452	701	893
Supplemental disclosure of cash flow information:
Interest paid (net of capitalization)	34,535	33,931	35,690
Income taxes	3,600	0	42
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(18,119)	(20,574)	21,190
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	$ 7,629	$ 3,613	$ 30,897

Organization

Organization	12 Months Ended
	Dec. 31, 2018
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 or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior of which we own 50%. 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 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 mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, Montana, New Mexico, North Dakota, Utah, and Wyoming. Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, we drill onshore oil and natural gas wells for our own account and for a wide range of other oil and natural gas companies. Our drilling operations are mainly in Oklahoma, Texas, Wyoming, North Dakota, and to a lesser extent in Colorado and Utah. Mid-Stream. Carried out by our subsidiary, Superior, 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, 2018
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. We consolidate the activities of Superior, a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements. Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentations. 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. Typically, this type of contract can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2018, all of our contracts were daywork contracts of which 24 were multi-well and had durations which ranged from six months to three years, 17 of which expire in 2019 and seven expiring in 2020 and beyond. 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, 2018 and 2017, book overdrafts were $5.1 million and $12.4 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: 2018 2017 2016 Oil and Natural Gas: CVR Refining, LP 14 % 2 % — % Valero Energy Corporation 10 % 9 % 11 % Energy Transfer Partners (formerly Sunoco Logistics Partners) 3 % 10 % 24 % Drilling: QEP Resources, Inc. 16 % 26 % 28 % Slawson Exploration Company, Inc 10 % 6 % 3 % Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) 3 % 7 % 18 % Mid-Stream: ONEOK, Inc. 45 % 36 % 30 % Range Resources Corporation 7 % 9 % 10 % Koch Energy Services, LLC 6 % 8 % 11 % Tenaska Resources, LLC 4 % 6 % 10 % We had a concentration of cash of $11.0 million and $11.4 million at December 31, 2018 and 2017, 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, 2018 and determined there was no material risk at that time. At December 31, 2018, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: 12/31/2018 (In millions) Bank of Montreal $ 9.9 Bank of America Merrill Lynch 2.7 Total net assets $ 12.6 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, except when idle for greater than 48 months, then it will be depreciated at the full active rate. 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 on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. 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 cause materially different carrying values of our assets. On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9. Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax), the fair value of the assets held for sale at December 31, 2018 is $22.5 million. When p roperty 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. Our contract drilling segment had no impairments in either 2016 or 2017. 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. 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 2018, 2017, and 2016, interest of approximately $16.5 million, $15.9 million, and $15.3 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 impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, 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, 2018, 2017, or 2016. There were no additions to goodwill in 2018, 2017, or 2016. Based on our impairment test performed as of December 31, 2018, the fair value of our drilling segment exceeded its carrying value by 37%. While the goodwill of this reporting unit is not currently impaired, there could be an impairment in the future as a result of changes in certain assumptions. For example, the fair value could be adversely affected and result in an impairment of goodwill if we do not realize the anticipated drilling rig utilization of the anticipated drilling rig dayrates, or if the estimated cash flows are discounted at a higher risk-adjusted rate or market multiples decrease. Goodwill of $0.4 million is deductible for tax purposes. 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 $15.9 million, $14.8 million, and $15.4 million were capitalized in 2018, 2017, and 2016, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $7.50, $6.00, and $6.24 per Boe in 2018, 2017, and 2016, respectively. The calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. Our unproved properties and wells in progress totaling $330.2 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 $7.6 million and $10.5 million in 2016 and 2017, respectively of costs being added to the total of our capitalized costs being amortized. We did not have any in 2018. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million net of tax) due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We had no non-cash ceiling test write-downs during 2017 or 2018. Our contract drilling segment provides drilling services for our exploration and production segment. Depending on the timing of the drilling services performed on our properties those services may be deemed, for financial reporting purposes, to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for these services are eliminated in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties. The contracts for these services are issued under the similar terms and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $22.5 million and $13.4 million during 2018 and 2017, respectively, from our contract drilling segment and eliminated the associated operating expense of $19.5 million and $11.8 million during 2018 and 2017, respectively, yielding $3.0 million and $1.6 million during 2018 and 2017, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016. ARO. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool. 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. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. 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 with the exception of normal purchase and normal sales which are expected to result in physical delivery. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. We document our risk management strategy and do not engage in derivative transactions for speculative purposes. Limited Partnerships. Unit Petroleum Company is a general partner in 13 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. During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. The change in tax law required the Company to remeasure existing net deferred tax liabilities using the lower rate in the period of enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); 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. Natural Gas Balancing. We account for revenue transactions under ASC 606 for recording natural gas sales , which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2018 balancing position to be approximately 3.8 Bcf on under-produced properties and approximately 3.7 Bcf on over-produced properties. We have recorded a receivable of $2.9 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.3 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 SARs. The value of our restricted stock grants is based on the closing stock price on the date of the grants. New Accounting Standards Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our financial statements. Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands Topic 718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This amendment will not have a material impact on our financial statements. Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements. Leases. The FASB has issued several accounting standards updates and amendments related to leases in the past two years, which are codified within Topic 842. For public companies, these are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Other recently issued amendments to Topic 842 have provided clarifying guidance regarding land easements, an additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees and lessors. The standard will not apply to leases of mineral rights. We established an implementation team working through the provisions of the new guidance including a review of different types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes, internal control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the new guidance is substantially complete. We have made certain accounting policy decisions including that we plan to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. Our transition will utilize the modified retrospective approach to adopting the new standard, and will be applied at the beginning of the period adopted (January 1, 2019) in accordance with ASU 2018-11. We have elected the transition practical expedient, which allows us to not evaluate land easements that existed prior to January 1, 2019, and the optional transition method to record our immaterial adoption impact through a cumulative adjustment to equity. We expect for certain lessee asset classes to elect the practical expedient and not separate lease and nonlease components. For these asset classes, we will account for the agreements as a single lease component. We have determined that Unit Drilling Company lessor drilling rig contracts will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract. For both lessee and lessor practical expedients, we considered quantitative and qualitative factors when determining if an asset class qualified for the application of the practical expedient. The adoption of this guidance will result in the addition of right-of-use assets and corresponding lease obligations to the consolidated balance sheet and will not have a material impact on the Company’s results of operations or cash flows. Upon adoption, the Company expects to record operating lease right-of-use assets and the corresponding operating lease liabilities in the range of approximately $3.0 million to $4.5 million, representing the present value of future lease payments under operating leases. The Company is in the process of finalizing its catalog of existing lease contracts and implementing changes to its processes. There would be no impact to the Superior credit agreement debt covenants and an immaterial impact to the Unit credit agreement debt covenants as a result of adopting this standard. Adopted Standards As of January 1, 2018, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and we now use 24.5%. This change is reflected in our Consolidated Statements of Comprehensive Income and in Note 17 - Equity. Also, as of January 1, 2018, we adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606) and all later amendments that modified ASC 606. We elected to apply this standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect on adoption, which only affected our mid-stream segment, is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for certain demand fees. Our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605. The additional disclosures required by ASC 606 have been included in Note 3 – Revenue from Contracts with Customers. Our internal control framework did not materially change because of this standard, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard,

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	REVENUE FROM CONTACTS WITH CUSTOMERS Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 18 – Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on time period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. We sell the hydrocarbons (from the oil and natural gas and mid-stream segments) to mid-stream and downstream oil and gas companies. We satisfy the performance obligation under each segment's contracts as follows: for the contract drilling and mid-stream contracts, we satisfy the performance obligation over the agreed-on time within the contracts, and for oil and natural gas contracts, we satisfy the performance obligation with each delivery of volumes. For oil and natural gas contracts, as it is more feasible, we account for these deliveries monthly. Per the contracts for all segments, customers pay for the services/goods received monthly within an agreed on number of days following the end of the month. Besides the mid-stream demand fees discussed further below, there were no other contract assets or liabilities falling within the scope of this accounting pronouncement. Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations Typical types of revenue contracts signed by our segments are Oil Sales Contracts, Gas Purchase Agreements, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract term can range from a single month to a term spanning a decade or more; some may also include evergreen provisions. Revenues from sales we make are recognized when our customer obtains control of the sold product. For sales to other mid-stream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. Our adoption of this standard required no adjustment to opening retained earnings. Certain costs—as either a deduction from revenue or as an expense—is determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs. The impact of the adoption of ASC 606 did not impact income from operations or net income for the year ended December 31, 2018. These tables summarize the impact of the adoption of ASC 606 on revenue and operating costs for the year ended December 31, 2018: As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606 (In thousands) Oil and natural gas revenues $ 423,059 $ (17,518) $ 440,577 Oil and natural gas operating costs 131,675 (17,518) 149,193 Gross profit $ 291,384 $ — $ 291,384 Our performance obligation for all commodity contracts is the delivery of oil and gas volumes to the customer. Typically, the contract is for a specified period (for example, a month or a year); however, each delivery under that contract can be considered separately identifiable since each delivery provides benefits to the customer on its own. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we conclude this performance obligation is satisfied monthly. We typically receive a payment within a set number of days following the end of the month which includes payment for all deliveries in that month. Depending on contract circumstances, judgment could be required to determine when the transfer of control occurs. Generally, depending of the facts and circumstances, we consider the transfer of control of the asset in a commodity sale to occur at the point the commodity transfers to our purchaser. Most of the consideration received by us for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by an agreed-on index price less deductions related to gathering, transportation, fractionation, and related fuel charges. There are also instances where the consideration is quantity multiplied by a weighted average sales price. These different pricing tools can change the perception of when control transfers; however, when analyzed with other control factors, typically the accounting conclusion is the same for both pricing methods. In these instances, the variable consideration is partially constrained. In addition, all variable consideration is settled at the end of the month; therefore, whether the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period. An estimation and allocation of transaction price and future obligations are not required. Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations The contracts our drilling segment uses are primarily industry standard IADC contracts model year 2003 and 2013. Contract terms range from six months to three Our performance obligation for all drilling contracts is to drill the agreed-on number of wells or drill over an agreed-on period as stated in the contract. Any mobilization and demobilization activities are not considered distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to three years. Most of the drilling contracts are for less than one year. As the customer simultaneously receives and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and that payment includes payment for all services performed during that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-on depth or by a set date. All consideration received for contract drilling is variable, excluding termination fees, which we have concluded will not apply to our contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the financial statements was immaterial. As of December 31, 2018, we had 32 contract drilling contracts (24 of which are term contracts) for a duration of two months to three years. Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). The majority of our drilling contracts have an original term of less than one year; however, the remaining performance obligations under the contracts that have a longer duration are not material. Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. The typical revenue contracts used by this segment are gas gathering and processing agreements. Contract terms range from a single month to terms spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services. On adoption of the standard, an adjustment to opening retained earnings was made for $1.7 million ($1.3 million, net of tax). This adjustment—related to the timing of revenue recognized on certain demand fees—impacted our Consolidated Balance Sheet (for the periods indicated) as follows: Balance at December 31, 2017 Adjustments due to ASC 606 Balance at January 1, (In thousands) Assets: Other assets $ 16,230 $ 10,798 $ 27,028 Liabilities and shareholders' equity: Current portion of other long-term liabilities 13,002 2,748 15,750 Other long-term liabilities 100,203 9,737 109,940 Deferred income taxes 133,477 (413) 133,064 Retained earnings 799,402 (1,274) 798,128 At December 31, 2018: As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606 (In thousands) Assets: Prepaid expenses and other $ 11,356 $ 285 $ 11,071 Other assets 27,816 12,879 14,937 Liabilities and shareholders' equity: Current portion of other long-term liabilities 14,250 2,874 11,376 Other long-term liabilities 101,234 7,007 94,227 Deferred income taxes 144,748 805 143,943 Retained earnings 752,840 2,478 750,362 This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Consolidated Statement of Operations for 2018: As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606 (In thousands) Gas gathering and processing revenues $ 223,730 $ 4,970 $ 218,760 Deferred income tax benefit (10,865) 1,218 (12,083) Net income (loss) (39,767) 3,752 (43,519) The only fixed consideration related to mid-stream consideration is a demand fee calculated by multiplying an agreed-on price by a fixed number of volumes per month over a specified term in the contract. Included below is the additional fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract. Contract Remaining Term of Contract 2019 2020 2021 2022 Total Remaining Impact to Revenue Demand fee contracts 4 years $ 2,632 $ (3,781) $ (3,507) $ 1,374 $ (3,282) Before implementing ASC 606, we immediately recognized the entire demand fee since the fee was payable within the first five years from the effective date of the contract and not over the entire term of the contract. However, as the demand fee does not specifically relate to a distinct performance obligation, under the new standard that amount should now be recognized over the life of the contract. Therefore, the demand fee previously recognized for $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018 and will be recognized over the remaining term of the contract. As this amount is fixed, recognition of the remaining portion will be stable. Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported). For 2018, $5.0 million was recognized in revenue for these demand fees. December 31, 2018 January 1, Change (In thousands) Contract assets $ 13,164 $ 10,798 $ 2,366 Contract liabilities 9,881 12,485 (2,604) Contract assets (liabilities), net $ 3,283 $ (1,687) $ 4,970 Our performance obligations for all contracts is to gather, transport, or process an agreed-on number of volumes as stated in the contract. Typically, the contract will establish a period over which the company will perform the mid-stream services. Certain contracts also include an agreed-on quantity (or an agreed-on minimum quantity) of volumes that the company will deliver or service. The term under mid-stream service contracts is typically five Most of the consideration received under mid-stream service contracts is variable. The consideration is calculated by multiplying a variable quantity (number of volumes) by an agreed-on price per MCF (commodity fee and the gathering fee). One fixed component of revenue is calculated by multiplying an agreed-on price by a certain volume commitment (MCF per day). Other revenue items may include shortfall fees. All variable consideration is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. However, this excludes the shortfall fee as this fee could be based on a set number of volumes over the course of more than one month. Per the new guidance related to disclosures for remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14). There is also a practical expedient for “variable consideration [that] is allocated entirely to a wholly unsatisfied performance obligation… that forms part of a single performance obligation… for which the criteria in paragraph 606-10-32-40 have been met” (ASC 606-10-50-14A). As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee. The last time we received a shortfall fee was in 2016 and the amount was immaterial to total mid-stream revenues. These terms have historically been limited in our contracts. We calculate revenue earned from the variable consideration related to mid-stream services by multiplying the number of volumes serviced times an agreed-on price. Therefore, the variable portion of this consideration is due to the change in volumes. This variability is resolved at the end of each month as the company will know the number of volumes serviced under each contract and payment is received monthly. The mid-stream gathering service contracts remaining are for a duration of less than one year to 15 years. While long term service contracts are in place as of the reporting date, due to the variable volumes an estimation and allocation of transaction price and future obligations are not required.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2018
Acquisitions and Divestitures [Abstract]
Acquisitions and Divestitures	ACQUISITIONS AND DIVESTITURES Acquisitions For 2016, we had approximately $0.6 million in acquisitions. On April 3, 2017, we closed on an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction. We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations , which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed. Final Adjusted Purchase Price Total consideration given $ 54,332 Final Adjusted Allocation of Purchase Price Oil and natural gas properties included in the full cost pool: Proved oil and natural gas properties $ 43,745 Undeveloped oil and natural gas properties 8,650 Total oil and natural gas properties included in the full cost pool (1) 52,395 Gas gathering equipment and other 2,340 Asset retirement obligation (403) Fair value of net assets acquired $ 54,332 _________________________ 2. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. The pro forma effects of this acquired business are immaterial to the results of operations. For 2017, we had approximately $4.7 million in other acquisitions. In December 2018, we closed on an acquisition of certain oil and natural gas assets located primarily in Custer County, Oklahoma. The total preliminary adjusted value of consideration given was $29.6 million As of November 1, 2018, the effective date of the acquisition, the estimated proved oil and gas reserves for the acquired properties was 2.6 MMBoe net to Unit. The acquisition added approximately 8,667 net oil and gas leasehold acres to our Penn Sands area in Oklahoma including approximately 44 wells. The acquisition included approximately 30 potential horizontal drilling locations which are anticipated to have a high percentage of oil relative to the total production stream. Of the acreage acquired, approximately 82% was held by production. We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations , which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed. Preliminary Purchase Price Total consideration given $ 29,633 Preliminary Allocation of Purchase Price Oil and natural gas properties included in the full cost pool: Proved oil and natural gas properties $ 14,546 Undeveloped oil and natural gas properties 15,502 Total oil and natural gas properties included in the full cost pool (1) 30,048 Asset retirement obligation (415) Fair value of net assets acquired $ 29,633 _________________________ 1. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates . The pro forma effects of this acquired business are immaterial to the results of operations. For 2018, we had approximately $0.6 million in other acquisitions. Divestitures Oil and Natural Gas We had non-core asset sales with proceeds, net of related expenses, of $22.5 million, $18.6 million, and $67.2 million, in 2018, 2017, and 2016, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized. Contract Drilling During December 2016, we sold one idle 1500 HP SCR drilling rig to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $1.7 million net book value of the drilling rig, resulting in a gain of $1.6 million. We did not have any divestitures in 2017. In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9. Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax). Mid-Stream On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior. The purchaser is SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. We received $300.0 million from this sale. A portion of the proceeds were used to pay down our bank debt and the remainder were used to accelerate the drilling program of our upstream subsidiary, Unit Petroleum Company and build additional BOSS drilling rigs. In connection with the sale of the interest in Superior, we took the necessary actions under the Indenture governing our outstanding senior subordinated notes to secure the ability to close the sale and have Superior released from the Indenture.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
	Dec. 31, 2018
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, 2016: Basic loss attributable to Unit Corporation per common share $ (135,624) 50,029 $ (2.71) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss attributable to Unit Corporation per common share $ (135,624) 50,029 $ (2.71) For the year ended December 31, 2017: Basic earnings attributable to Unit Corporation per common share $ 117,848 51,113 $ 2.31 Effect of dilutive stock options — 635 (0.03) Diluted income attributable to Unit Corporation per common share $ 117,848 51,748 $ 2.28 For the year ended December 31, 2018: Basic loss attributable to Unit Corporation per common share (45,288) 51,981 $ (0.87) Effect of dilutive restricted stock — — — Diluted loss attributable to Unit Corporation per common share $ (45,288) 51,981 $ (0.87) Due to the net loss for the years ended December 31, 2018 and 2016, approximately 934,000 and 509,000, respectively, 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: 2018 2017 2016 Options and SARs 66,500 87,500 199,755 Average exercise price $ 44.42 $ 51.34 $ 48.79

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES Accrued liabilities consisted of the following as of December 31: 2018 2017 (In thousands) Employee costs $ 22,056 $ 19,521 Lease operating expenses 12,756 11,819 Interest payable 6,635 6,745 Third-party credits 2,129 2,240 Taxes 1,378 3,404 Other 4,710 4,794 Total accrued liabilities $ 49,664 $ 48,523

Long-Term Debt And Other Long-T

Long-Term Debt And Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 (In thousands) Unit credit agreement with average interest rate of 3.4% at December 31, 2017 $ — $ 178,000 Superior credit agreement — — 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount $ 650,000 $ 828,000 Less: unamortized discount (1,623) (2,234) Less: debt issuance costs, net (3,902) (5,490) Total long-term debt $ 644,475 $ 820,276 Unit Credit Agreement. On October 18, 2018, we signed a Fifth Amendment to our Senior Credit Agreement (Unit credit agreement) amending our existing credit agreement entered into between the Company and certain lenders on September 13, 2011, as amended September 5, 2012, as further amended April 10, 2015, as further amended on April 8, 2016, as further amended on April 2, 2018, attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 15, 2011, September 11, 2012, April 13, 2015, April 8, 2016, and April 6, 2018, respectively, and the Company’s Current Report on Form 8-K/A filed on April 13, 2016, and each incorporated by reference herein. The Fifth Amendment, among other things, (i) extends the term of the Unit credit agreement to October 18, 2023, subject to certain conditions; (ii) reduces the pricing for borrowing and non-use fees; and (iii) eliminates the requirement that the company maintain a senior indebtedness to consolidated EBITDA ratio. The total commitment of credit and the borrowing base both remain unchanged at $425.0 million. Under the Unit credit agreement, the amount we can borrow is the lesser of the amount we elect 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. We are charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees are being amortized over the life of the Unit credit agreement. Under the Unit credit agreement, we have pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. On April 2, 2018, we signed the fourth amendment to the Unit credit agreement. The Fourth Amendment provided, among other things, for a reduction of the maximum credit amount from $875.0 million to $425.0 million, a reduction in the borrowing base from $475.0 million to $425.0 million, a reduction in the total commitment amount from $475.0 million to $425.0 million; and the full release of Superior and its subsidiaries as a borrower and co-obligor under the Unit credit agreement. Under the amendment once the sale of the interest in Superior was completed, we were required to use part of the proceeds to pay down the Unit credit agreement. The Superior sale closed on April 3, 2018 and the pay down was made that day. On May 2, 2018, as contemplated under the Fourth Amendment, we entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent for the benefit of the secured parties, under which we granted a security interest in the limited liability membership interests and other equity interests we own in Superior (which as of the date of this report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the Unit credit agreement. The borrowing base amount–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. We or the lenders may request a one time 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 Unit credit agreement. At our election, any part of the outstanding debt under the Unit 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 1.50% 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 Unit credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At December 31, 2018, we had no outstanding borrowings under the Unit 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 Unit credit agreement prohibits, among other things: • the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year; • the incurrence of additional debt with certain limited exceptions; • the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except for our lenders ; and • investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million. The Unit 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. • 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, 2018, we were in compliance with the covenants contained in the Unit credit agreement. Superior Credit Agreement. On May 10, 2018, Superior, a limited liability company equally owned between us and SP Investor Holdings, LLC, entered into a five Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement. The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. Additionally, the Superior credit agreement contains a number of customary covenants that, among other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of December 31, 2018, Superior was in compliance with the Superior credit agreement covenants The borrowings the Superior credit agreement will be used to fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior. On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the agreement. Superior's credit agreement is not guaranteed by Unit. 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 issuing the Notes. The Guarantors are 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. 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, 2018. Other Long-Term Liabilities Other long-term liabilities consisted of the following as of December 31: 2018 2017 (In thousands) ARO liability $ 64,208 $ 69,444 Workers’ compensation 12,738 13,340 Capital lease obligations 11,380 15,224 Contract liability 9,881 — Separation benefit plans 8,814 6,524 Deferred compensation plan 5,132 5,390 Gas balancing liability 3,331 3,283 115,484 113,205 Less current portion 14,250 13,002 Total other long-term liabilities $ 101,234 $ 100,203 Estimated annual principal payments under the terms of debt and other long-term liabilities from 2019 through 2023 are $14.2 million, $9.4 million, $692.0 million, $3.9 million, and $2.2 million, respectively. Capital Leases During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven average $4.3 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, 2018 are as follows: Amount Ending December 31, (In thousands) 2019 $ 6,168 2020 6,168 2021 3,768 Total future payments 16,104 Less payments related to: Maintenance 4,089 Interest 635 Present value of future minimum payments $ 11,380

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 (In thousands) ARO liability, January 1: $ 69,444 $ 70,170 Accretion of discount 2,393 2,886 Liability incurred 2,632 1,948 Liability settled (4,493) (2,694) Liability sold (281) (1,735) Revision of estimates (1) (5,487) (1,131) ARO liability, December 31: 64,208 69,444 Less current portion 1,437 1,726 Total long-term ARO liability $ 62,771 $ 67,718 _________________________ 1. Plugging liability estimates were revised in both 201

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among its many provisions, the Tax Act reduces the federal corporate tax rate from 35% to 21%, effective January 1, 2018. The change in tax law required the Company to revalue its existing net deferred tax liability using the lower rate in the period of enactment resulting in the recognition of an income tax benefit of $81.3 million for the year ended December 31, 2017 related to that revaluation. As a result, the Company recognized an overall income tax benefit of $57.7 million for the year ended December 31, 2017. 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: 2018 2017 2016 (In thousands) Income tax expense (benefit) computed by applying the statutory rate $ (11,290) $ 21,059 $ (72,386) State income tax expense (benefit), net of federal benefit (1,882) 1,655 (5,687) Deferred tax liability revaluation (1) — (81,307) — Restricted stock shortfall 424 1,867 5,465 Non-controlling interest in Superior (1,138) — — Statutory depletion and other (110) (952) 1,414 Income tax benefit $ (13,996) $ (57,678) $ (71,194) __________________________ 1. In 2017, the revaluation from the Tax Act. For the periods indicated, the total provision for income taxes consisted of the following: 2018 2017 2016 (In thousands) Current taxes: Federal $ (1,835) $ — $ — State (1,296) 5 15 (3,131) 5 15 Deferred taxes: Federal (8,741) (62,788) (62,923) State (2,124) 5,105 (8,286) (10,865) (57,683) (71,209) Total provision $ (13,996) $ (57,678) $ (71,194) Deferred tax assets and liabilities are comprised of the following at December 31: 2018 2017 (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 27,953 $ 32,242 Net operating loss carryforward 152,112 153,746 Alternative minimum tax and research and development tax credit carryforward 3,574 5,409 183,639 191,397 Deferred tax liability: Depreciation, depletion, amortization, and impairment (291,542) (324,874) Investment in Superior (36,845) — Net deferred tax liability (144,748) (133,477) Current deferred tax asset — — Non-current—deferred tax liability $ (144,748) $ (133,477) 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. We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal tax examinations for years before 2016 or state income tax examinations by state taxing authorities for years before 2015. At December 31, 2018, we have federal net operating loss carryforwards of approximately $576.9 million which expire from 2021 to 2037.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2018
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 184,203, 155,822, and 630,039 shares of common stock and recognized expense of $5.1 million, $4.4 million, and $4.0 million in 2018, 2017, and 2016, 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, 2018 and 2017 was $5.1 million and $5.4 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 $3.6 million, $2.7 million, and $3.1 million in 2018, 2017, and 2016, 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 three 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, 2018
Related Party Transactions [Abstract]
Transactions With Related Parties	TRANSACTIONS WITH RELATED PARTIESUnit Petroleum Company serves as the general partner of 13 oil and gas limited partnerships (the employee partnerships) which 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. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. Previously, there were three non-employee partnerships, one that was formed in 1984 and two formed in 1986 (investments by third parties). Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were also dissolved. 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: 2018 2017 2016 (In thousands) Well supervision and other fees $ 158 $ 172 $ 254 General and administrative expense reimbursement — — 6 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. As of December 31, 2016, John Nikkel retired as director and chairman of Unit's board and is no longer considered a related party. As of 2016, Mr. Nikkel was a 25.8% owner of Rampart Holdings, Inc. which owned 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 owned 20.0% of the company. There were no material revenues in 2016. There were no material royalties to disclose for 2016. Toklan operates the North Custer Gathering System, an inactive (since 2009) gathering system, under its affiliate, West Thomas Field Services, LLC (West Thomas), a company in which Mr. John Nikkel held an approximate 25.0% ownership interest and in which Mr. Robert Nikkel held 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 $0.4 million for 2016 volumes purchased. Additionally, on March 10, 2016, Mr. Nikkel purchased in the open market $0.4 million in aggregate principal amount of our outstanding 6.625% senior subordinated notes due 2021. The notes pay interest semi-annually in cash in arrears on May 15 and November 15 of each year. For 2016, interest payments for May and November were approximately $4,800 and $13,250, respectively. One of our directors, G. Bailey Peyton IV, also serves as Manager and 99.5% owner 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 $0.9 million, $0.7 million, and $0.5 million during 2018, 2017, and 2016, 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, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	STOCK-BASED COMPENSATION For restricted stock awards, we had: 2018 2017 2015 (In millions) Recognized stock compensation expense $ 17.8 $ 13.3 $ 9.6 Capitalized stock compensation cost for our oil and natural gas properties 2.1 1.8 2.1 Tax benefit on stock based compensation 4.4 5.0 3.6 The remaining unrecognized compensation cost related to unvested awards at December 31, 2018 is approximately $16.1 million of which $1.9 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 of a year. 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) and to non-employee directors. A total of 7,230,000 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, 2016 131,770 $ 46.60 Granted — — Exercised — — Forfeited (40,515) 51.76 Outstanding at December 31, 2016 91,255 44.31 Granted — — Exercised — — Forfeited (91,255) 44.31 Outstanding at December 31, 2017 — $ — There were no SARs granted or vested during 2018, 2017, or 2016. There were no SARs exercised in 2018. The SARs expired after 10 years from the date of the grant, and there were no outstanding shares at December 31, 2018. 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, 2016 936,662 277,160 1,213,822 $ 41.29 Granted 494,078 152,373 646,451 5.62 Vested (425,195) — (425,195) 43.47 Forfeited (75,808) (57,405) (133,213) 36.87 Nonvested at December 31, 2016 929,737 372,128 1,301,865 23.32 Granted 485,799 173,373 659,172 26.07 Vested (455,570) (62,119) (517,689) 29.87 Forfeited (44,408) (34,953) (79,361) 38.87 Nonvested at December 31, 2017 915,558 448,429 1,363,987 21.25 Granted 844,498 390,445 1,234,943 20.52 Vested (470,171) (209,643) (679,814) 24.30 Forfeited (21,002) (21,106) (42,108) 19.80 Nonvested at December 31, 2018 1,268,883 608,125 1,877,008 $ 19.70 Non-Employee Directors Number of Shares Weighted Average Price Nonvested at January 1, 2016 42,064 $ 41.83 Granted 90,000 12.02 Vested (20,248) 43.46 Forfeited — — Nonvested at December 31, 2016 111,816 $ 17.21 Granted 49,104 17.92 Vested (43,206) 21.24 Forfeited — — Nonvested at December 31, 2017 117,714 $ 16.03 Granted 44,312 19.86 Vested (54,981) 17.08 Forfeited — — Nonvested at December 31, 2018 107,045 $ 17.07 The time vested restricted stock awards granted are being recognized over a three The fair value of the restricted stock granted in 2018, 2017, and 2016 at the grant date was $24.7 million, $17.4 million, and $4.5 million, respectively. The aggregate intrinsic value of the 734,795 shares of restricted stock that vested in 2018 on their vesting date was $15.0 million. The aggregate intrinsic value of the 1,984,053 shares of restricted stock outstanding subject to vesting at December 31, 2018 was $28.3 million with a weighted average remaining life of 1.1 of a year. Non-Employee Directors' Stock Option Plan Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The option price for each stock option was the fair market value of the common stock on the date the stock options were granted. The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six months of its term except in case of death. On May 2, 2012, our stockholders approved the amended plan which succeeds this plan, the remaining available shares were transferred over to the new 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, 2016 129,500 $ 54.15 Granted — — Exercised — — Forfeited (21,000) 62.40 Outstanding at December 31, 2016 108,500 52.56 Granted — — Exercised — — Forfeited (21,000) 57.63 Outstanding at December 31, 2017 87,500 51.34 Granted — — Exercised — — Forfeited (21,000) 73.26 Outstanding at December 31, 2018 66,500 $ 44.42 There were no options exercised in 2018. Outstanding and Exercisable Weighted Average Exercise Price Number of Shares Weighted Average Remaining Weighted Average $31.30 - $41.21 38,500 0.9 years $ 37.58 $53.81 - $73.26 28,000 2.3 years $ 53.81 There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2018. The remaining weighted average remaining contractual term is 1.5 years.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2018
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 are based, in part, on our view of current and future market conditions. As of December 31, 2018, 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. • Basis Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis swaps to hedge the price risk between NYMEX and its physical delivery points. • 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. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. At December 31, 2018, the following non-designated hedges were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Jan’19 – Mar'19 Natural gas – swap 50,000 MMBtu/day $3.440 IF – NYMEX (HH) Apr'19 – Dec'19 Natural gas – swap 40,000 MMBtu/day $2.900 IF – NYMEX (HH) Jan’19 – Dec'19 Natural gas – basis swap 20,000 MMBtu/day $(0.659) PEPL Jan’19 – Dec'19 Natural gas – basis swap 10,000 MMBtu/day $(0.625) NGPL MIDCON Jan’19 – Dec'19 Natural gas – basis swap 30,000 MMBtu/day $(0.265) NGPL TEXOK Jan’20 – Dec'20 Natural gas – basis swap 30,000 MMBtu/day $(0.275) NGPL TEXOK Jan’19 – Dec'19 Natural gas – collar 20,000 MMBtu/day $2.63 - $3.03 IF – NYMEX (HH) Jan'19 – Mar'19 Natural gas – three-way collar 30,000 MMBtu/day $3.17 - $2.92 - $4.32 IF – NYMEX (HH) Jan’19 – Dec'19 Crude oil – three-way collar 4,000 Bbl/day $61.25 - $51.25 - $72.93 WTI – NYMEX After December 31, 2018, the following non-designated hedges were entered into: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Apr'19 – Oct'19 Natural gas – swap 20,000 MMBtu/day $2.900 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 2018 2017 (In thousands) Commodity derivatives: Current Current derivative assets $ 12,870 $ 721 Long-term Non-current derivative assets — — Total derivative assets $ 12,870 $ 721 Derivative Liabilities Fair Value Balance Sheet Location 2018 2017 (In thousands) Commodity derivatives: Current Current derivative liabilities $ — $ 7,763 Long-term Non-current derivative liabilities 293 — Total derivative liabilities $ 293 $ 7,763 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. Effect of derivative instruments on the Consolidated Statements of Operations for the year ended December 31: Derivatives Instruments Location of Gain or (Loss) Recognized in Income on Derivative Amount of Gain or (Loss) Recognized in Income on Derivative 2018 2017 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (3,184) $ 14,732 Total $ (3,184) $ 14,732 _________________________ 1. Amount s settled during the periods are a loss of $22,803 and a gain of $173, respectively.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The estimated fair value of our available-for-sale securities, reflected on our Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities: Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (In thousands) Equity Securities: December 31, 2018 $ 830 $ — $ 636 $ 194 December 31, 2017 $ 830 $ 102 $ — $ 932 During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. These securities would be classified as Level 2. 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, 2018 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 3,225 $ 10,964 $ (1,319) $ 12,870 Liabilities (1,278) (334) 1,319 (293) $ 1,947 $ 10,630 $ — $ 12,577 December 31, 2017 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 2,137 $ 3,344 $ (4,760) $ 721 Liabilities (8,973) (3,550) 4,760 (7,763) $ (6,836) $ (206) $ — $ (7,042) All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of December 31, 2018. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities). 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, 2018 December 31, 2017 (In thousands) Beginning of period $ (206) $ (7,122) Total gains or losses: Included in earnings (1) 4,159 7,791 Settlements 6,677 (875) End of period $ 10,630 $ (206) Total gains for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period $ 10,836 $ 6,916 _________________________ 1. Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives. The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2018: Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil three-way collar 10,592 Discounted cash flow Forward commodity price curve $0.00 - $19.44 Natural gas collars (334) Discounted cash flow Forward commodity price curve $0.00 - $0.38 Natural gas three-way collar 372 Discounted cash flow Forward commodity price curve $0.00 - $0.43 _________________________ 1. The commodity contracts detailed in this category include non-exchange-traded crude and natural gas three-way collars and natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period. Based on our valuation at December 31, 2018, 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, 2018, 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 agreements would approximate its fair value. This debt would be classified as Level 2. At December 31, 2018, we did not have any outstanding debt under our credit agreements. The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Consolidated Balance Sheets at December 31, 2018 and December 31, 2017 were $644.5 million and $642.3 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2018 and December 31, 2017 were $600.5 million and $649.7 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

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, 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 $4.6 million, $1.7 million, and $0.4 million in 2019 through 2021, respectively. Total rent expense incurred was $9.9 million, $8.8 million, and $11.1 million in 2018, 2017, and 2016, respectively. During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven 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 approximately $1,700, $2,900, $5,000 in 2018, 2017, and 2016, respectively. 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 2019, we have committed to purchase approximately $9.2 million of new drilling rig components. We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matter, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our results of operations, financial position, or cash flows.

Variable Interest Entity Arrang

Variable Interest Entity Arrangements	12 Months Ended
	Dec. 31, 2018
Variable Interest Entity Arrangements [Abstract]
Variable Interest Entity Disclosure	VARIABLE INTEREST ENTITY ARRANGEMENTSOn April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior will be governed and managed under the Amended and Restated Limited Liability Company Agreement and the MSA. The MSA is between our affiliate, SPC Midstream Operating, L.L.C. (the Operator) and Superior. The Operator is owned 100% by Unit Corporation. Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA houses the power to direct the activities that most significantly impact Superior's operating performance. The MSA is a separate variable interest. Unit through the MSA has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most significantly impact the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary as of December 31, 2018. As the primary beneficiary of this VIE, we consolidate in the financial statements the financial position, results of operations and cash flows of this VIE, and all intercompany balances and transactions between us and the VIE are eliminated in the consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements. As the Operator, we provide services, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $250,000. Superior's creditors have no recourse to our general credit. Superior's credit agreement is not guaranteed by Unit. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows: December 31, (In thousands) Current assets: Cash and cash equivalents $ 5,841 Accounts receivable 33,207 Prepaid expenses and other 2,693 Total current assets 41,741 Property and equipment: Gas gathering and processing equipment 767,388 Transportation equipment 3,086 770,474 Less accumulated depreciation, depletion, amortization, and impairment 364,740 Net property and equipment 405,734 Other assets 15,907 Total assets $ 463,382 Current liabilities: Accounts payable $ 32,214 Accrued liabilities 3,688 Current portion of other long-term liabilities 6,875 Total current liabilities 42,777 Long-term debt less debt issuance costs — Other long-term liabilities 14,687 Total liabilities $ 57,464

Equity

Equity	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Equity	EQUITY At-the-Market (ATM) Common Stock Program On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intended to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes. On May 2, 2018, we terminated the Distribution Agreement. The Distribution Agreement was terminable at will on written notification by us with no penalty. As of the date of termination, we had sold 787,547 shares of our common stock under the Distribution Agreement resulting in net proceeds of approximately $18.6 million. We paid the sales agent a commission of 2.0% of the gross sales price per share sold. As a result of the termination, there will be no more sales of our common stock under the Distribution Agreement. Accumulated Other Comprehensive Income (Loss) Components of accumulated other comprehensive income (loss) were as follows for the years ended December 31: 2018 2017 2016 (In thousands) Unrealized appreciation (depreciation) on securities, before tax $ (738) $ 102 $ — Tax benefit (expense) (1) 181 (39) — Unrealized appreciation (depreciation) on securities, net of tax $ (557) $ 63 $ — _______________________ 1. In 2018, due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%. Changes in accumulated other comprehensive income (loss) by component, net of tax, for the years ended December 31 are as follows: Net Gains on Equity Securities 2018 2017 2016 (In thousands) Balance at December 31: $ 63 $ — $ — Adjustment due to ASU 2018-02 (1) 13 — — Balance at January 1: 76 — — Unrealized appreciation (depreciation) before reclassifications (1) (557) 63 — Amounts reclassified from accumulated other comprehensive income — — — Net current-period other comprehensive income (loss) (557) 63 — Balance at December 31: $ (481) $ 63 $ — _______________________ 1. In 2018, due to the implementation of

Industry Segment Information

Industry Segment Information	12 Months Ended
	Dec. 31, 2018
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: Year Ended December 31, 2018 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: (1) Oil and natural gas $ 423,059 $ — $ — $ — $ — $ 423,059 Contract drilling — 218,982 — — (22,490) 196,492 Gas gathering and processing — — 312,417 — (88,687) 223,730 Total revenues 423,059 218,982 312,417 — (111,177) 843,281 Expenses: Operating costs: Oil and natural gas 136,870 — — — (5,195) 131,675 Contract drilling — 150,834 — — (19,449) 131,385 Gas gathering and processing — — 251,328 — (83,492) 167,836 Total operating costs 136,870 150,834 251,328 — (108,136) 430,896 Depreciation, depletion, and amortization 133,584 57,508 44,834 7,679 — 243,605 Impairments ( 2 ) — 147,884 — — — 147,884 Total expenses 270,454 356,226 296,162 7,679 (108,136) 822,385 General and administrative — — — 38,707 — 38,707 Gain on disposition of assets (139) (425) (110) (30) — (704) Income (loss) from operations 152,744 (136,819) 16,365 (46,356) (3,041) (17,107) Loss on derivatives — — — (3,184) — (3,184) Interest expense, net — — (1,214) (32,280) — (33,494) Other — — — 22 — 22 Income (loss) before income taxes $ 152,744 $ (136,819) $ 15,151 $ (81,798) $ (3,041) $ (53,763) Identifiable assets: Oil and natural gas ( 3 ) $ 1,357,779 $ — $ — $ — $ (6,949) $ 1,350,830 Contract drilling — 806,696 — — (85) 806,611 Gas gathering and processing — — 466,851 — (5,023) 461,828 Total identifiable assets ( 4 ) 1,357,779 806,696 466,851 — (12,057) 2,619,269 Corporate land and building — — — 55,505 — 55,505 Other corporate assets ( 5 ) — — — 25,566 (2,287) 23,279 Total assets $ 1,357,779 $ 806,696 $ 466,851 $ 81,071 $ (14,344) $ 2,698,053 Capital expenditures: $ 367,335 $ 75,510 $ 44,810 $ 1,125 $ — $ 488,780 _______________________ 1. The revenues for oil and na tural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. Impairment for contract drilling equipment includes a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment. 3. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 4. Identifiable assets are those used in Unit’s operations in each industry segment. 5. Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. Year Ended December 31, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 357,744 $ — $ — $ — $ — $ 357,744 Contract drilling — 188,172 — — (13,452) 174,720 Gas gathering and processing — — 277,049 — (69,873) 207,176 Total revenues 357,744 188,172 277,049 — (83,325) 739,640 Expenses: Operating costs: Oil and natural gas 135,532 — — — (4,743) 130,789 Contract drilling — 134,432 — — (11,832) 122,600 Gas gathering and processing — — 220,613 — (65,130) 155,483 Total operating costs 135,532 134,432 220,613 — (81,705) 408,872 Depreciation, depletion and amortization 101,911 56,370 43,499 7,477 — 209,257 Total expenses 237,443 190,802 264,112 7,477 (81,705) 618,129 General and administrative — — — 38,087 — 38,087 (Gain) loss on disposition of assets (228) 776 (25) (850) — (327) Income (loss) from operations 120,529 (3,406) 12,962 (44,714) (1,620) 83,751 Gain on derivatives — — — 14,732 — 14,732 Interest expense, net — — — (38,334) — (38,334) Other — — — 21 — 21 Income (loss) before income taxes $ 120,529 $ (3,406) $ 12,962 $ (68,295) $ (1,620) $ 60,170 Identifiable assets: Oil and natural gas ( 1 ) $ 1,134,080 $ — $ — $ — $ (6,180) $ 1,127,900 Contract drilling — 933,063 — — — 933,063 Gas gathering and processing — — 439,369 — (798) 438,571 Total identifiable assets ( 2 ) 1,134,080 933,063 439,369 — (6,978) 2,499,534 Corporate land and building — — — 56,854 — 56,854 Other corporate assets ( 3 ) — — — 25,064 — 25,064 Total assets $ 1,134,080 $ 933,063 $ 439,369 $ 81,918 $ (6,978) $ 2,581,452 Capital expenditures: $ 270,443 $ 36,148 $ 22,168 $ 3,521 $ — $ 332,280 _______________________ 1. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 2. Identifiable assets are those used in Unit’s operations in each industry segment. 3. Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. Year Ended December 31, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 294,221 $ — $ — $ — $ — $ 294,221 Contract drilling — 122,086 — — — 122,086 Gas gathering and processing — — 237,785 — (51,915) 185,870 Total revenues 294,221 122,086 237,785 — (51,915) 602,177 Expenses: Operating costs: Oil and natural gas 126,739 — — — (6,555) 120,184 Contract drilling — 88,154 — — — 88,154 Gas gathering and processing — — 182,969 — (45,360) 137,609 Total operating costs 126,739 88,154 182,969 — (51,915) 345,947 Depreciation, depletion and amortization 113,811 46,992 45,715 1,835 — 208,353 Impairments (1) 161,563 — — — — 161,563 Total expenses 402,113 135,146 228,684 1,835 (51,915) 715,863 General and administrative — — — 33,337 — 33,337 (Gain) loss on disposition of assets 324 (3,184) 302 18 — (2,540) Income (loss) from operations (108,216) (9,876) 8,799 (35,190) — (144,483) Gain on derivatives — — — (22,813) — (22,813) Interest expense, net — — — (39,829) — (39,829) Other — — — 307 — 307 Income (loss) before income taxes $ (108,216) $ (9,876) $ 8,799 $ (97,525) $ — $ (206,818) Identifiable assets: Oil and natural gas ( 2 ) $ 970,238 $ — $ — $ — $ (5,079) $ 965,159 Contract drilling — 941,676 — — — 941,676 Gas gathering and processing — — 462,330 — (730) 461,600 Total identifiable assets ( 3 ) 970,238 941,676 462,330 — (5,809) 2,368,435 Corporate land and building — — — 58,188 — 58,188 Other corporate assets ( 4 ) — — — 52,680 — 52,680 Total assets $ 970,238 $ 941,676 $ 462,330 $ 110,868 $ (5,809) $ 2,479,303 Capital expenditures: $ 89,562 $ 19,134 $ 16,796 $ 16,663 $ — $ 142,155 _______________________ 1. We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax). 2. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 3. Identifiable assets are those used in Unit’s operations in each industry segment. 4. Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.

Selected Quarterly Financial In

Selected Quarterly Financial Information	12 Months Ended
	Dec. 31, 2018
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) 2017 Revenues $ 175,724 $ 170,581 $ 188,488 $ 204,847 Gross income (1) $ 32,657 $ 24,462 $ 27,181 $ 37,211 Net income attributable to Unit Corporation $ 15,929 $ 9,059 $ 3,705 $ 89,155 Net income attributable to Unit Corporation per common share: Basic $ 0.32 $ 0.18 $ 0.07 $ 1.74 Diluted (2) $ 0.31 $ 0.17 $ 0.07 $ 1.71 2018 Revenues $ 205,132 $ 203,303 $ 220,058 $ 214,788 Gross income (loss) (1) $ 38,833 $ 40,915 $ 49,216 $ (108,068) Net income attributable to Unit Corporation $ 7,865 $ 5,788 $ 18,899 $ (77,840) Net income (loss) attributable to Unit Corporation per common share: Basic $ 0.15 $ 0.11 $ 0.36 $ (1.49) Diluted $ 0.15 $ 0.11 $ 0.36 $ (1.49) _________________________ 1. Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss). 2. The earnings per share for the year's four quarters does not equal annual income per share.

Supplemental Condensed Consolid

Supplemental Condensed Consolidated Financial Information	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Supplemental Condensed Consolidating Financial Information	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION We have no significant assets or operations other than our investments in our subsidiaries. Our wholly owned subsidiaries are the guarantors of our Notes. On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior and that company and its subsidiaries are no longer guarantors of the Notes. Instead of providing separate financial statements for each subsidiary issuer and guarantor, we have included the accompanying unaudited condensed consolidating financial statements based on Rule 3-10 of the SEC's Regulation S-X. For purposes of the following footnote: • we are referred to as "Parent", • the direct subsidiaries are 100% owned by the Parent and the guarantee is full and unconditional and joint and several and referred to as "Combined Guarantor Subsidiaries", and • Superior and its subsidiaries and the Operator are referred to as "Non-Guarantor Subsidiaries." The following unaudited supplemental condensed consolidating financial information reflects the Parent's separate accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods indicated. Condensed Consolidating Balance Sheets December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 403 $ 208 $ 5,841 $ — $ 6,452 Accounts receivable, net of allowance for doubtful accounts of $2,531 (Guarantor of $1,326 and Parent of $1,205) 2,539 94,526 36,676 (14,344) 119,397 Materials and supplies — 473 — — 473 Current derivative asset 12,870 — — — 12,870 Current income tax receivable 243 1,811 — — 2,054 Assets held for sale — 22,511 — — 22,511 Prepaid expenses and other 5,103 3,560 2,693 — 11,356 Total current assets 21,158 123,089 45,210 (14,344) 175,113 Property and equipment: Oil and natural gas properties on the full cost method: Proved properties — 6,018,568 — — 6,018,568 Unproved properties not being amortized — 330,216 — — 330,216 Drilling equipment — 1,284,419 — — 1,284,419 Gas gathering and processing equipment — — 767,388 — 767,388 Saltwater disposal systems — 68,339 — — 68,339 Corporate land and building — 59,081 — — 59,081 Transportation equipment 9,273 17,165 3,086 — 29,524 Other 28,584 28,923 — — 57,507 37,857 7,806,711 770,474 — 8,615,042 Less accumulated depreciation, depletion, amortization, and impairment 27,504 5,790,481 364,741 — 6,182,726 Net property and equipment 10,353 2,016,230 405,733 — 2,432,316 Intercompany receivable 950,916 — — (950,916) — Goodwill — 62,808 — — 62,808 Investments 1,160,444 1,500 — (1,160,444) 1,500 Other assets 5,115 5,293 15,908 — 26,316 Total assets $ 2,147,986 $ 2,208,920 $ 466,851 $ (2,125,704) $ 2,698,053 December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 8,697 $ 122,610 $ 32,214 $ (13,576) $ 149,945 Accrued liabilities 28,230 16,409 5,493 (468) 49,664 Current portion of other long-term liabilities 812 6,563 6,875 — 14,250 Total current liabilities 37,739 145,582 44,582 (14,044) 213,859 Intercompany debt — 948,707 2,209 (950,916) — Bonds payable less debt issuance costs 644,475 — — — 644,475 Non-current derivative liabilities 293 — — — 293 Other long-term liabilities 13,134 73,713 14,687 (300) 101,234 Deferred income taxes 60,983 83,765 — — 144,748 Shareholders’ equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued — — — — — Common stock, $.20 par value, 175,000,000 shares authorized, 54,055,600 shares issued 10,414 — — — 10,414 Capital in excess of par value 628,108 45,921 197,042 (242,963) 628,108 Contributions from Unit — — 792 (792) — Accumulated other comprehensive loss — (481) — — (481) Retained earnings 752,840 911,713 4,976 (916,689) 752,840 Total shareholders’ equity attributable to Unit Corporation 1,391,362 957,153 202,810 (1,160,444) 1,390,881 Non-controlling interests in consolidated subsidiaries — — 202,563 — 202,563 Total shareholders' equity 1,391,362 957,153 405,373 (1,160,444) 1,593,444 Total liabilities and shareholders’ equity $ 2,147,986 $ 2,208,920 $ 466,851 $ (2,125,704) $ 2,698,053 December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 510 $ 191 $ — $ — $ 701 Accounts receivable, net of allowance for doubtful accounts of $2,450 (Guarantor of $1,245 and Non-Guarantor of $1,205) 154 89,622 28,714 (6,978) 111,512 Materials and supplies — 505 — — 505 Current derivative asset 721 — — — 721 Current income tax receivable 61 0 — — — 61 Prepaid expenses and other 2,925 2,370 877 — 6,172 Total current assets 4,371 92,688 29,591 (6,978) 119,672 Property and equipment: Oil and natural gas properties on the full cost method: Proved properties — 5,712,813 — — 5,712,813 Unproved properties not being amortized — 296,764 — — 296,764 Drilling equipment — 1,593,611 — — 1,593,611 Gas gathering and processing equipment — — 726,236 — 726,236 Saltwater disposal systems — 62,618 — — 62,618 Corporate land and building — 59,080 — — 59,080 Transportation equipment 9,270 17,423 2,938 — 29,631 Other 28,039 25,400 — — 53,439 37,309 7,767,709 729,174 — 8,534,192 Less accumulated depreciation, depletion, amortization, and impairment 21,268 5,807,757 322,425 — 6,151,450 Net property and equipment 16,041 1,959,952 406,749 — 2,382,742 Intercompany receivable 1,155,725 — — (1,155,725) — Goodwill — 62,808 — — 62,808 Investments 1,044,709 1,500 — (1,044,709) 1,500 Other assets 5,373 6,328 3,029 — 14,730 Total assets $ 2,226,219 $ 2,123,276 $ 439,369 $ (2,207,412) $ 2,581,452 December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 13,124 $ 87,514 $ 18,988 $ (6,978) $ 112,648 Accrued liabilities 26,165 19,134 3,224 — 48,523 Current derivative liability 7,763 — — — 7,763 Current portion of other long-term liabilities 657 8,501 3,844 — 13,002 Total current liabilities 47,709 115,149 26,056 (6,978) 181,936 Intercompany debt — 870,582 285,143 (1,155,725) — Long-term debt 178,000 — — — 178,000 Bonds payable less debt issuance costs 642,276 — — — 642,276 Other long-term liabilities 11,257 77,566 11,380 — 100,203 Deferred income taxes 1,480 85,443 46,554 — 133,477 Shareholders’ equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued — — — — — Common stock, $.20 par value, 175,000,000 shares authorized, 52,880,134 shares issued 10,280 — — — 10,280 Capital in excess of par value 535,815 45,921 15,549 (61,470) 535,815 Accumulated other comprehensive income — 63 — — 63 Retained earnings 799,402 928,552 54,687 (983,239) 799,402 Total shareholders’ equity attributable to Unit Corporation 1,345,497 974,536 70,236 (1,044,709) 1,345,560 Non-controlling interests in consolidated subsidiaries — — — — — Total shareholders' equity 1,345,497 974,536 70,236 (1,044,709) 1,345,560 Total liabilities and shareholders’ equity $ 2,226,219 $ 2,123,276 $ 439,369 $ (2,207,412) $ 2,581,452 Condensed Consolidating Statements of Operations Year Ended December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 642,041 $ 312,417 $ (111,177) $ 843,281 Expenses: Operating costs — 287,704 251,328 (108,136) 430,896 Depreciation, depletion, and amortization 7,679 191,092 44,834 — 243,605 Impairments — 147,884 — — 147,884 General and administrative — 36,083 2,624 — 38,707 Gain on disposition of assets (30) (564) (110) — (704) Total operating expenses 7,649 662,199 298,676 (108,136) 860,388 Income (loss) from operations (7,649) (20,158) 13,741 (3,041) (17,107) Interest, net (32,280) — (1,214) — (33,494) Loss on derivatives (3,184) — — — (3,184) Other 22 — — — 22 Income (loss) before income taxes (43,091) (20,158) 12,527 (3,041) (53,763) Income tax expense (benefit) (12,707) (3,319) 2,030 — (13,996) Equity in net earnings from investment in subsidiaries, net of taxes (14,904) — — 14,904 — Net loss (45,288) (16,839) 10,497 11,863 (39,767) Less: net income attributable to non-controlling interest — — 5,521 — 5,521 Net loss attributable to Unit Corporation $ (45,288) $ (16,839) $ 4,976 $ 11,863 $ (45,288) Year Ended December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 545,916 $ 277,049 $ (83,325) $ 739,640 Expenses: Operating costs — 269,964 220,613 (81,705) 408,872 Depreciation, depletion, and amortization 7,477 158,281 43,499 — 209,257 General and administrative — 29,440 8,647 — 38,087 (Gain) loss on disposition of assets (850) 548 (25) — (327) Total operating expenses 6,627 458,233 272,734 (81,705) 655,889 Income (loss) from operations (6,627) 87,683 4,315 (1,620) 83,751 Interest, net (37,645) — (689) — (38,334) Gain on derivatives 14,732 — — — 14,732 Other 21 — — — 21 Income (loss) before income taxes (29,519) 87,683 3,626 (1,620) 60,170 Income tax benefit (12,599) (20,881) (24,198) — (57,678) Equity in net earnings from investment in subsidiaries, net of taxes 134,768 — — (134,768) — Net income 117,848 108,564 27,824 (136,388) 117,848 Less: net income attributable to non-controlling interest — — — — — Net income attributable to Unit Corporation $ 117,848 $ 108,564 $ 27,824 $ (136,388) $ 117,848 Year Ended December 31, 2016 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 416,307 $ 237,785 $ (51,915) $ 602,177 Expenses: Operating costs — 214,892 182,970 (51,915) 345,947 Depreciation, depletion, and amortization 1,835 160,803 45,715 — 208,353 Impairments — 161,563 — — 161,563 General and administrative — 26,158 7,179 — 33,337 (Gain) loss on disposition of assets 18 (2,860) 302 — (2,540) Total operating expenses 1,853 560,556 236,166 (51,915) 746,660 Income (loss) from operations (1,853) (144,249) 1,619 — (144,483) Interest, net (38,995) — (834) — (39,829) Loss on derivatives (22,813) — — — (22,813) Other — 307 — — 307 Income (loss) before income taxes (63,661) (143,942) 785 — (206,818) Income tax expense (benefit) (24,031) (48,654) 1,491 — (71,194) Equity in net earnings from investment in subsidiaries, net of taxes (95,994) — — 95,994 — Net loss (135,624) (95,288) (706) 95,994 (135,624) Less: net income attributable to non-controlling interest — — — — — Net loss attributable to Unit Corporation $ (135,624) $ (95,288) $ (706) $ 95,994 $ (135,624) Condensed Consolidating Statements of Comprehensive Income (Loss) Year Ended December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (45,288) $ (16,839) $ 10,497 $ 11,863 $ (39,767) Other comprehensive income, net of taxes: Unrealized loss on securities, net of tax (($181)) — (557) — — (557) Comprehensive loss (45,288) (17,396) 10,497 11,863 (40,324) Less: Comprehensive income attributable to non-controlling interests — — 5,521 — 5,521 Comprehensive loss attributable to Unit Corporation $ (45,288) $ (17,396) $ 4,976 $ 11,863 $ (45,845) Year Ended December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net income $ 117,848 $ 108,564 $ 27,824 $ (136,388) $ 117,848 Other comprehensive income, net of taxes: Unrealized gain on securities, net of tax ($39) — 63 — — 63 Comprehensive income 117,848 108,627 27,824 (136,388) 117,911 Less: Comprehensive income attributable to non-controlling interests — — — — — Comprehensive income attributable to Unit Corporation $ 117,848 $ 108,627 $ 27,824 $ (136,388) $ 117,911 Year Ended December 31, 2016 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (135,624) $ (95,288) $ (706) $ 95,994 $ (135,624) Other comprehensive income, net of taxes: Unrealized loss on securities, net of tax ($0) — — — — — Comprehensive loss (135,624) (95,288) (706) 95,994 (135,624) Less: Comprehensive income attributable to non-controlling interests — — — — — Comprehensive loss attributable to Unit Corporation $ (135,624) $ (95,288) $ (706) $ 95,994 $ (135,624) Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (120,317) $ 327,075 $ 12,129 $ 128,872 $ 347,759 INVESTING ACTIVITIES: Capital expenditures 236 (400,990) (45,528) — (446,282) Producing properties and other acquisitions — (29,970) — — (29,970) Proceeds from disposition of property and equipment 30 25,777 103 — 25,910 Net cash provided by (used in) investing activities 266 (405,183) (45,425) — (450,342) FINANCING ACTIVITIES: Borrowings under credit agreements 97,100 — 2,000 — 99,100 Payments under credit agreements (275,100) — (2,000) — (277,100) Intercompany borrowings (advances), net 204,809 78,125 (154,854) (128,080) — Payments on capitalized leases — — (3,843) — (3,843) Proceeds from investments of non-controlling interest 102,958 — 197,042 — 300,000 Contributions from Unit — — 792 (792) — Transaction costs associated with sale of non-controlling interest (2,503) — — — (2,503) Book overdrafts (7,320) — — — (7,320) Net cash provided by financing activities 119,944 78,125 39,137 (128,872) 108,334 Net increase in cash and cash equivalents (107) 17 5,841 — 5,751 Cash and cash equivalents, beginning of period 510 191 — — 701 Cash and cash equivalents, end of period $ 403 $ 208 $ 5,841 $ — $ 6,452 Year Ended December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (1,683) $ 224,446 $ 43,193 $ — $ 265,956 INVESTING ACTIVITIES: Capital expenditures (3,594) (233,254) (18,705) — (255,553) Producing properties and other acquisitions — (58,026) — — (58,026) Proceeds from disposition of property and equipment 964 20,674 75 — 21,713 Other — (1,500) — — (1,500) Net cash used in investing activities (2,630) (272,106) (18,630) — (293,366) FINANCING ACTIVITIES: Borrowings under credit agreement 343,900 — — — 343,900 Payments under credit agreement (326,700) — — — (326,700) Intercompany borrowings (advances), net (26,606) 47,475 (20,869) — — Payments on capitalized leases — — (3,694) — (3,694) Proceeds from common stock issued, net of issue costs 18,623 — — — 18,623 Book overdrafts (4,911) — — — (4,911) Net cash provided by (used in) financing activities 4,306 47,475 (24,563) — 27,218 Net increase in cash and cash equivalents (7) (185) — — (192) Cash and cash equivalents, beginning of period 517 376 — — 893 Cash and cash equivalents, end of period $ 510 $ 191 $ — $ — $ 701 Year Ended December 31, 2016 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by operating activities $ 1,781 $ 197,132 $ 41,217 $ — $ 240,130 INVESTING ACTIVITIES: Capital expenditures (3,927) (158,983) (23,239) — (186,149) Producing properties and other acquisitions — (564) — — (564) Proceeds from disposition of property and equipment 13 74,694 116 — 74,823 Other 750 — 169 — 919 Net cash provided by (used in) investing activities (3,164) (84,853) (22,954) — (110,971) FINANCING ACTIVITIES: Borrowings under credit agreement 251,398 — — — 251,398 Payments under credit agreement (371,600) — — — (371,600) Intercompany borrowings (advances), net 126,797 (112,228) (14,569) — — Payments on capitalized leases — — (3,694) — (3,694) Tax expense from stock compensation (376) — — — (376) Book overdrafts (4,829) — — — (4,829) Net cash used in financing activities 1,390 (112,228) (18,263) — (129,101) Net increase in cash and cash equivalents 7 51 — — 58 Cash and cash equivalents, beginning of period 510 325 — — 835 Cash and cash equivalents, end of period $ 517 $ 376 $ — $ — $ 893

Supplemental Oil And Gas Disclo

Supplemental Oil And Gas Disclosures	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 2016 (In thousands) Capitalized costs: Proved properties $ 6,018,568 $ 5,712,813 $ 5,446,305 Unproved properties 330,216 296,764 314,867 6,348,784 6,009,577 5,761,172 Accumulated depreciation, depletion, amortization, and impairment (5,124,257) (4,996,696) (4,900,304) Net capitalized costs $ 1,224,527 $ 1,012,881 $ 860,868 Cost incurred: Unproved properties acquired $ 57,430 $ 47,029 $ 21,675 Proved properties acquired 15,158 47,638 564 Exploration 15,907 14,811 17,325 Development 280,692 160,941 80,582 Asset retirement obligation (7,629) (3,613) (30,906) Total costs incurred $ 361,558 $ 266,806 $ 89,240 The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2018, by the year in which such costs were incurred: 2018 2017 2016 2015 and Prior Total (In thousands) Unproved properties acquired and wells in progress $ 60,372 $ 46,986 $ 21,947 $ 200,911 $ 330,216 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: 2018 2017 2016 (In thousands) Revenues $ 429,119 $ 347,285 $ 282,742 Production costs (131,328) (113,344) (103,568) Depreciation, depletion, amortization, and impairment (132,923) (101,326) (274,155) 164,868 132,615 (94,981) Income tax (expense) benefit (42,915) (52,078) 32,696 Results of operations for producing activities (excluding corporate overhead and financing costs) $ 121,953 $ 80,537 $ (62,285) 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 Total MBoe (In thousands) 2016 Proved developed and undeveloped reserves: Beginning of year 16,735 37,687 484,868 135,233 Revision of previous estimates (1) (549) (2,473) (31,670) (8,300) Extensions and discoveries 1,816 1,588 13,720 5,690 Infill reserves in existing proved fields 663 2,724 24,704 7,504 Purchases of minerals in place 114 43 630 262 Production (2,974) (5,014) (55,735) (17,277) Sales (109) (73) (30,938) (5,338) End of year 15,696 34,482 405,579 117,774 Proved developed reserves: Beginning of year 14,679 31,218 416,395 115,296 End of year 12,724 28,502 347,121 99,079 Proved undeveloped reserves: Beginning of year 2,056 6,469 68,473 19,937 End of year 2,972 5,980 58,458 18,695 2017 Proved developed and undeveloped reserves: Beginning of year 15,696 34,482 405,579 117,774 Revision of previous estimates (1) 730 4,325 38,330 11,444 Extensions and discoveries 2,235 4,520 49,321 14,975 Infill reserves in existing proved fields 1,632 5,779 52,270 16,123 Purchases of minerals in place 2,019 1,197 15,313 5,768 Production (2,715) (4,737) (51,260) (15,996) Sales (84) (80) (903) (314) End of year 19,513 45,486 508,650 149,774 Proved developed reserves: Beginning of year 12,724 28,502 347,121 99,079 End of year 14,862 33,358 388,446 112,961 Proved undeveloped reserves: Beginning of year 2,972 5,980 58,458 18,695 End of year 4,651 12,128 120,204 36,813 2018 Proved developed and undeveloped reserves: Beginning of year 19,513 45,486 508,650 149,774 Revision of previous estimates 180 (1,368) (17,859) (4,165) Extensions and discoveries 3,250 5,149 75,806 21,033 Infill reserves in existing proved fields 1,898 2,795 23,778 8,656 Purchases of minerals in place 701 856 6,897 2,707 Production (2,874) (4,925) (55,627) (17,070) Sales (110) (197) (5,682) (1,254) End of year 22,558 47,796 535,963 159,681 Proved developed reserves: Beginning of year 14,862 33,358 388,446 112,961 End of year 15,192 33,515 377,216 111,576 Proved undeveloped reserves: Beginning of year 4,651 12,128 120,204 36,813 End of year 7,366 14,281 158,747 48,105 _________________________ 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 adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows: 2018 2017 2016 (In thousands) Future cash flows $ 3,980,369 $ 3,347,396 $ 2,030,925 Future production costs (1,479,744) (1,308,244) (861,625) Future development costs (442,984) (369,560) (173,446) Future income tax expenses (307,916) (234,152) (141,752) Future net cash flows 1,749,725 1,435,440 854,102 10% annual discount for estimated timing of cash flows (766,047) (628,270) (335,892) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 983,678 $ 807,170 $ 518,210 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: 2018 2017 2016 (In thousands) Sales and transfers of oil and natural gas produced, net of production costs $ (297,791) $ (239,953) $ (173,920) Net changes in prices and production costs 120,062 236,126 (94,026) Revisions in quantity estimates and changes in production timing (33,282) 87,239 (51,979) Extensions, discoveries, and improved recovery, less related costs 234,172 102,965 84,738 Changes in estimated future development costs 19,535 (5,194) 70,976 Previously estimated cost incurred during the period 63,557 36,044 16,602 Purchases of minerals in place 23,416 51,686 2,652 Sales of minerals in place (5,004) (1,447) (17,248) Accretion of discount 89,753 57,517 69,069 Net change in income taxes (31,674) (33,389) 44,241 Other—net (6,236) (2,634) (22,381) Net change 176,508 288,960 (71,276) Beginning of year 807,170 518,210 589,486 End of year $ 983,678 $ 807,170 $ 518,210 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 neither 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, 2018, future cash flows were computed by applying the unescalated 12-month average prices of $65.56 per barrel for oil, $37.68 per barrel for NGLs, and $3.10 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, 2018
Valuation and Qualifying Accounts [Abstract]
Valuation And Qualifying Accounts And Reserves	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, 2018 $ 2,450 $ 81 $ — $ 2,531 Year ended December 31, 2017 $ 3,773 $ 348 $ (1,671) $ 2,450 Year ended December 31, 2016 $ 5,199 $ 785 $ (2,211) $ 3,773

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2018
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. We consolidate the activities of Superior, a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentations. 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. Typically, this type of contract can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2018, all of our contracts were daywork contracts of which 24 were multi-well and had durations which ranged from six months to three years, 17 of which expire in 2019 and seven expiring in 2020 and beyond. 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, 2018 and 2017, book overdrafts were $5.1 million and $12.4 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: 2018 2017 2016 Oil and Natural Gas: CVR Refining, LP 14 % 2 % — % Valero Energy Corporation 10 % 9 % 11 % Energy Transfer Partners (formerly Sunoco Logistics Partners) 3 % 10 % 24 % Drilling: QEP Resources, Inc. 16 % 26 % 28 % Slawson Exploration Company, Inc 10 % 6 % 3 % Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) 3 % 7 % 18 % Mid-Stream: ONEOK, Inc. 45 % 36 % 30 % Range Resources Corporation 7 % 9 % 10 % Koch Energy Services, LLC 6 % 8 % 11 % Tenaska Resources, LLC 4 % 6 % 10 % We had a concentration of cash of $11.0 million and $11.4 million at December 31, 2018 and 2017, 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, 2018 and determined there was no material risk at that time. At December 31, 2018, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: 12/31/2018 (In millions) Bank of Montreal $ 9.9 Bank of America Merrill Lynch 2.7 Total net assets $ 12.6
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, except when idle for greater than 48 months, then it will be depreciated at the full active rate. 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 on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. 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 cause materially different carrying values of our assets. On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. In December 2018, our Board of Directors approved a plan to sell 41 drilling rigs (29 mechanical drilling rigs and 12 SCR diesel-electric drilling rigs) and other equipment. This plan satisfies the criteria of assets held for sale under ASC 360-10-45-9. Over the last five years, only six of our drilling rigs in the fleet have not been utilized. We made a strategic decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs (good candidates for modification) and sell the other drilling rigs that we now choose not to market. We estimated the fair value of the 41 drilling rigs we will no longer market based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax), the fair value of the assets held for sale at December 31, 2018 is $22.5 million. When p roperty 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. Our contract drilling segment had no impairments in either 2016 or 2017. 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. 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 2018, 2017, and 2016, interest of approximately $16.5 million, $15.9 million, and $15.3 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 impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, 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, 2018, 2017, or 2016. There were no additions to goodwill in 2018, 2017, or 2016. Based on our impairment test performed as of December 31, 2018, the fair value of our drilling segment exceeded its carrying value by 37%. While the goodwill of this reporting unit is not currently impaired, there could be an impairment in the future as a result of changes in certain assumptions. For example, the fair value could be adversely affected and result in an impairment of goodwill if we do not realize the anticipated drilling rig utilization of the anticipated drilling rig dayrates, or if the estimated cash flows are discounted at a higher risk-adjusted rate or market multiples decrease. Goodwill of $0.4 million is deductible for tax purposes.
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 $15.9 million, $14.8 million, and $15.4 million were capitalized in 2018, 2017, and 2016, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $7.50, $6.00, and $6.24 per Boe in 2018, 2017, and 2016, respectively. The calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. Our unproved properties and wells in progress totaling $330.2 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 $7.6 million and $10.5 million in 2016 and 2017, respectively of costs being added to the total of our capitalized costs being amortized. We did not have any in 2018. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million net of tax) due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We had no non-cash ceiling test write-downs during 2017 or 2018.
ARO	We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.
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. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. 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 with the exception of normal purchase and normal sales which are expected to result in physical delivery. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.We document our risk management strategy and do not engage in derivative transactions for speculative purposes.
Limited Partnerships	Unit Petroleum Company is a general partner in 13 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	During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. The change in tax law required the Company to remeasure existing net deferred tax liabilities using the lower rate in the period of enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); 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.
Natural Gas Balancing	We account for revenue transactions under ASC 606 for recording natural gas sales , which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2018 balancing position to be approximately 3.8 Bcf on under-produced properties and approximately 3.7 Bcf on over-produced properties. We have recorded a receivable of $2.9 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.3 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 SARs. The value of our restricted stock grants is based on the closing stock price on the date of the grants.
New Accounting Standards	Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our financial statements. Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands Topic 718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This amendment will not have a material impact on our financial statements. Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements. Leases. The FASB has issued several accounting standards updates and amendments related to leases in the past two years, which are codified within Topic 842. For public companies, these are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard requires lessees to recognize at the commencement date of a lease a lease liability, which represents the lessee's obligation to make lease payments arising from the lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Other recently issued amendments to Topic 842 have provided clarifying guidance regarding land easements, an additional modified retrospective transition method, and added several practical expedients to apply Topic 842 for both lessees and lessors. The standard will not apply to leases of mineral rights. We established an implementation team working through the provisions of the new guidance including a review of different types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes, internal control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the new guidance is substantially complete. We have made certain accounting policy decisions including that we plan to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. Our transition will utilize the modified retrospective approach to adopting the new standard, and will be applied at the beginning of the period adopted (January 1, 2019) in accordance with ASU 2018-11. We have elected the transition practical expedient, which allows us to not evaluate land easements that existed prior to January 1, 2019, and the optional transition method to record our immaterial adoption impact through a cumulative adjustment to equity. We expect for certain lessee asset classes to elect the practical expedient and not separate lease and nonlease components. For these asset classes, we will account for the agreements as a single lease component. We have determined that Unit Drilling Company lessor drilling rig contracts will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract. For both lessee and lessor practical expedients, we considered quantitative and qualitative factors when determining if an asset class qualified for the application of the practical expedient. The adoption of this guidance will result in the addition of right-of-use assets and corresponding lease obligations to the consolidated balance sheet and will not have a material impact on the Company’s results of operations or cash flows. Upon adoption, the Company expects to record operating lease right-of-use assets and the corresponding operating lease liabilities in the range of approximately $3.0 million to $4.5 million, representing the present value of future lease payments under operating leases. The Company is in the process of finalizing its catalog of existing lease contracts and implementing changes to its processes. There would be no impact to the Superior credit agreement debt covenants and an immaterial impact to the Unit credit agreement debt covenants as a result of adopting this standard. Adopted Standards As of January 1, 2018, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and we now use 24.5%. This change is reflected in our Consolidated Statements of Comprehensive Income and in Note 17 - Equity. Also, as of January 1, 2018, we adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606) and all later amendments that modified ASC 606. We elected to apply this standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect on adoption, which only affected our mid-stream segment, is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for certain demand fees. Our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605. The additional disclosures required by ASC 606 have been included in Note 3 – Revenue from Contracts with Customers. Our internal control framework did not materially change because of this standard, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard,

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 2016 Oil and Natural Gas: CVR Refining, LP 14 % 2 % — % Valero Energy Corporation 10 % 9 % 11 % Energy Transfer Partners (formerly Sunoco Logistics Partners) 3 % 10 % 24 % Drilling: QEP Resources, Inc. 16 % 26 % 28 % Slawson Exploration Company, Inc 10 % 6 % 3 % Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) 3 % 7 % 18 % Mid-Stream: ONEOK, Inc. 45 % 36 % 30 % Range Resources Corporation 7 % 9 % 10 % Koch Energy Services, LLC 6 % 8 % 11 % Tenaska Resources, LLC 4 % 6 % 10 %
Schedule of Fair Values of the Net Assets (Liabilities) [Table Text Block]	At December 31, 2018, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: 12/31/2018 (In millions) Bank of Montreal $ 9.9 Bank of America Merrill Lynch 2.7 Total net assets $ 12.6

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Adoption of ASC606 [Line Items]
Balance Sheet Impact of the Adoption of ASC606	This adjustment—related to the timing of revenue recognized on certain demand fees—impacted our Consolidated Balance Sheet (for the periods indicated) as follows: Balance at December 31, 2017 Adjustments due to ASC 606 Balance at January 1, (In thousands) Assets: Other assets $ 16,230 $ 10,798 $ 27,028 Liabilities and shareholders' equity: Current portion of other long-term liabilities 13,002 2,748 15,750 Other long-term liabilities 100,203 9,737 109,940 Deferred income taxes 133,477 (413) 133,064 Retained earnings 799,402 (1,274) 798,128 At December 31, 2018: As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606 (In thousands) Assets: Prepaid expenses and other $ 11,356 $ 285 $ 11,071 Other assets 27,816 12,879 14,937 Liabilities and shareholders' equity: Current portion of other long-term liabilities 14,250 2,874 11,376 Other long-term liabilities 101,234 7,007 94,227 Deferred income taxes 144,748 805 143,943 Retained earnings 752,840 2,478 750,362
Revenue, Remaining Performance Obligation	Included below is the additional fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract. Contract Remaining Term of Contract 2019 2020 2021 2022 Total Remaining Impact to Revenue Demand fee contracts 4 years $ 2,632 $ (3,781) $ (3,507) $ 1,374 $ (3,282)
Contract with Customer, Asset and Liability	For 2018, $5.0 million was recognized in revenue for these demand fees. December 31, 2018 January 1, Change (In thousands) Contract assets $ 13,164 $ 10,798 $ 2,366 Contract liabilities 9,881 12,485 (2,604) Contract assets (liabilities), net $ 3,283 $ (1,687) $ 4,970
Oil and Natural Gas
Adoption of ASC606 [Line Items]
Revenue Impact of the Adoption of ASC606	These tables summarize the impact of the adoption of ASC 606 on revenue and operating costs for the year ended December 31, 2018: As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606 (In thousands) Oil and natural gas revenues $ 423,059 $ (17,518) $ 440,577 Oil and natural gas operating costs 131,675 (17,518) 149,193 Gross profit $ 291,384 $ — $ 291,384
Mid-Stream
Adoption of ASC606 [Line Items]
Revenue Impact of the Adoption of ASC606	This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Consolidated Statement of Operations for 2018: As Reported Adjustments due to ASC 606 Amounts without the Adoption of ASC 606 (In thousands) Gas gathering and processing revenues $ 223,730 $ 4,970 $ 218,760 Deferred income tax benefit (10,865) 1,218 (12,083) Net income (loss) (39,767) 3,752 (43,519)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
EOG Acquisition
Business Acquisition [Line Items]
Fair Value of Acquired Assets and Liabilities	The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed. Final Adjusted Purchase Price Total consideration given $ 54,332 Final Adjusted Allocation of Purchase Price Oil and natural gas properties included in the full cost pool: Proved oil and natural gas properties $ 43,745 Undeveloped oil and natural gas properties 8,650 Total oil and natural gas properties included in the full cost pool (1) 52,395 Gas gathering equipment and other 2,340 Asset retirement obligation (403) Fair value of net assets acquired $ 54,332 _________________________ 2. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.
Excalibur Acquisition
Business Acquisition [Line Items]
Fair Value of Acquired Assets and Liabilities	The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed. Preliminary Purchase Price Total consideration given $ 29,633 Preliminary Allocation of Purchase Price Oil and natural gas properties included in the full cost pool: Proved oil and natural gas properties $ 14,546 Undeveloped oil and natural gas properties 15,502 Total oil and natural gas properties included in the full cost pool (1) 30,048 Asset retirement obligation (415) Fair value of net assets acquired $ 29,633 _________________________ 1. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates .

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2016: Basic loss attributable to Unit Corporation per common share $ (135,624) 50,029 $ (2.71) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss attributable to Unit Corporation per common share $ (135,624) 50,029 $ (2.71) For the year ended December 31, 2017: Basic earnings attributable to Unit Corporation per common share $ 117,848 51,113 $ 2.31 Effect of dilutive stock options — 635 (0.03) Diluted income attributable to Unit Corporation per common share $ 117,848 51,748 $ 2.28 For the year ended December 31, 2018: Basic loss attributable to Unit Corporation per common share (45,288) 51,981 $ (0.87) Effect of dilutive restricted stock — — — Diluted loss attributable to Unit Corporation per common share $ (45,288) 51,981 $ (0.87)
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: 2018 2017 2016 Options and SARs 66,500 87,500 199,755 Average exercise price $ 44.42 $ 51.34 $ 48.79

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities [Abstract]
Accrued Liabilities [Table Text Block]	Accrued liabilities consisted of the following as of December 31: 2018 2017 (In thousands) Employee costs $ 22,056 $ 19,521 Lease operating expenses 12,756 11,819 Interest payable 6,635 6,745 Third-party credits 2,129 2,240 Taxes 1,378 3,404 Other 4,710 4,794 Total accrued liabilities $ 49,664 $ 48,523

Long-Term Debt And Other Long_2

Long-Term Debt And Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 (In thousands) Unit credit agreement with average interest rate of 3.4% at December 31, 2017 $ — $ 178,000 Superior credit agreement — — 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount $ 650,000 $ 828,000 Less: unamortized discount (1,623) (2,234) Less: debt issuance costs, net (3,902) (5,490) Total long-term debt $ 644,475 $ 820,276
Other Long Term Liabilities [Table Text Block]	Other long-term liabilities consisted of the following as of December 31: 2018 2017 (In thousands) ARO liability $ 64,208 $ 69,444 Workers’ compensation 12,738 13,340 Capital lease obligations 11,380 15,224 Contract liability 9,881 — Separation benefit plans 8,814 6,524 Deferred compensation plan 5,132 5,390 Gas balancing liability 3,331 3,283 115,484 113,205 Less current portion 14,250 13,002 Total other long-term liabilities $ 101,234 $ 100,203
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future payments required under the capital leases at December 31, 2018 are as follows: Amount Ending December 31, (In thousands) 2019 $ 6,168 2020 6,168 2021 3,768 Total future payments 16,104 Less payments related to: Maintenance 4,089 Interest 635 Present value of future minimum payments $ 11,380

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 (In thousands) ARO liability, January 1: $ 69,444 $ 70,170 Accretion of discount 2,393 2,886 Liability incurred 2,632 1,948 Liability settled (4,493) (2,694) Liability sold (281) (1,735) Revision of estimates (1) (5,487) (1,131) ARO liability, December 31: 64,208 69,444 Less current portion 1,437 1,726 Total long-term ARO liability $ 62,771 $ 67,718 _________________________ 1. Plugging liability estimates were revised in both 201

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 2016 (In thousands) Income tax expense (benefit) computed by applying the statutory rate $ (11,290) $ 21,059 $ (72,386) State income tax expense (benefit), net of federal benefit (1,882) 1,655 (5,687) Deferred tax liability revaluation (1) — (81,307) — Restricted stock shortfall 424 1,867 5,465 Non-controlling interest in Superior (1,138) — — Statutory depletion and other (110) (952) 1,414 Income tax benefit $ (13,996) $ (57,678) $ (71,194) __________________________ 1. In 2017, the revaluation from the Tax Act.
Schedule Of Total Provision For Income Taxes [Table Text Block]	For the periods indicated, the total provision for income taxes consisted of the following: 2018 2017 2016 (In thousands) Current taxes: Federal $ (1,835) $ — $ — State (1,296) 5 15 (3,131) 5 15 Deferred taxes: Federal (8,741) (62,788) (62,923) State (2,124) 5,105 (8,286) (10,865) (57,683) (71,209) Total provision $ (13,996) $ (57,678) $ (71,194)
Schedule Of Deferred Tax Assets And Liabilities [Table Text Block]	Deferred tax assets and liabilities are comprised of the following at December 31: 2018 2017 (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 27,953 $ 32,242 Net operating loss carryforward 152,112 153,746 Alternative minimum tax and research and development tax credit carryforward 3,574 5,409 183,639 191,397 Deferred tax liability: Depreciation, depletion, amortization, and impairment (291,542) (324,874) Investment in Superior (36,845) — Net deferred tax liability (144,748) (133,477) Current deferred tax asset — — Non-current—deferred tax liability $ (144,748) $ (133,477)

Transactions With Related Par_2

Transactions With Related Parties (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 2016 (In thousands) Well supervision and other fees $ 158 $ 172 $ 254 General and administrative expense reimbursement — — 6

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 2015 (In millions) Recognized stock compensation expense $ 17.8 $ 13.3 $ 9.6 Capitalized stock compensation cost for our oil and natural gas properties 2.1 1.8 2.1 Tax benefit on stock based compensation 4.4 5.0 3.6
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, 2016 131,770 $ 46.60 Granted — — Exercised — — Forfeited (40,515) 51.76 Outstanding at December 31, 2016 91,255 44.31 Granted — — Exercised — — Forfeited (91,255) 44.31 Outstanding at December 31, 2017 — $ —
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, 2016 936,662 277,160 1,213,822 $ 41.29 Granted 494,078 152,373 646,451 5.62 Vested (425,195) — (425,195) 43.47 Forfeited (75,808) (57,405) (133,213) 36.87 Nonvested at December 31, 2016 929,737 372,128 1,301,865 23.32 Granted 485,799 173,373 659,172 26.07 Vested (455,570) (62,119) (517,689) 29.87 Forfeited (44,408) (34,953) (79,361) 38.87 Nonvested at December 31, 2017 915,558 448,429 1,363,987 21.25 Granted 844,498 390,445 1,234,943 20.52 Vested (470,171) (209,643) (679,814) 24.30 Forfeited (21,002) (21,106) (42,108) 19.80 Nonvested at December 31, 2018 1,268,883 608,125 1,877,008 $ 19.70 Non-Employee Directors Number of Shares Weighted Average Price Nonvested at January 1, 2016 42,064 $ 41.83 Granted 90,000 12.02 Vested (20,248) 43.46 Forfeited — — Nonvested at December 31, 2016 111,816 $ 17.21 Granted 49,104 17.92 Vested (43,206) 21.24 Forfeited — — Nonvested at December 31, 2017 117,714 $ 16.03 Granted 44,312 19.86 Vested (54,981) 17.08 Forfeited — — Nonvested at December 31, 2018 107,045 $ 17.07
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, 2016 129,500 $ 54.15 Granted — — Exercised — — Forfeited (21,000) 62.40 Outstanding at December 31, 2016 108,500 52.56 Granted — — Exercised — — Forfeited (21,000) 57.63 Outstanding at December 31, 2017 87,500 51.34 Granted — — Exercised — — Forfeited (21,000) 73.26 Outstanding at December 31, 2018 66,500 $ 44.42
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 0.9 years $ 37.58 $53.81 - $73.26 28,000 2.3 years $ 53.81

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Non-designated Hedges Outstanding [Table Text Block]	At December 31, 2018, the following non-designated hedges were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Jan’19 – Mar'19 Natural gas – swap 50,000 MMBtu/day $3.440 IF – NYMEX (HH) Apr'19 – Dec'19 Natural gas – swap 40,000 MMBtu/day $2.900 IF – NYMEX (HH) Jan’19 – Dec'19 Natural gas – basis swap 20,000 MMBtu/day $(0.659) PEPL Jan’19 – Dec'19 Natural gas – basis swap 10,000 MMBtu/day $(0.625) NGPL MIDCON Jan’19 – Dec'19 Natural gas – basis swap 30,000 MMBtu/day $(0.265) NGPL TEXOK Jan’20 – Dec'20 Natural gas – basis swap 30,000 MMBtu/day $(0.275) NGPL TEXOK Jan’19 – Dec'19 Natural gas – collar 20,000 MMBtu/day $2.63 - $3.03 IF – NYMEX (HH) Jan'19 – Mar'19 Natural gas – three-way collar 30,000 MMBtu/day $3.17 - $2.92 - $4.32 IF – NYMEX (HH) Jan’19 – Dec'19 Crude oil – three-way collar 4,000 Bbl/day $61.25 - $51.25 - $72.93 WTI – NYMEX
Schedule Of Subsequent Non-designated Hedges [Table Text Block]	After December 31, 2018, the following non-designated hedges were entered into: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Apr'19 – Oct'19 Natural gas – swap 20,000 MMBtu/day $2.900 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 2018 2017 (In thousands) Commodity derivatives: Current Current derivative assets $ 12,870 $ 721 Long-term Non-current derivative assets — — Total derivative assets $ 12,870 $ 721 Derivative Liabilities Fair Value Balance Sheet Location 2018 2017 (In thousands) Commodity derivatives: Current Current derivative liabilities $ — $ 7,763 Long-term Non-current derivative liabilities 293 — Total derivative liabilities $ 293 $ 7,763
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 for the year ended December 31: Derivatives Instruments Location of Gain or (Loss) Recognized in Income on Derivative Amount of Gain or (Loss) Recognized in Income on Derivative 2018 2017 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (3,184) $ 14,732 Total $ (3,184) $ 14,732 _________________________ 1. Amount s settled during the periods are a loss of $22,803 and a gain of $173, respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Available-for-sale Securities [Table Text Block]	The following is a summary of available-for-sale securities: Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (In thousands) Equity Securities: December 31, 2018 $ 830 $ — $ 636 $ 194 December 31, 2017 $ 830 $ 102 $ — $ 932
Recurring Fair Value Measurements [Table Text Block]	The following tables set forth our recurring fair value measurements: December 31, 2018 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 3,225 $ 10,964 $ (1,319) $ 12,870 Liabilities (1,278) (334) 1,319 (293) $ 1,947 $ 10,630 $ — $ 12,577 December 31, 2017 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 2,137 $ 3,344 $ (4,760) $ 721 Liabilities (8,973) (3,550) 4,760 (7,763) $ (6,836) $ (206) $ — $ (7,042)
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, 2018 December 31, 2017 (In thousands) Beginning of period $ (206) $ (7,122) Total gains or losses: Included in earnings (1) 4,159 7,791 Settlements 6,677 (875) End of period $ 10,630 $ (206) Total gains for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period $ 10,836 $ 6,916 _________________________ 1. Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives.
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, 2018: Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil three-way collar 10,592 Discounted cash flow Forward commodity price curve $0.00 - $19.44 Natural gas collars (334) Discounted cash flow Forward commodity price curve $0.00 - $0.38 Natural gas three-way collar 372 Discounted cash flow Forward commodity price curve $0.00 - $0.43 _________________________ 1. The commodity contracts detailed in this category include non-exchange-traded crude and natural gas three-way collars and natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.

Variable Interest Entity Arra_2

Variable Interest Entity Arrangements (Tables)	12 Months Ended
	Dec. 31, 2018
Variable Interest Entity Arrangements [Abstract]
Schedule of Assets and Liabilities	The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows: December 31, (In thousands) Current assets: Cash and cash equivalents $ 5,841 Accounts receivable 33,207 Prepaid expenses and other 2,693 Total current assets 41,741 Property and equipment: Gas gathering and processing equipment 767,388 Transportation equipment 3,086 770,474 Less accumulated depreciation, depletion, amortization, and impairment 364,740 Net property and equipment 405,734 Other assets 15,907 Total assets $ 463,382 Current liabilities: Accounts payable $ 32,214 Accrued liabilities 3,688 Current portion of other long-term liabilities 6,875 Total current liabilities 42,777 Long-term debt less debt issuance costs — Other long-term liabilities 14,687 Total liabilities $ 57,464

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income [Table Text Block]	Components of accumulated other comprehensive income (loss) were as follows for the years ended December 31: 2018 2017 2016 (In thousands) Unrealized appreciation (depreciation) on securities, before tax $ (738) $ 102 $ — Tax benefit (expense) (1) 181 (39) — Unrealized appreciation (depreciation) on securities, net of tax $ (557) $ 63 $ — _______________________ 1. In 2018, due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Changes in accumulated other comprehensive income (loss) by component, net of tax, for the years ended December 31 are as follows: Net Gains on Equity Securities 2018 2017 2016 (In thousands) Balance at December 31: $ 63 $ — $ — Adjustment due to ASU 2018-02 (1) 13 — — Balance at January 1: 76 — — Unrealized appreciation (depreciation) before reclassifications (1) (557) 63 — Amounts reclassified from accumulated other comprehensive income — — — Net current-period other comprehensive income (loss) (557) 63 — Balance at December 31: $ (481) $ 63 $ — _______________________ 1. In 2018, due to the implementation of

Industry Segment Information (T

Industry Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Revenue From Different Segments [Table Text Block]	The following table provides certain information about the operations of each of our segments: Year Ended December 31, 2018 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: (1) Oil and natural gas $ 423,059 $ — $ — $ — $ — $ 423,059 Contract drilling — 218,982 — — (22,490) 196,492 Gas gathering and processing — — 312,417 — (88,687) 223,730 Total revenues 423,059 218,982 312,417 — (111,177) 843,281 Expenses: Operating costs: Oil and natural gas 136,870 — — — (5,195) 131,675 Contract drilling — 150,834 — — (19,449) 131,385 Gas gathering and processing — — 251,328 — (83,492) 167,836 Total operating costs 136,870 150,834 251,328 — (108,136) 430,896 Depreciation, depletion, and amortization 133,584 57,508 44,834 7,679 — 243,605 Impairments ( 2 ) — 147,884 — — — 147,884 Total expenses 270,454 356,226 296,162 7,679 (108,136) 822,385 General and administrative — — — 38,707 — 38,707 Gain on disposition of assets (139) (425) (110) (30) — (704) Income (loss) from operations 152,744 (136,819) 16,365 (46,356) (3,041) (17,107) Loss on derivatives — — — (3,184) — (3,184) Interest expense, net — — (1,214) (32,280) — (33,494) Other — — — 22 — 22 Income (loss) before income taxes $ 152,744 $ (136,819) $ 15,151 $ (81,798) $ (3,041) $ (53,763) Identifiable assets: Oil and natural gas ( 3 ) $ 1,357,779 $ — $ — $ — $ (6,949) $ 1,350,830 Contract drilling — 806,696 — — (85) 806,611 Gas gathering and processing — — 466,851 — (5,023) 461,828 Total identifiable assets ( 4 ) 1,357,779 806,696 466,851 — (12,057) 2,619,269 Corporate land and building — — — 55,505 — 55,505 Other corporate assets ( 5 ) — — — 25,566 (2,287) 23,279 Total assets $ 1,357,779 $ 806,696 $ 466,851 $ 81,071 $ (14,344) $ 2,698,053 Capital expenditures: $ 367,335 $ 75,510 $ 44,810 $ 1,125 $ — $ 488,780 _______________________ 1. The revenues for oil and na tural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. Impairment for contract drilling equipment includes a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment. 3. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 4. Identifiable assets are those used in Unit’s operations in each industry segment. 5. Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. Year Ended December 31, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 357,744 $ — $ — $ — $ — $ 357,744 Contract drilling — 188,172 — — (13,452) 174,720 Gas gathering and processing — — 277,049 — (69,873) 207,176 Total revenues 357,744 188,172 277,049 — (83,325) 739,640 Expenses: Operating costs: Oil and natural gas 135,532 — — — (4,743) 130,789 Contract drilling — 134,432 — — (11,832) 122,600 Gas gathering and processing — — 220,613 — (65,130) 155,483 Total operating costs 135,532 134,432 220,613 — (81,705) 408,872 Depreciation, depletion and amortization 101,911 56,370 43,499 7,477 — 209,257 Total expenses 237,443 190,802 264,112 7,477 (81,705) 618,129 General and administrative — — — 38,087 — 38,087 (Gain) loss on disposition of assets (228) 776 (25) (850) — (327) Income (loss) from operations 120,529 (3,406) 12,962 (44,714) (1,620) 83,751 Gain on derivatives — — — 14,732 — 14,732 Interest expense, net — — — (38,334) — (38,334) Other — — — 21 — 21 Income (loss) before income taxes $ 120,529 $ (3,406) $ 12,962 $ (68,295) $ (1,620) $ 60,170 Identifiable assets: Oil and natural gas ( 1 ) $ 1,134,080 $ — $ — $ — $ (6,180) $ 1,127,900 Contract drilling — 933,063 — — — 933,063 Gas gathering and processing — — 439,369 — (798) 438,571 Total identifiable assets ( 2 ) 1,134,080 933,063 439,369 — (6,978) 2,499,534 Corporate land and building — — — 56,854 — 56,854 Other corporate assets ( 3 ) — — — 25,064 — 25,064 Total assets $ 1,134,080 $ 933,063 $ 439,369 $ 81,918 $ (6,978) $ 2,581,452 Capital expenditures: $ 270,443 $ 36,148 $ 22,168 $ 3,521 $ — $ 332,280 _______________________ 1. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 2. Identifiable assets are those used in Unit’s operations in each industry segment. 3. Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. Year Ended December 31, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 294,221 $ — $ — $ — $ — $ 294,221 Contract drilling — 122,086 — — — 122,086 Gas gathering and processing — — 237,785 — (51,915) 185,870 Total revenues 294,221 122,086 237,785 — (51,915) 602,177 Expenses: Operating costs: Oil and natural gas 126,739 — — — (6,555) 120,184 Contract drilling — 88,154 — — — 88,154 Gas gathering and processing — — 182,969 — (45,360) 137,609 Total operating costs 126,739 88,154 182,969 — (51,915) 345,947 Depreciation, depletion and amortization 113,811 46,992 45,715 1,835 — 208,353 Impairments (1) 161,563 — — — — 161,563 Total expenses 402,113 135,146 228,684 1,835 (51,915) 715,863 General and administrative — — — 33,337 — 33,337 (Gain) loss on disposition of assets 324 (3,184) 302 18 — (2,540) Income (loss) from operations (108,216) (9,876) 8,799 (35,190) — (144,483) Gain on derivatives — — — (22,813) — (22,813) Interest expense, net — — — (39,829) — (39,829) Other — — — 307 — 307 Income (loss) before income taxes $ (108,216) $ (9,876) $ 8,799 $ (97,525) $ — $ (206,818) Identifiable assets: Oil and natural gas ( 2 ) $ 970,238 $ — $ — $ — $ (5,079) $ 965,159 Contract drilling — 941,676 — — — 941,676 Gas gathering and processing — — 462,330 — (730) 461,600 Total identifiable assets ( 3 ) 970,238 941,676 462,330 — (5,809) 2,368,435 Corporate land and building — — — 58,188 — 58,188 Other corporate assets ( 4 ) — — — 52,680 — 52,680 Total assets $ 970,238 $ 941,676 $ 462,330 $ 110,868 $ (5,809) $ 2,479,303 Capital expenditures: $ 89,562 $ 19,134 $ 16,796 $ 16,663 $ — $ 142,155 _______________________ 1. We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax). 2. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 3. Identifiable assets are those used in Unit’s operations in each industry segment. 4. Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.

Selected Quarterly Financial _2

Selected Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2017 Revenues $ 175,724 $ 170,581 $ 188,488 $ 204,847 Gross income (1) $ 32,657 $ 24,462 $ 27,181 $ 37,211 Net income attributable to Unit Corporation $ 15,929 $ 9,059 $ 3,705 $ 89,155 Net income attributable to Unit Corporation per common share: Basic $ 0.32 $ 0.18 $ 0.07 $ 1.74 Diluted (2) $ 0.31 $ 0.17 $ 0.07 $ 1.71 2018 Revenues $ 205,132 $ 203,303 $ 220,058 $ 214,788 Gross income (loss) (1) $ 38,833 $ 40,915 $ 49,216 $ (108,068) Net income attributable to Unit Corporation $ 7,865 $ 5,788 $ 18,899 $ (77,840) Net income (loss) attributable to Unit Corporation per common share: Basic $ 0.15 $ 0.11 $ 0.36 $ (1.49) Diluted $ 0.15 $ 0.11 $ 0.36 $ (1.49) _________________________ 1. Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss). 2. The earnings per share for the year's four quarters does not equal annual income per share.

Supplemental Condensed Consol_2

Supplemental Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheets December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 403 $ 208 $ 5,841 $ — $ 6,452 Accounts receivable, net of allowance for doubtful accounts of $2,531 (Guarantor of $1,326 and Parent of $1,205) 2,539 94,526 36,676 (14,344) 119,397 Materials and supplies — 473 — — 473 Current derivative asset 12,870 — — — 12,870 Current income tax receivable 243 1,811 — — 2,054 Assets held for sale — 22,511 — — 22,511 Prepaid expenses and other 5,103 3,560 2,693 — 11,356 Total current assets 21,158 123,089 45,210 (14,344) 175,113 Property and equipment: Oil and natural gas properties on the full cost method: Proved properties — 6,018,568 — — 6,018,568 Unproved properties not being amortized — 330,216 — — 330,216 Drilling equipment — 1,284,419 — — 1,284,419 Gas gathering and processing equipment — — 767,388 — 767,388 Saltwater disposal systems — 68,339 — — 68,339 Corporate land and building — 59,081 — — 59,081 Transportation equipment 9,273 17,165 3,086 — 29,524 Other 28,584 28,923 — — 57,507 37,857 7,806,711 770,474 — 8,615,042 Less accumulated depreciation, depletion, amortization, and impairment 27,504 5,790,481 364,741 — 6,182,726 Net property and equipment 10,353 2,016,230 405,733 — 2,432,316 Intercompany receivable 950,916 — — (950,916) — Goodwill — 62,808 — — 62,808 Investments 1,160,444 1,500 — (1,160,444) 1,500 Other assets 5,115 5,293 15,908 — 26,316 Total assets $ 2,147,986 $ 2,208,920 $ 466,851 $ (2,125,704) $ 2,698,053 December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 8,697 $ 122,610 $ 32,214 $ (13,576) $ 149,945 Accrued liabilities 28,230 16,409 5,493 (468) 49,664 Current portion of other long-term liabilities 812 6,563 6,875 — 14,250 Total current liabilities 37,739 145,582 44,582 (14,044) 213,859 Intercompany debt — 948,707 2,209 (950,916) — Bonds payable less debt issuance costs 644,475 — — — 644,475 Non-current derivative liabilities 293 — — — 293 Other long-term liabilities 13,134 73,713 14,687 (300) 101,234 Deferred income taxes 60,983 83,765 — — 144,748 Shareholders’ equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued — — — — — Common stock, $.20 par value, 175,000,000 shares authorized, 54,055,600 shares issued 10,414 — — — 10,414 Capital in excess of par value 628,108 45,921 197,042 (242,963) 628,108 Contributions from Unit — — 792 (792) — Accumulated other comprehensive loss — (481) — — (481) Retained earnings 752,840 911,713 4,976 (916,689) 752,840 Total shareholders’ equity attributable to Unit Corporation 1,391,362 957,153 202,810 (1,160,444) 1,390,881 Non-controlling interests in consolidated subsidiaries — — 202,563 — 202,563 Total shareholders' equity 1,391,362 957,153 405,373 (1,160,444) 1,593,444 Total liabilities and shareholders’ equity $ 2,147,986 $ 2,208,920 $ 466,851 $ (2,125,704) $ 2,698,053 December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 510 $ 191 $ — $ — $ 701 Accounts receivable, net of allowance for doubtful accounts of $2,450 (Guarantor of $1,245 and Non-Guarantor of $1,205) 154 89,622 28,714 (6,978) 111,512 Materials and supplies — 505 — — 505 Current derivative asset 721 — — — 721 Current income tax receivable 61 0 — — — 61 Prepaid expenses and other 2,925 2,370 877 — 6,172 Total current assets 4,371 92,688 29,591 (6,978) 119,672 Property and equipment: Oil and natural gas properties on the full cost method: Proved properties — 5,712,813 — — 5,712,813 Unproved properties not being amortized — 296,764 — — 296,764 Drilling equipment — 1,593,611 — — 1,593,611 Gas gathering and processing equipment — — 726,236 — 726,236 Saltwater disposal systems — 62,618 — — 62,618 Corporate land and building — 59,080 — — 59,080 Transportation equipment 9,270 17,423 2,938 — 29,631 Other 28,039 25,400 — — 53,439 37,309 7,767,709 729,174 — 8,534,192 Less accumulated depreciation, depletion, amortization, and impairment 21,268 5,807,757 322,425 — 6,151,450 Net property and equipment 16,041 1,959,952 406,749 — 2,382,742 Intercompany receivable 1,155,725 — — (1,155,725) — Goodwill — 62,808 — — 62,808 Investments 1,044,709 1,500 — (1,044,709) 1,500 Other assets 5,373 6,328 3,029 — 14,730 Total assets $ 2,226,219 $ 2,123,276 $ 439,369 $ (2,207,412) $ 2,581,452 December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 13,124 $ 87,514 $ 18,988 $ (6,978) $ 112,648 Accrued liabilities 26,165 19,134 3,224 — 48,523 Current derivative liability 7,763 — — — 7,763 Current portion of other long-term liabilities 657 8,501 3,844 — 13,002 Total current liabilities 47,709 115,149 26,056 (6,978) 181,936 Intercompany debt — 870,582 285,143 (1,155,725) — Long-term debt 178,000 — — — 178,000 Bonds payable less debt issuance costs 642,276 — — — 642,276 Other long-term liabilities 11,257 77,566 11,380 — 100,203 Deferred income taxes 1,480 85,443 46,554 — 133,477 Shareholders’ equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued — — — — — Common stock, $.20 par value, 175,000,000 shares authorized, 52,880,134 shares issued 10,280 — — — 10,280 Capital in excess of par value 535,815 45,921 15,549 (61,470) 535,815 Accumulated other comprehensive income — 63 — — 63 Retained earnings 799,402 928,552 54,687 (983,239) 799,402 Total shareholders’ equity attributable to Unit Corporation 1,345,497 974,536 70,236 (1,044,709) 1,345,560 Non-controlling interests in consolidated subsidiaries — — — — — Total shareholders' equity 1,345,497 974,536 70,236 (1,044,709) 1,345,560 Total liabilities and shareholders’ equity $ 2,226,219 $ 2,123,276 $ 439,369 $ (2,207,412) $ 2,581,452
Condensed Consolidating Statements of Operations	Condensed Consolidating Statements of Operations Year Ended December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 642,041 $ 312,417 $ (111,177) $ 843,281 Expenses: Operating costs — 287,704 251,328 (108,136) 430,896 Depreciation, depletion, and amortization 7,679 191,092 44,834 — 243,605 Impairments — 147,884 — — 147,884 General and administrative — 36,083 2,624 — 38,707 Gain on disposition of assets (30) (564) (110) — (704) Total operating expenses 7,649 662,199 298,676 (108,136) 860,388 Income (loss) from operations (7,649) (20,158) 13,741 (3,041) (17,107) Interest, net (32,280) — (1,214) — (33,494) Loss on derivatives (3,184) — — — (3,184) Other 22 — — — 22 Income (loss) before income taxes (43,091) (20,158) 12,527 (3,041) (53,763) Income tax expense (benefit) (12,707) (3,319) 2,030 — (13,996) Equity in net earnings from investment in subsidiaries, net of taxes (14,904) — — 14,904 — Net loss (45,288) (16,839) 10,497 11,863 (39,767) Less: net income attributable to non-controlling interest — — 5,521 — 5,521 Net loss attributable to Unit Corporation $ (45,288) $ (16,839) $ 4,976 $ 11,863 $ (45,288) Year Ended December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 545,916 $ 277,049 $ (83,325) $ 739,640 Expenses: Operating costs — 269,964 220,613 (81,705) 408,872 Depreciation, depletion, and amortization 7,477 158,281 43,499 — 209,257 General and administrative — 29,440 8,647 — 38,087 (Gain) loss on disposition of assets (850) 548 (25) — (327) Total operating expenses 6,627 458,233 272,734 (81,705) 655,889 Income (loss) from operations (6,627) 87,683 4,315 (1,620) 83,751 Interest, net (37,645) — (689) — (38,334) Gain on derivatives 14,732 — — — 14,732 Other 21 — — — 21 Income (loss) before income taxes (29,519) 87,683 3,626 (1,620) 60,170 Income tax benefit (12,599) (20,881) (24,198) — (57,678) Equity in net earnings from investment in subsidiaries, net of taxes 134,768 — — (134,768) — Net income 117,848 108,564 27,824 (136,388) 117,848 Less: net income attributable to non-controlling interest — — — — — Net income attributable to Unit Corporation $ 117,848 $ 108,564 $ 27,824 $ (136,388) $ 117,848 Year Ended December 31, 2016 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 416,307 $ 237,785 $ (51,915) $ 602,177 Expenses: Operating costs — 214,892 182,970 (51,915) 345,947 Depreciation, depletion, and amortization 1,835 160,803 45,715 — 208,353 Impairments — 161,563 — — 161,563 General and administrative — 26,158 7,179 — 33,337 (Gain) loss on disposition of assets 18 (2,860) 302 — (2,540) Total operating expenses 1,853 560,556 236,166 (51,915) 746,660 Income (loss) from operations (1,853) (144,249) 1,619 — (144,483) Interest, net (38,995) — (834) — (39,829) Loss on derivatives (22,813) — — — (22,813) Other — 307 — — 307 Income (loss) before income taxes (63,661) (143,942) 785 — (206,818) Income tax expense (benefit) (24,031) (48,654) 1,491 — (71,194) Equity in net earnings from investment in subsidiaries, net of taxes (95,994) — — 95,994 — Net loss (135,624) (95,288) (706) 95,994 (135,624) Less: net income attributable to non-controlling interest — — — — — Net loss attributable to Unit Corporation $ (135,624) $ (95,288) $ (706) $ 95,994 $ (135,624)
Condensed Consolidating Statement of Comprehensive Income (Loss)	Condensed Consolidating Statements of Comprehensive Income (Loss) Year Ended December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (45,288) $ (16,839) $ 10,497 $ 11,863 $ (39,767) Other comprehensive income, net of taxes: Unrealized loss on securities, net of tax (($181)) — (557) — — (557) Comprehensive loss (45,288) (17,396) 10,497 11,863 (40,324) Less: Comprehensive income attributable to non-controlling interests — — 5,521 — 5,521 Comprehensive loss attributable to Unit Corporation $ (45,288) $ (17,396) $ 4,976 $ 11,863 $ (45,845) Year Ended December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net income $ 117,848 $ 108,564 $ 27,824 $ (136,388) $ 117,848 Other comprehensive income, net of taxes: Unrealized gain on securities, net of tax ($39) — 63 — — 63 Comprehensive income 117,848 108,627 27,824 (136,388) 117,911 Less: Comprehensive income attributable to non-controlling interests — — — — — Comprehensive income attributable to Unit Corporation $ 117,848 $ 108,627 $ 27,824 $ (136,388) $ 117,911 Year Ended December 31, 2016 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (135,624) $ (95,288) $ (706) $ 95,994 $ (135,624) Other comprehensive income, net of taxes: Unrealized loss on securities, net of tax ($0) — — — — — Comprehensive loss (135,624) (95,288) (706) 95,994 (135,624) Less: Comprehensive income attributable to non-controlling interests — — — — — Comprehensive loss attributable to Unit Corporation $ (135,624) $ (95,288) $ (706) $ 95,994 $ (135,624)
Condensed Consolidating Statements of Cash Flows	Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2018 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (120,317) $ 327,075 $ 12,129 $ 128,872 $ 347,759 INVESTING ACTIVITIES: Capital expenditures 236 (400,990) (45,528) — (446,282) Producing properties and other acquisitions — (29,970) — — (29,970) Proceeds from disposition of property and equipment 30 25,777 103 — 25,910 Net cash provided by (used in) investing activities 266 (405,183) (45,425) — (450,342) FINANCING ACTIVITIES: Borrowings under credit agreements 97,100 — 2,000 — 99,100 Payments under credit agreements (275,100) — (2,000) — (277,100) Intercompany borrowings (advances), net 204,809 78,125 (154,854) (128,080) — Payments on capitalized leases — — (3,843) — (3,843) Proceeds from investments of non-controlling interest 102,958 — 197,042 — 300,000 Contributions from Unit — — 792 (792) — Transaction costs associated with sale of non-controlling interest (2,503) — — — (2,503) Book overdrafts (7,320) — — — (7,320) Net cash provided by financing activities 119,944 78,125 39,137 (128,872) 108,334 Net increase in cash and cash equivalents (107) 17 5,841 — 5,751 Cash and cash equivalents, beginning of period 510 191 — — 701 Cash and cash equivalents, end of period $ 403 $ 208 $ 5,841 $ — $ 6,452 Year Ended December 31, 2017 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (1,683) $ 224,446 $ 43,193 $ — $ 265,956 INVESTING ACTIVITIES: Capital expenditures (3,594) (233,254) (18,705) — (255,553) Producing properties and other acquisitions — (58,026) — — (58,026) Proceeds from disposition of property and equipment 964 20,674 75 — 21,713 Other — (1,500) — — (1,500) Net cash used in investing activities (2,630) (272,106) (18,630) — (293,366) FINANCING ACTIVITIES: Borrowings under credit agreement 343,900 — — — 343,900 Payments under credit agreement (326,700) — — — (326,700) Intercompany borrowings (advances), net (26,606) 47,475 (20,869) — — Payments on capitalized leases — — (3,694) — (3,694) Proceeds from common stock issued, net of issue costs 18,623 — — — 18,623 Book overdrafts (4,911) — — — (4,911) Net cash provided by (used in) financing activities 4,306 47,475 (24,563) — 27,218 Net increase in cash and cash equivalents (7) (185) — — (192) Cash and cash equivalents, beginning of period 517 376 — — 893 Cash and cash equivalents, end of period $ 510 $ 191 $ — $ — $ 701 Year Ended December 31, 2016 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by operating activities $ 1,781 $ 197,132 $ 41,217 $ — $ 240,130 INVESTING ACTIVITIES: Capital expenditures (3,927) (158,983) (23,239) — (186,149) Producing properties and other acquisitions — (564) — — (564) Proceeds from disposition of property and equipment 13 74,694 116 — 74,823 Other 750 — 169 — 919 Net cash provided by (used in) investing activities (3,164) (84,853) (22,954) — (110,971) FINANCING ACTIVITIES: Borrowings under credit agreement 251,398 — — — 251,398 Payments under credit agreement (371,600) — — — (371,600) Intercompany borrowings (advances), net 126,797 (112,228) (14,569) — — Payments on capitalized leases — — (3,694) — (3,694) Tax expense from stock compensation (376) — — — (376) Book overdrafts (4,829) — — — (4,829) Net cash used in financing activities 1,390 (112,228) (18,263) — (129,101) Net increase in cash and cash equivalents 7 51 — — 58 Cash and cash equivalents, beginning of period 510 325 — — 835 Cash and cash equivalents, end of period $ 517 $ 376 $ — $ — $ 893

Supplemental Oil And Gas Disc_2

Supplemental Oil And Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2018 2017 2016 (In thousands) Capitalized costs: Proved properties $ 6,018,568 $ 5,712,813 $ 5,446,305 Unproved properties 330,216 296,764 314,867 6,348,784 6,009,577 5,761,172 Accumulated depreciation, depletion, amortization, and impairment (5,124,257) (4,996,696) (4,900,304) Net capitalized costs $ 1,224,527 $ 1,012,881 $ 860,868 Cost incurred: Unproved properties acquired $ 57,430 $ 47,029 $ 21,675 Proved properties acquired 15,158 47,638 564 Exploration 15,907 14,811 17,325 Development 280,692 160,941 80,582 Asset retirement obligation (7,629) (3,613) (30,906) Total costs incurred $ 361,558 $ 266,806 $ 89,240
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, 2018, by the year in which such costs were incurred: 2018 2017 2016 2015 and Prior Total (In thousands) Unproved properties acquired and wells in progress $ 60,372 $ 46,986 $ 21,947 $ 200,911 $ 330,216
Results Of Operations For Producing Activities [Table Text Block]	The results of operations for producing activities are as follows: 2018 2017 2016 (In thousands) Revenues $ 429,119 $ 347,285 $ 282,742 Production costs (131,328) (113,344) (103,568) Depreciation, depletion, amortization, and impairment (132,923) (101,326) (274,155) 164,868 132,615 (94,981) Income tax (expense) benefit (42,915) (52,078) 32,696 Results of operations for producing activities (excluding corporate overhead and financing costs) $ 121,953 $ 80,537 $ (62,285)
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 Total MBoe (In thousands) 2016 Proved developed and undeveloped reserves: Beginning of year 16,735 37,687 484,868 135,233 Revision of previous estimates (1) (549) (2,473) (31,670) (8,300) Extensions and discoveries 1,816 1,588 13,720 5,690 Infill reserves in existing proved fields 663 2,724 24,704 7,504 Purchases of minerals in place 114 43 630 262 Production (2,974) (5,014) (55,735) (17,277) Sales (109) (73) (30,938) (5,338) End of year 15,696 34,482 405,579 117,774 Proved developed reserves: Beginning of year 14,679 31,218 416,395 115,296 End of year 12,724 28,502 347,121 99,079 Proved undeveloped reserves: Beginning of year 2,056 6,469 68,473 19,937 End of year 2,972 5,980 58,458 18,695 2017 Proved developed and undeveloped reserves: Beginning of year 15,696 34,482 405,579 117,774 Revision of previous estimates (1) 730 4,325 38,330 11,444 Extensions and discoveries 2,235 4,520 49,321 14,975 Infill reserves in existing proved fields 1,632 5,779 52,270 16,123 Purchases of minerals in place 2,019 1,197 15,313 5,768 Production (2,715) (4,737) (51,260) (15,996) Sales (84) (80) (903) (314) End of year 19,513 45,486 508,650 149,774 Proved developed reserves: Beginning of year 12,724 28,502 347,121 99,079 End of year 14,862 33,358 388,446 112,961 Proved undeveloped reserves: Beginning of year 2,972 5,980 58,458 18,695 End of year 4,651 12,128 120,204 36,813 2018 Proved developed and undeveloped reserves: Beginning of year 19,513 45,486 508,650 149,774 Revision of previous estimates 180 (1,368) (17,859) (4,165) Extensions and discoveries 3,250 5,149 75,806 21,033 Infill reserves in existing proved fields 1,898 2,795 23,778 8,656 Purchases of minerals in place 701 856 6,897 2,707 Production (2,874) (4,925) (55,627) (17,070) Sales (110) (197) (5,682) (1,254) End of year 22,558 47,796 535,963 159,681 Proved developed reserves: Beginning of year 14,862 33,358 388,446 112,961 End of year 15,192 33,515 377,216 111,576 Proved undeveloped reserves: Beginning of year 4,651 12,128 120,204 36,813 End of year 7,366 14,281 158,747 48,105 _________________________ 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 adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows: 2018 2017 2016 (In thousands) Future cash flows $ 3,980,369 $ 3,347,396 $ 2,030,925 Future production costs (1,479,744) (1,308,244) (861,625) Future development costs (442,984) (369,560) (173,446) Future income tax expenses (307,916) (234,152) (141,752) Future net cash flows 1,749,725 1,435,440 854,102 10% annual discount for estimated timing of cash flows (766,047) (628,270) (335,892) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 983,678 $ 807,170 $ 518,210
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: 2018 2017 2016 (In thousands) Sales and transfers of oil and natural gas produced, net of production costs $ (297,791) $ (239,953) $ (173,920) Net changes in prices and production costs 120,062 236,126 (94,026) Revisions in quantity estimates and changes in production timing (33,282) 87,239 (51,979) Extensions, discoveries, and improved recovery, less related costs 234,172 102,965 84,738 Changes in estimated future development costs 19,535 (5,194) 70,976 Previously estimated cost incurred during the period 63,557 36,044 16,602 Purchases of minerals in place 23,416 51,686 2,652 Sales of minerals in place (5,004) (1,447) (17,248) Accretion of discount 89,753 57,517 69,069 Net change in income taxes (31,674) (33,389) 44,241 Other—net (6,236) (2,634) (22,381) Net change 176,508 288,960 (71,276) Beginning of year 807,170 518,210 589,486 End of year $ 983,678 $ 807,170 $ 518,210

Schedule II - Valuation And Q_2

Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Tables)	12 Months Ended
	Dec. 31, 2018
Valuation and Qualifying Accounts [Abstract]
Summary of Valuation Allowance [Table Text Block]	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, 2018 $ 2,450 $ 81 $ — $ 2,531 Year ended December 31, 2017 $ 3,773 $ 348 $ (1,671) $ 2,450 Year ended December 31, 2016 $ 5,199 $ 785 $ (2,211) $ 3,773

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CVR Refining, LP | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	14.00%	2.00%	0.00%
Valero Energy Corporation | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	9.00%	11.00%
Energy Transfer Partners (formerly Sunoco Logistics Partners) | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	3.00%	10.00%	24.00%
QEP Resources, Inc. | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	16.00%	26.00%	28.00%
Slawson Exploration Company, Inc | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	6.00%	3.00%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	3.00%	7.00%	18.00%
ONEOK, Inc. | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	45.00%	36.00%	30.00%
Range Resources Corporation | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	7.00%	9.00%	10.00%
Koch Energy Services, LLC | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	6.00%	8.00%	11.00%
Tenaska Resources, LLC | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	4.00%	6.00%	10.00%

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Schedule of Fair Values of the Net Asset (Liabilities)) (Details) $ in Millions	Dec. 31, 2018USD ($)
Derivative Counterparty [Line Items]
Total net assets	$ 12.6
Bank of Montreal
Derivative Counterparty [Line Items]
Total net assets	9.9
Bank of America Merrill Lynch
Derivative Counterparty [Line Items]
Total net assets	$ 2.7

Summary Of Significant Accoun_6

Summary Of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)rigcontractPartnershipsMMcf		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Summary Of Significant Accounting Policies [Line Items]
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	We consolidate the activities of Superior, a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.
Number of contracts, daywork expiring in one year | contract	17
Number of contracts, daywork expiring in two years | contract	7
Book Overdrafts	$ 5,100,000		$ 12,400,000
Concentration of cash	11,000,000		11,400,000
Impairments	147,884,000		0	$ 161,563,000
Assets held for sale	22,511,000		0
Interest Costs Capitalized	16,500,000		15,900,000	15,300,000
Goodwill impairment	0		0	0
Additions to goodwill	$ 0		0	0
Percentage fair value exceeds carrying value for goodwill	37.00%
Goodwill deductible for tax purposes	$ 400,000
Directly related overhead costs capitalized	15,900,000		14,800,000	15,400,000
Average rates used for depreciation, depletion, and amortization per Boe	7.50		6	6.24
Unproved properties not being amortized	$ 330,216,000		296,764,000	314,867,000
Future discounted net cash flows discounted	10.00%
Unproved properties included in amortization	$ 0		10,500,000	7,600,000
Revenues from transactions with operating segments of same entity	22,500,000		13,400,000	0
Eliminated associated operating expense	19,500,000		11,800,000
Eliminated yielding	$ 3,000,000		$ 1,600,000
Number of oil and gas limited partnerships | Partnerships	13
Federal statutory income tax rate, percent	21.00%		35.00%
Tax benefit from change in enacted tax rate	$ 0	[1]	$ (81,307,000)	0	[1]
Liability recognized to under production	$ (3,331,000)		(3,283,000)
Minimum
Summary Of Significant Accounting Policies [Line Items]
Number of days for drilling of one well	10 days
Contact duration	6 months
Insurance coverage	$ 0
Operating Lease, Right-of-Use Asset	3,000,000
Operating Lease, Liability	$ 3,000,000
Maximum
Summary Of Significant Accounting Policies [Line Items]
Number of days for drilling of one well	90 days
Contact duration	3 years
Insurance coverage	$ 1,000,000
Operating Lease, Right-of-Use Asset	4,500,000
Operating Lease, Liability	$ 4,500,000
Under-Produced Properties
Summary Of Significant Accounting Policies [Line Items]
Natural gas balancing (MMcf) | MMcf	3,800
Over-Produced Properties
Summary Of Significant Accounting Policies [Line Items]
Natural gas balancing (MMcf) | MMcf	3,700
Natural Gas Balancing
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	$ 2,900,000
Drilling Equipment
Summary Of Significant Accounting Policies [Line Items]
Minimum depreciation percentage for idle drilling rigs (if idle under 48 months)	20.00%
Number of drilling rigs removed from service | rig	41
Impairments	$ 147,900,000		0	0
Impairment of contract drilling equipment, net of tax	$ 111,700,000
Drilling Equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years	15 years
Building
Summary Of Significant Accounting Policies [Line Items]
Useful life, years	39 years
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
Oil and Natural Gas
Summary Of Significant Accounting Policies [Line Items]
Impairments	$ 0	[2]	$ 0	161,600,000
Non-cash ceiling test write-down net of tax				$ 100,600,000
ASU 2018-02 end balance
Summary Of Significant Accounting Policies [Line Items]
Federal statutory income tax rate, percent	24.50%		37.75%
Mechanical drilling rigs | Drilling Equipment
Summary Of Significant Accounting Policies [Line Items]
Number of drilling rigs removed from service | rig	29
SCR diesel-electric drilling rigs | Drilling Equipment
Summary Of Significant Accounting Policies [Line Items]
Number of drilling rigs removed from service | rig	12
[1]	In 2017, the revaluation from the Tax Act.
[2]	Impairment for contract drilling equipment includes a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Revenue Impact of the Adoption of ASC606) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Adoption of ASC606 [Line Items]
Oil and natural gas revenues										$ 423,059		$ 357,744	$ 294,221
Oil and natural gas operating costs										131,675		130,789	120,184
Oil and natural gas gross profit	[1]	$ (108,068)	$ 49,216	$ 40,915	$ 38,833	$ 37,211	$ 27,181	$ 24,462	$ 32,657
Gas gathering and processing revenues										223,730		207,176	185,870
Deferred tax benefit										(10,865)		(57,683)	(71,209)
Net income (loss)										(39,767)		117,848	(135,624)
Adjustments due to ASC606 [Member]
Adoption of ASC606 [Line Items]
Oil and natural gas revenues										(17,518)
Oil and natural gas operating costs										(17,518)
Gas gathering and processing revenues										4,970
Deferred tax benefit										1,218
Net income (loss)										3,752
Amounts without the adoption of ASC606 [Member]
Adoption of ASC606 [Line Items]
Oil and natural gas revenues										440,577
Oil and natural gas operating costs										149,193
Gas gathering and processing revenues										218,760
Deferred tax benefit										(12,083)
Net income (loss)										(43,519)
Oil and Natural Gas
Adoption of ASC606 [Line Items]
Oil and natural gas revenues										423,059	[2]	357,744	294,221
Oil and natural gas operating costs										136,870		135,532	126,739
Oil and natural gas gross profit										291,384
Gas gathering and processing revenues										0	[2]	$ 0	$ 0
Oil and Natural Gas | Adjustments due to ASC606 [Member]
Adoption of ASC606 [Line Items]
Oil and natural gas gross profit										0
Oil and Natural Gas | Amounts without the adoption of ASC606 [Member]
Adoption of ASC606 [Line Items]
Oil and natural gas gross profit										$ 291,384
[1]	Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss).
[2]	The revenues for oil and na tural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

Revenue from Contracts with C_4

Revenue from Contracts with Customers (Balance Sheet Impact of the Adoption of ASC606) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
ASSETS
Prepaid expenses and other	$ 11,356		$ 6,172
Other assets	27,816	$ 27,028	16,230
LIABILITIES AND SHAREHOLDERS' EQUITY
Current portion of other long-term liabilities	14,250	15,750	13,002
Other long-term liabilities	101,234	109,940	100,203
Deferred income taxes	144,748	133,064	133,477
Retained earnings	752,840	798,128	$ 799,402
Mid-Stream | Adjustments due to ASC606 [Member]
ASSETS
Prepaid expenses and other	285
Other assets	12,879	10,798
LIABILITIES AND SHAREHOLDERS' EQUITY
Current portion of other long-term liabilities	2,874	2,748
Other long-term liabilities	7,007	9,737
Deferred income taxes	805	(413)
Retained earnings	2,478	$ (1,274)
Mid-Stream | Amounts without the adoption of ASC606 [Member]
ASSETS
Prepaid expenses and other	11,071
Other assets	14,937
LIABILITIES AND SHAREHOLDERS' EQUITY
Current portion of other long-term liabilities	11,376
Other long-term liabilities	94,227
Deferred income taxes	143,943
Retained earnings	$ 750,362

Revenue from Contracts with C_5

Revenue from Contracts with Customers (Revenue, Remaining Performance Obligation) (Details) - Mid-Stream - Demand fee contracts [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining term of contract	4 years
Remaining impact to revenue	$ (3,282)
2,019
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	2,632
2,020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	(3,781)
2,021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	(3,507)
2,022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	$ 1,374

Revenue from Contracts with C_6

Revenue from Contracts with Customers (Contract with Customer, Asset and Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Adoption of ASC606 [Line Items]
Contract liability	$ 9,881	$ 0
Change in contact assets and liabilities, net	(4,970)	$ 0	$ 0
Mid-Stream
Adoption of ASC606 [Line Items]
Contract Assets	13,164			$ 10,798
Change in contract assets	2,366
Contract liability	9,881			12,485
Change in contract liabilities	(2,604)
Contract assets (liabilities), net	3,283			$ (1,687)
Change in contact assets and liabilities, net	$ 4,970

Revenue from Contracts with C_7

Revenue from Contracts with Customers (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)contract		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jan. 01, 2018USD ($)
Segment Reporting Information [Line Items]
Retained earnings	$ 752,840		$ 799,402		$ 798,128
Gas gathering and processing revenues	223,730		207,176	$ 185,870
Adjustments due to ASC606 [Member]
Segment Reporting Information [Line Items]
Gas gathering and processing revenues	$ 4,970
Minimum
Segment Reporting Information [Line Items]
Contact duration	6 months
Number of days for drilling of one well	10 days
Maximum
Segment Reporting Information [Line Items]
Contact duration	3 years
Number of days for drilling of one well	90 days
Oil and Natural Gas
Segment Reporting Information [Line Items]
Revenue Satisfied at Point in Time, Transfer of Control	Revenues from sales we make are recognized when our customer obtains control of the sold product. For sales to other mid-stream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer.
Gas gathering and processing revenues	$ 0	[1]	0	0
Oil and Natural Gas | Adjustments due to ASC606 [Member]
Segment Reporting Information [Line Items]
Retained earnings					0
Drilling
Segment Reporting Information [Line Items]
Revenue Satisfied over Time, Method Used	At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under this new standard allow us to recognize revenues associated with our drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Those liabilities will generally only arise in relation to upfront mobilization fees paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue.
Number of daywork contracts | contract	32
Revenue, Practical Expedient, Initial Application and Transition, Qualitative Assessment	The majority of our drilling contracts have an original term of less than one year; however, the remaining performance obligations under the contracts that have a longer duration are not material.
Gas gathering and processing revenues	$ 0	[1]	0	0
Drilling | Adjustments due to ASC606 [Member]
Segment Reporting Information [Line Items]
Retained earnings					0
Drilling | Long-term Contract with Customer [Member]
Segment Reporting Information [Line Items]
Number of daywork contracts | contract	24
Drilling | Minimum
Segment Reporting Information [Line Items]
Contact duration	6 months
Number of days for drilling of one well	10 days
Drilling | Minimum | Long-term Contract with Customer [Member]
Segment Reporting Information [Line Items]
Contact duration	2 months
Drilling | Maximum
Segment Reporting Information [Line Items]
Contact duration	3 years
Number of days for drilling of one well	90 days
Mid-Stream
Segment Reporting Information [Line Items]
Revenue Satisfied over Time, Method Used	Contract terms range from a single month to terms spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.
Revenue, Practical Expedient, Initial Application and Transition, Qualitative Assessment	As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee.
Gas gathering and processing revenues	$ 312,417	[1]	$ 277,049	$ 237,785
Mid-Stream | Adjustments due to ASC606 [Member]
Segment Reporting Information [Line Items]
Retained earnings	$ 2,478				(1,274)
Adjustment to opening retained earnings, before tax					(1,700)
Adjustment to opening retained earnings, after tax					$ (1,300)
Mid-Stream | Minimum
Segment Reporting Information [Line Items]
Contact duration	5 years
Remaining term of contract	1 year
Mid-Stream | Maximum
Segment Reporting Information [Line Items]
Contact duration	10 years
Remaining term of contract	15 years
[1]	The revenues for oil and na tural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Fair Value of Acquired Assets and Liabilities) (Details) - USD ($) $ in Thousands		Dec. 06, 2018	Apr. 03, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Proved oil and natural gas properties				$ 6,018,568	$ 5,712,813	$ 5,446,305
Unproved properties not being amortized				330,216	296,764	314,867
Asset retirement obligation				$ (64,208)	$ (69,444)	$ (70,170)
EOG Acquisition
Business Acquisition [Line Items]
Total consideration given			$ 54,332
Proved oil and natural gas properties			43,745
Unproved properties not being amortized			8,650
Total oil and natural gas properties included in the full cost pool	[1]		52,395
Gas gathering equipment and other			2,340
Asset retirement obligation			(403)
Fair value of net assets acquired			$ 54,332
Excalibur Acquisition
Business Acquisition [Line Items]
Total consideration given		$ 29,633
Proved oil and natural gas properties		14,546
Unproved properties not being amortized		15,502
Total oil and natural gas properties included in the full cost pool	[2]	30,048
Asset retirement obligation		(415)
Fair value of net assets acquired		$ 29,633
[1]	We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.
[2]	We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details) MBoe in Thousands	Dec. 06, 2018USD ($)aMBoewellsnumberOfDrillingLocations	Apr. 03, 2018USD ($)	Apr. 03, 2017USD ($)aMBoewells	Dec. 31, 2018USD ($)MBoerig		Dec. 31, 2017USD ($)MBoerig	Dec. 31, 2016USD ($)MBoerig	Dec. 31, 2015MBoe
Acquisitions and Divestitures [Line Items]
Proved Developed Reserves (Volume) | MBoe				111,576		112,961	99,079	115,296
Impairments				$ 147,884,000		$ 0	$ 161,563,000
EOG Acquisition
Acquisitions and Divestitures [Line Items]
Total consideration given			$ 54,332,000
Business Acquisition, Effective Date of Acquisition			Jan. 1, 2017
Proved Developed Reserves (Volume) | MBoe			3,200
Natural Gas Gathering System			1
Excalibur Acquisition
Acquisitions and Divestitures [Line Items]
Total consideration given	$ 29,633,000
Business Acquisition, Effective Date of Acquisition	Nov. 1, 2018
Proved Developed Reserves (Volume) | MBoe	2,600
Horizontal drilling locations | numberOfDrillingLocations	30
Acquired land with existing production capacity, percent	82.00%
Hoxbar | EOG Acquisition
Acquisitions and Divestitures [Line Items]
Area of Real Estate Property | a			8,300
Proved developed producing wells | wells			47
Acquired land with existing production capacity, percent			71.00%
Penn Sands | Excalibur Acquisition
Acquisitions and Divestitures [Line Items]
Area of Real Estate Property | a	8,667
Wells acquired | wells	44
Oil and Natural Gas
Acquisitions and Divestitures [Line Items]
Other acquisitions				600,000		4,700,000	600,000
Proceeds from divestiture of assets				22,500,000		18,600,000	67,200,000
Impairments				$ 0	[1]	$ 0	$ 161,600,000
Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of rigs sold | rig						0	1
Number of drilling rigs removed from service | rig				41
Net book value of drilling rigs sold							$ 1,700,000
Gain (loss) on sale of drilling rigs							1,600,000
Impairments				$ 147,900,000		$ 0	$ 0
Impairment of contract drilling equipment, net of tax				$ 111,700,000
Mechanical drilling rigs | Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of drilling rigs removed from service | rig				29
SCR diesel-electric drilling rigs | Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of drilling rigs removed from service | rig				12
Ownership interest in Superior Pipeline Company, L.L.C.
Acquisitions and Divestitures [Line Items]
Ownership interest sold		50.00%
Proceeds from sale of non-controlling interest		$ 300,000,000
[1]	Impairment for contract drilling equipment includes a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Income (loss) of basic earnings (loss) attributable to Unit Corporation per common share	$ (77,840)	$ 18,899	$ 5,788	$ 7,865	$ 89,155		$ 3,705		$ 9,059		$ 15,929		$ (45,288)	$ 117,848	$ (135,624)
Income (loss) of effect of dilutive stock options, restricted stock, and SARs													0	0	0
Income (loss) of diluted earnings (loss) attributable to Unit Corporation per common share													$ (45,288)	$ 117,848	$ (135,624)
Weighted shares of basic earnings (loss) attributable to Unit Corporation per common share													51,981	51,113	50,029
Weighted shares of effect of dilutive stock options, restricted stock, and SARs													0	635	0
Weighted shares of diluted earnings (loss) attributable to Unit Corporation per common share													51,981	51,748	50,029
Per share amount of basic earnings (loss) attributable to Unit Corporation per common share	$ (1.49)	$ 0.36	$ 0.11	$ 0.15	$ 1.74	[1]	$ 0.07	[1]	$ 0.18	[1]	$ 0.32	[1]	$ (0.87)	$ 2.31	$ (2.71)
Per share amount of effect of dilutive stock options, restricted stock, and SARs													0	(0.03)	0
Per share amount of diluted earnings (loss) attributable to Unit Corporation per common share	$ (1.49)	$ 0.36	$ 0.11	$ 0.15	$ 1.71	[1]	$ 0.07	[1]	$ 0.17	[1]	$ 0.31	[1]	$ (0.87)	$ 2.28	$ (2.71)
[1]	The earnings per share for the year's four quarters does not equal annual income 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options and SARs	66,500	87,500	199,755
Average Exercise Price	$ 44.42	$ 51.34	$ 48.79

Earnings (Loss) Per Share (Narr

Earnings (Loss) Per Share (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	934,000	0	509,000
Stock options 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	66,500	87,500	199,755

Accrued Liabilities (Accrued Li

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accrued Liabilities [Abstract]
Employee costs	$ 22,056	$ 19,521
Lease operating expenses	12,756	11,819
Interest payable	6,635	6,745
Third-party credits	2,129	2,240
Taxes	1,378	3,404
Other	4,710	4,794
Total accrued liabilities	$ 49,664	$ 48,523

Long-Term Debt And Other Long_3

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
6.625% senior subordinated notes due 2021	$ 650,000	$ 650,000
Long-term Debt, Gross	650,000	828,000
Less: unamortized discount	(1,623)	(2,234)
Less: debt issuance costs, net	(3,902)	(5,490)
Total long-term debt	$ 644,475	$ 820,276
Line of Credit Facility, Interest Rate at Period End	0.00%	3.40%
Superior Credit Agreement [Member]
Debt Instrument [Line Items]
Credit Agreement	$ 0	$ 0
Unit Credit Agreement [Member]
Debt Instrument [Line Items]
Credit Agreement	$ 0	$ 178,000

Long-Term Debt And Other Long_4

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term debt and other long-term liabilites [Abstract]
ARO liability	$ 64,208		$ 69,444	$ 70,170
Workers' compensation	12,738		13,340
Capital lease obligations	11,380		15,224
Contract liability	9,881		0
Separation benefit plans	8,814		6,524
Deferred compensation plan	5,132		5,390
Gas balancing liability	3,331		3,283
Other liabilities	115,484		113,205
Current portion of other long-term liabilities	14,250	$ 15,750	13,002
Other long-term liabilities	$ 101,234	$ 109,940	$ 100,203

Long-Term Debt and Other Long_5

Long-Term Debt and Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Ending December 31, [Abstract]
2,019	$ 6,168
2,020	6,168
2,021	3,768
Total future payments	16,104
Less payments related to:
Maintenance	4,089
Interest	635
Present value of future minimum payments	$ 11,380	$ 15,224

Long-Term Debt And Other Long_6

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	May 02, 2018	Dec. 31, 2018	Apr. 02, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Oil and Gas Property, Full Cost Method, Discount Percentage		10.00%
Variable Interest Entity, Date Involvement Began		Apr. 3, 2018
Aggregate principal amount		$ 650,000			$ 650,000
Interest percentage of senior subordinated notes		6.625%
Debt Instrument, Maturity Date		May 15, 2021
Deducting fees for debt issuance		$ 14,700
Senior notes repurchase price in percentage		101.00%
Senior Notes, Covenant Compliance		We were in compliance with all covenants of the Notes
Principal Payments Year One		$ 14,200
Principal Payments Year Two		9,400
Principal Payments Year Three		692,000
Principal Payments Year Four		3,900
Principal Payments Year Five		$ 2,200
Number of compressors under capital lease agreement		20
Capital lease term		7 years
Capital Lease Obligations, Current		$ 4,000
Capital Lease Obligations, Noncurrent		$ 7,400
Discount rate capital leases		4.00%
Maintenance		$ 4,089
Interest		635
Capital leases, future minimum payments, average annual payment		$ 4,300
Capital lease fair market value percentage for purchase		10.00%
Unit Credit Agreement [Member]
Debt Instrument [Line Items]
Credit facility maturity date		October 18, 2023
Commitment fee percentage under credit facility		0.375%
Origination, agency and syndication fees		$ 3,300
Credit Facility Maximum Credit Amount			$ 425,000	$ 875,000
Debt instrument, variable interest rate, payable assessment period		90 days
LIBOR interest rate plus one percent plus a margin		LIBOR plus 1.00% plus a margin
Line of credit facility, amount borrowed		$ 0			178,000
Unit Credit Agreement, Dividend Restrictions		the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;
Unit Credit Agreement, Asset Restrictions		investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million.
Current ratio of credit facility		1 to 1
Leverage ratio of long-term debt		4 to 1
Covenant Compliance		we were in compliance with the covenants contained in the Unit credit agreement.
Unit Credit Agreement [Member] | Minimum
Debt Instrument [Line Items]
LIBOR plus interest rate		1.50%
Unit Credit Agreement [Member] | Maximum
Debt Instrument [Line Items]
LIBOR plus interest rate		2.50%
Unit Credit Agreement [Member] | Line Of Credit Facility Commitment Amount
Debt Instrument [Line Items]
Credit facility current credit amount			425,000	475,000
Unit Credit Agreement [Member] | Line Of Credit Facility Lender Determined Amount
Debt Instrument [Line Items]
Credit facility current credit amount			$ 425,000	$ 475,000
Unit Credit Agreement [Member] | Proved developed producing total value of our oil and gas properties
Debt Instrument [Line Items]
Percentage of collateral pledged		80.00%
Oil and Gas Property, Full Cost Method, Discount Percentage		8.00%
Superior Credit Agreement [Member]
Debt Instrument [Line Items]
Commitment fee percentage under credit facility		0.375%
Origination, agency and syndication fees		$ 1,700
Credit Facility Maximum Credit Amount		250,000
Credit facility current credit amount		200,000
Line of credit facility, amount borrowed		$ 0			$ 0
Covenant Compliance		Superior was in compliance with the Superior credit agreement covenants
Superior Credit Agreement, Initiation Date		May 10, 2018
Superior Credit Agreement, Term		5 years
Superior Credit Agreement, Interest Rate Description		annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%.
Consolidated EBITDA to interest expense ratio		2.50 to 1.00
Funded debt to consolidated EBITDA ratio		4.00 to 1.00
Pledge Agreement | Unit Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Collateral	we granted a security interest in the limited liability membership interests and other equity interests we own in Superior (which as of the date of this report is 50% of the aggregate outstanding equity interests of Superior)

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
ARO liability, January 1:		$ 69,444	$ 70,170
Accretion of discount		2,393	2,886
Liability incurred		2,632	1,948
Liability settled		(4,493)	(2,694)
Liability sold		(281)	(1,735)
Revision of estimates	[1]	(5,487)	(1,131)
ARO liability, December 31:		64,208	69,444
Less current portion		1,437	1,726
Total long-term ARO liability		$ 62,771	$ 67,718
[1]	Plugging liability estimates were revised in both 2018 and 2017 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments and 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, 2018		Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax expense (benefit) computed by applying the statutory rate	$ (11,290)		$ 21,059	$ (72,386)
State income tax expense (benefit), net of federal benefit	(1,882)		1,655	(5,687)
Deferred tax liability revaluation	0	[1]	(81,307)	0	[1]
Restricted stock shortfall	424		1,867	5,465
Non-controlling interest in Superior	(1,138)		0	0
Statutory depletion and other	(110)		(952)	1,414
Income tax expense (benefit)	$ (13,996)		$ (57,678)	$ (71,194)
[1]	In 2017, the revaluation from the Tax Act.

Income Taxes (Schedule Of Total

Income Taxes (Schedule Of Total Provision For Income Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current taxes, Federal	$ (1,835)	$ 0	$ 0
Current taxes, State	(1,296)	5	15
Current taxes	(3,131)	5	15
Deferred taxes, Federal	(8,741)	(62,788)	(62,923)
Deferred taxes, State	(2,124)	5,105	(8,286)
Deferred taxes	(10,865)	(57,683)	(71,209)
Total provision	$ (13,996)	$ (57,678)	$ (71,194)

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Allowance for losses and nondeductible accruals	$ 27,953		$ 32,242
Net operating loss carryforward	152,112		153,746
Alternative minimum tax and research and development tax credit carryforward	3,574		5,409
Deferred tax assets, total	183,639		191,397
Depreciation, depletion, amortization, and impairment	(291,542)		(324,874)
Investment in Superior	(36,845)		0
Net deferred tax liability	(144,748)		(133,477)
Current deferred tax asset	0		0
Non-current-deferred tax liability	$ (144,748)	$ (133,064)	$ (133,477)

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Federal statutory income tax rate, percent	21.00%		35.00%
Tax benefit from change in enacted tax rate	$ 0	[1]	$ (81,307)	$ 0	[1]
Income tax expense (benefit)	(13,996)		$ (57,678)	$ (71,194)
Operating loss carryforwards	$ 576,900
Operating loss carryforwards expiration	expire from 2021 to 2037
[1]	In 2017, the revaluation from the Tax Act.

Employee Benefit Plans (Details

Employee Benefit Plans (Details) $ in Thousands	May 05, 2004yr	Jan. 01, 1997week	Dec. 31, 2018USD ($)yrshares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares
Defined Benefit Plan Disclosure [Line Items]
Recognized stock compensation expense			$ 17,800	$ 13,300	$ 9,600
Deferred compensation plan			$ 5,132	$ 5,390
Employee Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution of shares, common stock | shares			184,203	155,822	630,039
Recognized stock compensation expense			$ 5,100	$ 4,400	$ 4,000
Separation Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service period, years		20 years
Maximum period benefit, weeks | week		104
Separation benefit plans expense			$ 3,600	$ 2,700	$ 3,100
Special Separation Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service period, years	20 years
Age limit | yr	65
Change Of Control Contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employee contract period, years | yr			3
Employment contract period extension, years			1 year
Grace period following the first anniversary			30 days
Multiple for determination compensation			2.9
Additional period for 401k, years			3 years

Transactions With Related Par_3

Transactions With Related Parties (Schedule of Amount Received in Public and Private Partnerships) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Well supervision and other fees	$ 158	$ 172	$ 254
General and administrative expense reimbursement	$ 0	$ 0	$ 6

Transactions With Related Par_4

Transactions With Related Parties (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)Partnerships	Dec. 31, 2017USD ($)Partnerships	Dec. 31, 2016USD ($)Partnerships	Nov. 30, 2016USD ($)	May 31, 2016USD ($)	Mar. 10, 2016USD ($)
Related Party Transaction [Line Items]
Number of oil and gas limited partnerships for employee investment | Partnerships	13
Partnerships dissolved | Partnerships	0	0	2
Minimum
Related Party Transaction [Line Items]
Interest rate of employee partnerships in oil and gas properties	1.00%
Maximum
Related Party Transaction [Line Items]
Interest rate of employee partnerships in oil and gas properties	15.00%
John Nikkel
Related Party Transaction [Line Items]
John Nikkel senior subordinated note purchase						$ 400,000
Interest John Nikkel received on senior notes				$ 13,250	$ 4,800
G. Bailey Peyton IV
Related Party Transaction [Line Items]
Payments for royalties	$ 900,000	$ 700,000	$ 500,000
Toklan Oil and Gas Company | John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage		25.80%
Revenue from related parties		$ 0
Payments for royalties		$ 0	$ 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		$ 400,000
West Thomas Field Services, LLC | Robert Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage		20.00%
Peyton Royalties, LP | G. Bailey Peyton IV
Related Party Transaction [Line Items]
Related party ownership percentage		99.50%

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognized stock compensation expense	$ 17.8	$ 13.3	$ 9.6
Capitalized stock compensation cost for our oil and natural gas properties	2.1	1.8	2.1
Tax benefit on stock based compensation	$ 4.4	$ 5	$ 3.6

Stock-Based Compensation (Activ

Stock-Based Compensation (Activity Pertaining to Stock Appreciation Rights) (Details) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	0	91,255	131,770
Weighted average price, beginning balance	$ 0	$ 44.31	$ 46.60
Number of shares, granted	0	0	0
Weighted average price, granted		$ 0	$ 0
Number of shares, exercised		0	0
Weighted average price, exercised		$ 0	$ 0
Number of shares, forfeited		(91,255)	(40,515)
Weighted average price, forfeited		$ 44.31	$ 51.76
Number of shares, ending balance	0	0	91,255
Weighted average price, ending balance		$ 0	$ 44.31

Stock-Based Compensation (Act_2

Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	1,363,987	1,301,865	1,213,822
Weighted average price, beginning balance	$ 21.25	$ 23.32	$ 41.29
Number of shares, granted	1,234,943	659,172	646,451
Weighted average price, granted	$ 20.52	$ 26.07	$ 5.62
Number of shares, vested	(679,814)	(517,689)	(425,195)
Weighted average price, vested	$ 24.30	$ 29.87	$ 43.47
Number of shares, forfeited	(42,108)	(79,361)	(133,213)
Weighted average price, forfeited	$ 19.80	$ 38.87	$ 36.87
Number of shares, ending balance	1,877,008	1,363,987	1,301,865
Weighted average price, ending balance	$ 19.70	$ 21.25	$ 23.32
Restricted Stock - Non-employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	117,714	111,816	42,064
Weighted average price, beginning balance	$ 16.03	$ 17.21	$ 41.83
Number of shares, granted	44,312	49,104	90,000
Weighted average price, granted	$ 19.86	$ 17.92	$ 12.02
Number of shares, vested	(54,981)	(43,206)	(20,248)
Weighted average price, vested	$ 17.08	$ 21.24	$ 43.46
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$ 0	$ 0	$ 0
Number of shares, ending balance	107,045	117,714	111,816
Weighted average price, ending balance	$ 17.07	$ 16.03	$ 17.21
Time Vested | Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	915,558	929,737	936,662
Number of shares, granted	844,498	485,799	494,078
Number of shares, vested	(470,171)	(455,570)	(425,195)
Number of shares, forfeited	(21,002)	(44,408)	(75,808)
Number of shares, ending balance	1,268,883	915,558	929,737
Performance Shares | Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	448,429	372,128	277,160
Number of shares, granted	390,445	173,373	152,373
Number of shares, vested	(209,643)	(62,119)	0
Number of shares, forfeited	(21,106)	(34,953)	(57,405)
Number of shares, ending balance	608,125	448,429	372,128

Stock-Based Compensation (Act_3

Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) - Directors Plan - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	87,500	108,500	129,500
Weighted average price, beginning balance	$ 51.34	$ 52.56	$ 54.15
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0	$ 0	$ 0
Number of shares, exercised	0	0	0
Weighted average price, exercised	$ 0	$ 0	$ 0
Number of shares, forfeited	(21,000)	(21,000)	(21,000)
Weighted average price, forfeited	$ 73.26	$ 57.63	$ 62.40
Number of shares, ending balance	66,500	87,500	108,500
Weighted average price, ending balance	$ 44.42	$ 51.34	$ 52.56

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, 2018$ / 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	10 months 24 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	28,000
Outstanding and exercisable options weighted average remaining contractual life, years	2 years 3 months 18 days
Outstanding and exercisable options, weighted average exercise price	$ 53.81

Stock-Based Compensation (Narra

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 16.1
Unrecognized compensation cost, expect to be capitalized	$ 1.9
Weighted average years over which this cost will be recognized	9 months 18 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	0	0	91,255
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance				7,230,000
Number of shares, ending balance	1,984,053
Vesting Period	3 years
Grant date fair value	$ 24.7	$ 17.4	$ 4.5
Number of shares, vested	(734,795)
Exercised intrinsic value	$ 15
Exercisable options intrinsic value	$ 28.3
Restricted stock weighted average remaining contractual term, years	1 year 1 month 6 days
Directors Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Vesting Period	6 months
Exercisable options intrinsic value	$ 0
Director option awards	3,500
Weighted average remaining contractual term, years	1 year 6 months
Stock Performance Measures [Member] | Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	0.00%
Stock Performance Measures [Member] | Restricted Stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	200.00%
Cash flow to total assets performance [Member] | Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	0.00%
Cash flow to total assets performance [Member] | Restricted Stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	200.00%
Cash flow to total assets performance [Member] | 2018 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	69.00%
Cash flow to total assets performance [Member] | 2017 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	99.00%
Cash flow to total assets performance [Member] | 2016 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	200.00%
Year one [Member] | Cash flow to total assets performance [Member] | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%
Year two and three [Member] | Cash flow to total assets performance [Member] | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%

Derivatives (Schedule of Non-de

Derivatives (Schedule of Non-designated Hedges Outstanding) (Details)	12 Months Ended
	Dec. 31, 2018MMBTU$ / Unitbbl
Natural gas | Swap | If Nymex | Jan'19 - Mar'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	50,000
Swap Price	3.440
Natural gas | Swap | If Nymex | Apr'19 - Dec'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	40,000
Swap Price	2.900
Natural gas | Basis Swap | PEPL | Jan'19 - Dec'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	20,000
Swap Price	(0.659)
Natural gas | Basis Swap | NGPL Midcon | Jan'19 - Dec'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	10,000
Swap Price	(0.625)
Natural gas | Basis Swap | NGPL Texok | Jan'19 - Dec'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	30,000
Swap Price	(0.265)
Natural gas | Basis Swap | NGPL Texok | Jan'20 - Dec'20
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	30,000
Swap Price	(0.275)
Natural gas | Collar | If Nymex | Jan'19 - Dec'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	20,000
Floor Price	2.63
Ceiling Price	3.03
Natural gas | Three-way collar | If Nymex | Jan'19 - Mar'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	30,000
Floor Price	3.17
Ceiling Price	4.32
Subfloor Price	2.92
Crude Oil | Three-way collar | Wti Nymex | Jan'19 - Dec'19
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Bbl) | bbl	4,000
Floor Price	61.25
Ceiling Price	72.93
Subfloor Price	51.25

Derivatives (Schedule Of Subseq

Derivatives (Schedule Of Subsequent Non-designated Hedges) (Details) - Subsequent to December 31, 2018 - Apr'19- Oct'19 - Natural gas - If Nymex - Swap	2 Months Ended
	Feb. 22, 2019MMBTU$ / Unit
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) | MMBTU	20,000
Swap Price | $ / Unit	2.900

Derivatives (Fair Value Of Deri

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 12,870	$ 721
Non-current derivative assets	0	0
Total derivatives assets	12,870	721
Current derivative liabilities	0	7,763
Non-current derivative liabilities	293	0
Total derivative liabilities	$ 293	$ 7,763

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, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivatives		$ (3,184)	$ 14,732
Cash receipts (payments) on derivatives settled		(22,803)	173
Commodity Contract
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Derivatives	[1]	$ (3,184)	$ 14,732
[1]	Amount s settled during the periods are a loss of $22,803 and a gain of $173, respectively.

Fair Value Measurements (Availa

Fair Value Measurements (Available-for-sale Securities) (Details) - Level 2 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 830	$ 830
Gross Unrealized Gains	0	102
Gross Unrealized Losses	636	0
Estimated Fair Value	$ 194	$ 932

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	$ 12,600
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	12,870	$ 721
Liabilities	(293)	(7,763)
Financial assets (liabilities)	12,577	(7,042)
Commodity Contract | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	3,225	2,137
Liabilities	(1,278)	(8,973)
Financial assets (liabilities)	1,947	(6,836)
Commodity Contract | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	10,964	3,344
Liabilities	(334)	(3,550)
Financial assets (liabilities)	10,630	(206)
Commodity Contract | Effect of Netting
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	(1,319)	(4,760)
Liabilities	1,319	4,760
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, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Beginning of period		$ (206)	$ (7,122)
Included in earnings	[1]	4,159	7,791
Settlements		6,677	(875)
End of period		10,630	(206)
Total gains for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period		$ 10,836	$ 6,916
[1]	Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives.

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) - Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)$ / Unit
Crude Oil | Three-way collar
Fair Value | $	$ 10,592	[1]
Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Crude Oil | Minimum | Three-way collar
Average Forward Price	0
Crude Oil | Maximum | Three-way collar
Average Forward Price	19.44
Natural gas | Collar
Fair Value | $	$ (334)	[1]
Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Natural gas | Three-way collar
Fair Value | $	$ 372	[1]
Valuation Technique(s)	Discounted cash flow	[1]
Unobservable Input	Forward commodity price curve	[1]
Natural gas | Minimum | Collar
Average Forward Price	0
Natural gas | Minimum | Three-way collar
Average Forward Price	0
Natural gas | Maximum | Collar
Average Forward Price	0.38
Natural gas | Maximum | Three-way collar
Average Forward Price	0.43
[1]	The commodity contracts detailed in this category include non-exchange-traded crude and natural gas three-way collars and natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Option, Qualitative Disclosures Related to Election [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0
Transfers between Level 2 and Level 3 assets (liabilities)	0
Level 2
Fair Value, Option, Qualitative Disclosures Related to Election [Line Items]
6.625% senior subordinated notes due 2021	644,500	$ 642,300
Estimated fair value of long-term debt	$ 600,500	$ 649,700

Commitments And Contingencies (

Commitments And Contingencies (Details)	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Other Commitments [Line Items]
Future minimum rental payments under leases, year one	$ 4,600,000
Future minimum rental payments under leases, year two	1,700,000
Future minimum rental payments under leases, year three	400,000
Rent expense incurred	$ 9,900,000	$ 8,800,000	$ 11,100,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
2,019	$ 6,168,000
2,020	6,168,000
2,021	3,768,000
Maintenance	4,089,000
Interest	635,000
Capital leases, future minimum payments, average annual payment	$ 4,300,000
Capital lease fair market value percentage for purchase	10.00%
Repurchase of limited units outstanding	20.00%
Repurchase of limited units outstanding amount	$ 1,700	$ 2,900	$ 5,000
Drilling Equipment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 9,200,000

Variable Interest Entity Arra_3

Variable Interest Entity Arrangements (Schedule of Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018		Jan. 01, 2018	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 6,452			$ 701		$ 893	$ 835
Accounts receivable	119,397			111,512
Prepaid expenses and other	11,356			6,172
Total current assets	175,113			119,672
Property and Equipment:
Gas gathering and processing equipment	767,388			726,236
Transportation equipment	29,524			29,631
Property, plant and equipment, gross, total	8,615,042			8,534,192
Less accumulated depreciation, depletion, amortization, and impairment	6,182,726			6,151,450
Net property and equipment	2,432,316			2,382,742
Other assets	27,816		$ 27,028	16,230
Total assets	2,698,053	[1]		2,581,452	[1]	$ 2,479,303
Current liabilities:
Accounts payable	149,945			112,648
Accrued liabilities	49,664			48,523
Current portion of other long-term liabilities	14,250		15,750	13,002
Total current liabilities	213,859			181,936
Long-term debt less debt issuance costs	644,475			820,276
Other long-term liabilities	101,234		$ 109,940	$ 100,203
VIE
Current assets:
Cash and cash equivalents	5,841
Accounts receivable	33,207
Prepaid expenses and other	2,693
Total current assets	41,741
Property and Equipment:
Gas gathering and processing equipment	767,388
Transportation equipment	3,086
Property, plant and equipment, gross, total	770,474
Less accumulated depreciation, depletion, amortization, and impairment	364,740
Net property and equipment	405,734
Other assets	15,907
Total assets	463,382
Current liabilities:
Accounts payable	32,214
Accrued liabilities	3,688
Current portion of other long-term liabilities	6,875
Total current liabilities	42,777
Long-term debt less debt issuance costs	0
Other long-term liabilities	14,687
Total liabilities	$ 57,464
[1]	Unit Corporation's consolidated total assets as of December 31, 2018 include current and long-term assets of its variable interest entity (VIE) (Superior) of $41.7 million and $421.6 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 16 – Variable Interest Entity Arrangements.

Variable Interest Entity Arra_4

Variable Interest Entity Arrangements (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Variable Interest Entity [Line Items]
Date Involvement Began	Apr. 3, 2018
Superior Pipeline Company, L.L.C. [Member]
Variable Interest Entity [Line Items]
Date Involvement Began	Apr. 3, 2018
Methodology for Determining Whether Entity is Primary Beneficiary	The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA houses the power to direct the activities that most significantly impact Superior's operating performance. The MSA is a separate variable interest. Unit through the MSA has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most significantly impact the entity’s economic performance. Because of this, Unit is considered the primary beneficiary.
Lack of Recourse	Superior's creditors have no recourse to our general credit.
Superior Pipeline Company, L.L.C. [Member] | SPC Midstream Operating, L.L.C. [Member]
Variable Interest Entity [Line Items]
Monthly service fee	$ 250
Superior Pipeline Company, L.L.C. [Member] | SP Investor Holdings, LLC [Member]
Variable Interest Entity [Line Items]
Ownership percentage	50.00%

Equity (Schedule of Accumulated

Equity (Schedule of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Accumulated Other Comprehensive Income (Loss) [Abstract]
Unrealized appreciation (depreciation) on securities, before tax		$ (738)	$ 102	$ 0
Tax benefit (expense)	[1]	181	(39)	0
Unrealized appreciation (depreciation) on securities, net of tax		$ (557)	$ 63	$ 0
[1]	In 2018, due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Equity (Reclassification out of

Equity (Reclassification out of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018	Dec. 31, 2015
New Accounting Pronouncement, Early Adoption [Line Items]
Beginning Balance		$ 63	$ 0	$ 0
Unrealized appreciation (depreciation) before reclassifications	[1]	(557)	63	0
Amounts reclassified from accumulated other comprehensive income		0	0	0
Net current-period other comprehensive income (loss)		(557)	63	0
Ending Balance		$ (481)	$ 63	0
ASU 2018-02 effect
New Accounting Pronouncement, Early Adoption [Line Items]
Adjustment due to ASU 2018-02	[1]			$ 0	$ 13	$ 0
[1]	In 2018, due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Apr. 04, 2017
Class of Stock [Line Items]
Common stock, par value	$ 0.2	$ 0.2
Common stock, shares issued	54,055,600	52,880,134
Proceeds from common stock issued, net of issue costs	$ 0	$ 18,623	$ 0
At-the-Market Common Stock Program [Member]
Class of Stock [Line Items]
Common stock, par value					$ 0.20
Aggregate Offering Price					$ 100,000
Commission of the gross sales price by share paid percentage					2.00%
Common stock, shares issued	787,547			787,547

Industry Segment Information (R

Industry Segment Information (Revenue From Different Segments) (Details) - USD ($) $ in Thousands		3 Months Ended										12 Months Ended
		Dec. 31, 2018		Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Revenues
Oil and natural gas												$ 423,059		$ 357,744		$ 294,221
Contract drilling												196,492		174,720		122,086
Gas gathering and processing												223,730		207,176		185,870
Total revenues		$ 214,788		$ 220,058	$ 203,303	$ 205,132	$ 204,847		$ 188,488	$ 170,581	$ 175,724	843,281		739,640		602,177
Operating costs:
Oil and natural gas												131,675		130,789		120,184
Contract drilling												131,385		122,600		88,154
Gas gathering and processing												167,836		155,483		137,609
Total operating costs												430,896		408,872		345,947
Depreciation, depletion, and amortization												243,605		209,257		208,353
Impairments												147,884		0		161,563
Total expenses												822,385		618,129		715,863
General and administrative												38,707		38,087		33,337
Gain (loss) on disposition of assets												704		327		2,540
Income (loss) from operations												(17,107)		83,751		(144,483)
Gain (loss) on derivatives												(3,184)		14,732		(22,813)
Interest expense, net												(33,494)		(38,334)		(39,829)
Other												22		21		307
Income (loss) before income taxes												(53,763)		60,170		(206,818)
Identifiable assets:
Oil and natural gas		1,350,830	[1]				1,127,900	[2]				1,350,830	[1]	1,127,900	[2]	965,159	[3]
Contract drilling		806,611					933,063					806,611		933,063		941,676
Gas gathering and processing		461,828					438,571					461,828		438,571		461,600
Total identifiable assets		2,619,269	[4]				2,499,534	[5]				2,619,269	[4]	2,499,534	[5]	2,368,435	[6]
Corporate land and building		55,505					56,854					55,505		56,854		58,188
Other corporate assets		23,279	[7]				25,064	[8]				23,279	[7]	25,064	[8]	52,680	[9]
Total assets		2,698,053	[10]				2,581,452	[10]				2,698,053	[10]	2,581,452	[10]	2,479,303
Capital expenditures:
Total capital expenditures												488,780		332,280		142,155
Oil and Natural Gas
Revenues
Oil and natural gas												423,059	[11]	357,744		294,221
Contract drilling												0	[11]	0		0
Gas gathering and processing												0	[11]	0		0
Total revenues												423,059	[11]	357,744		294,221
Operating costs:
Oil and natural gas												136,870		135,532		126,739
Contract drilling												0		0		0
Gas gathering and processing												0		0		0
Total operating costs												136,870		135,532		126,739
Depreciation, depletion, and amortization												133,584		101,911		113,811
Impairments	[12]															161,563
Total expenses												270,454		237,443		402,113
General and administrative												0		0		0
Gain (loss) on disposition of assets												139		228		(324)
Income (loss) from operations												152,744		120,529		(108,216)
Gain (loss) on derivatives												0		0		0
Interest expense, net												0		0		0
Other												0		0		0
Income (loss) before income taxes												152,744		120,529		(108,216)
Identifiable assets:
Oil and natural gas		1,357,779	[1]				1,134,080	[2]				1,357,779	[1]	1,134,080	[2]	970,238	[3]
Contract drilling		0					0					0		0		0
Gas gathering and processing		0					0					0		0		0
Total identifiable assets		1,357,779	[4]				1,134,080	[5]				1,357,779	[4]	1,134,080	[5]	970,238	[6]
Corporate land and building		0					0					0		0		0
Other corporate assets		0	[7]				0	[8]				0	[7]	0	[8]	0	[9]
Total assets		1,357,779					1,134,080					1,357,779		1,134,080		970,238
Capital expenditures:
Total capital expenditures												367,335		270,443		89,562
Drilling
Revenues
Oil and natural gas												0	[11]	0		0
Contract drilling												218,982	[11]	188,172		122,086
Gas gathering and processing												0	[11]	0		0
Total revenues												218,982	[11]	188,172		122,086
Operating costs:
Oil and natural gas												0		0		0
Contract drilling												150,834		134,432		88,154
Gas gathering and processing												0		0		0
Total operating costs												150,834		134,432		88,154
Depreciation, depletion, and amortization												57,508		56,370		46,992
Impairments												147,884	[13]			0	[12]
Total expenses												356,226		190,802		135,146
General and administrative												0		0		0
Gain (loss) on disposition of assets												425		(776)		3,184
Income (loss) from operations												(136,819)		(3,406)		(9,876)
Gain (loss) on derivatives												0		0		0
Interest expense, net												0		0		0
Other												0		0		0
Income (loss) before income taxes												(136,819)		(3,406)		(9,876)
Identifiable assets:
Oil and natural gas		0	[1]				0	[2]				0	[1]	0	[2]	0	[3]
Contract drilling		806,696					933,063					806,696		933,063		941,676
Gas gathering and processing		0					0					0		0		0
Total identifiable assets		806,696	[4]				933,063	[5]				806,696	[4]	933,063	[5]	941,676	[6]
Corporate land and building		0					0					0		0		0
Other corporate assets		0	[7]				0	[8]				0	[7]	0	[8]	0	[9]
Total assets		806,696					933,063					806,696		933,063		941,676
Capital expenditures:
Total capital expenditures												75,510		36,148		19,134
Mid-Stream
Revenues
Oil and natural gas												0	[11]	0		0
Contract drilling												0	[11]	0		0
Gas gathering and processing												312,417	[11]	277,049		237,785
Total revenues												312,417	[11]	277,049		237,785
Operating costs:
Oil and natural gas												0		0		0
Contract drilling												0		0		0
Gas gathering and processing												251,328		220,613		182,969
Total operating costs												251,328		220,613		182,969
Depreciation, depletion, and amortization												44,834		43,499		45,715
Impairments												0	[13]			0	[12]
Total expenses												296,162		264,112		228,684
General and administrative												0		0		0
Gain (loss) on disposition of assets												110		25		(302)
Income (loss) from operations												16,365		12,962		8,799
Gain (loss) on derivatives												0		0		0
Interest expense, net												(1,214)		0		0
Other												0		0		0
Income (loss) before income taxes												15,151		12,962		8,799
Identifiable assets:
Oil and natural gas		0	[1]				0	[2]				0	[1]	0	[2]	0	[3]
Contract drilling		0					0					0		0		0
Gas gathering and processing		466,851					439,369					466,851		439,369		462,330
Total identifiable assets		466,851	[4]				439,369	[5]				466,851	[4]	439,369	[5]	462,330	[6]
Corporate land and building		0					0					0		0		0
Other corporate assets		0	[7]				0	[8]				0	[7]	0	[8]	0	[9]
Total assets		466,851					439,369					466,851		439,369		462,330
Capital expenditures:
Total capital expenditures												44,810		22,168		16,796
Other Segments
Revenues
Oil and natural gas												0	[11]	0		0
Contract drilling												0	[11]	0		0
Gas gathering and processing												0	[11]	0		0
Total revenues												0	[11]	0		0
Operating costs:
Oil and natural gas												0		0		0
Contract drilling												0		0		0
Gas gathering and processing												0		0		0
Total operating costs												0		0		0
Depreciation, depletion, and amortization												7,679		7,477		1,835
Impairments												0	[13]			0	[12]
Total expenses												7,679		7,477		1,835
General and administrative												38,707		38,087		33,337
Gain (loss) on disposition of assets												30		850		(18)
Income (loss) from operations												(46,356)		(44,714)		(35,190)
Gain (loss) on derivatives												(3,184)		14,732		(22,813)
Interest expense, net												(32,280)		(38,334)		(39,829)
Other												22		21		307
Income (loss) before income taxes												(81,798)		(68,295)		(97,525)
Identifiable assets:
Oil and natural gas		0	[1]				0	[2]				0	[1]	0	[2]	0	[3]
Contract drilling		0					0					0		0		0
Gas gathering and processing		0					0					0		0		0
Total identifiable assets		0	[4]				0	[5]				0	[4]	0	[5]	0	[6]
Corporate land and building		55,505					56,854					55,505		56,854		58,188
Other corporate assets		25,566	[7]				25,064	[8]				25,566	[7]	25,064	[8]	52,680	[9]
Total assets		81,071					81,918					81,071		81,918		110,868
Capital expenditures:
Total capital expenditures												1,125		3,521		16,663
Intersubsegment Eliminations
Revenues
Oil and natural gas												0		0		0
Contract drilling												(22,490)		(13,452)		0
Gas gathering and processing												(88,687)		(69,873)		(51,915)
Total revenues												(111,177)		(83,325)		(51,915)
Operating costs:
Oil and natural gas												(5,195)		(4,743)		(6,555)
Contract drilling												(19,449)		(11,832)		0
Gas gathering and processing												(83,492)		(65,130)		(45,360)
Total operating costs												(108,136)		(81,705)		(51,915)
Depreciation, depletion, and amortization												0		0		0
Impairments												0	[13]			0	[12]
Total expenses												(108,136)		(81,705)		(51,915)
General and administrative												0		0		0
Gain (loss) on disposition of assets												0		0		0
Income (loss) from operations												(3,041)		(1,620)		0
Gain (loss) on derivatives												0		0		0
Interest expense, net												0		0		0
Other												0		0		0
Income (loss) before income taxes												(3,041)		(1,620)		0
Identifiable assets:
Oil and natural gas		(6,949)	[1]				(6,180)	[2]				(6,949)	[1]	(6,180)	[2]	(5,079)	[3]
Contract drilling		(85)					0					(85)		0		0
Gas gathering and processing		(5,023)					(798)					(5,023)		(798)		(730)
Total identifiable assets		(12,057)	[4]				(6,978)	[5]				(12,057)	[4]	(6,978)	[5]	(5,809)	[6]
Corporate land and building		0					0					0		0		0
Other corporate assets		(2,287)	[7]				0	[8]				(2,287)	[7]	0	[8]	0	[9]
Total assets		$ (14,344)					$ (6,978)					(14,344)		(6,978)		(5,809)
Capital expenditures:
Total capital expenditures												$ 0		$ 0		$ 0
[1]	Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
[2]	Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
[3]	Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
[4]	Identifiable assets are those used in Unit’s operations in each industry segment.
[5]	Identifiable assets are those used in Unit’s operations in each industry segment.
[6]	Identifiable assets are those used in Unit’s operations in each industry segment.
[7]	Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
[8]	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
[9]	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
[10]	Unit Corporation's consolidated total assets as of December 31, 2018 include current and long-term assets of its variable interest entity (VIE) (Superior) of $41.7 million and $421.6 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 16 – Variable Interest Entity Arrangements.
[11]	The revenues for oil and na tural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
[12]	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax).
[13]	Impairment for contract drilling equipment includes a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

Selected Quarterly Financial _3

Selected Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended												12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues		$ 214,788	$ 220,058	$ 203,303	$ 205,132	$ 204,847		$ 188,488		$ 170,581		$ 175,724		$ 843,281	$ 739,640	$ 602,177
Gross income (loss)	[1]	(108,068)	49,216	40,915	38,833	37,211		27,181		24,462		32,657
Net income (loss) attributable to Unit Corporation		$ (77,840)	$ 18,899	$ 5,788	$ 7,865	$ 89,155		$ 3,705		$ 9,059		$ 15,929		$ (45,288)	$ 117,848	$ (135,624)
Net income (loss) attributable to Unit Corporation per common share:
Basic		$ (1.49)	$ 0.36	$ 0.11	$ 0.15	$ 1.74	[2]	$ 0.07	[2]	$ 0.18	[2]	$ 0.32	[2]	$ (0.87)	$ 2.31	$ (2.71)
Diluted		$ (1.49)	$ 0.36	$ 0.11	$ 0.15	$ 1.71	[2]	$ 0.07	[2]	$ 0.17	[2]	$ 0.31	[2]	$ (0.87)	$ 2.28	$ (2.71)
[1]	Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss).
[2]	The earnings per share for the year's four quarters does not equal annual income per share.

Supplemental Condensed Consol_3

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Balance Sheets) (Details) - USD ($) $ in Thousands		Dec. 31, 2018		Jan. 01, 2018	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 6,452			$ 701		$ 893	$ 835
Accounts receivable		119,397			111,512
Materials and supplies		473			505
Current derivative assets		12,870			721
Current income taxes receivable		2,054			61
Assets held for sale		22,511			0
Prepaid expenses and other		11,356			6,172
Total current assets		175,113			119,672
Oil and Gas Property [Abstract]
Proved properties		6,018,568			5,712,813		5,446,305
Unproved properties not being amortized		330,216			296,764		314,867
Drilling equipment		1,284,419			1,593,611
Gas gathering and processing equipment		767,388			726,236
Saltwater disposal systems		68,339			62,618
Corporate land and building		59,081			59,080
Transportation equipment		29,524			29,631
Other		57,507			53,439
Property, plant and equipment, gross, total		8,615,042			8,534,192
Less accumulated depreciation, depletion, amortization, and impairment		6,182,726			6,151,450
Net property and equipment		2,432,316			2,382,742
Intercompany receivable		0			0
Goodwill		62,808			62,808
Investments		1,500			1,500
Other assets		26,316			14,730
Total assets		2,698,053	[1]		2,581,452	[1]	2,479,303
Current liabilities:
Accounts payable		149,945			112,648
Accrued liabilities		49,664			48,523
Current derivative liabilities		0			7,763
Current portion of other long-term liabilities		14,250		$ 15,750	13,002
Total current liabilities		213,859			181,936
Intercompany debt		0			0
Long-term debt					178,000
Bonds payable less debt issuance costs		644,475			642,276
Non-current derivative liabilities		293			0
Other long-term liabilities		101,234		109,940	100,203
Deferred income taxes		144,748		133,064	133,477
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		10,414			10,280
Capital in excess of par value		628,108			535,815
Contributions from Unit		0
Accumulated other comprehensive income (loss)		(481)		76	63		0	0
Retained earnings		752,840		$ 798,128	799,402
Total shareholders' equity attributable to Unit Corporation		1,390,881			1,345,560
Non-controlling interests in consolidated subsidiaries		202,563			0
Total shareholders' equity		1,593,444			1,345,560		1,194,070	1,313,580
Total liabilities and shareholders' equity	[1]	2,698,053			2,581,452
Consolidating Adjustments
Current assets:
Cash and cash equivalents		0			0		0	0
Accounts receivable		(14,344)			(6,978)
Materials and supplies		0			0
Current derivative assets		0			0
Current income taxes receivable		0			0
Assets held for sale		0
Prepaid expenses and other		0			0
Total current assets		(14,344)			(6,978)
Oil and Gas Property [Abstract]
Proved properties		0			0
Unproved properties not being amortized		0			0
Drilling equipment		0			0
Gas gathering and processing equipment		0			0
Saltwater disposal systems		0			0
Corporate land and building		0			0
Transportation equipment		0			0
Other		0			0
Property, plant and equipment, gross, total		0			0
Less accumulated depreciation, depletion, amortization, and impairment		0			0
Net property and equipment		0			0
Intercompany receivable		(950,916)			(1,155,725)
Goodwill		0			0
Investments		(1,160,444)			(1,044,709)
Other assets		0			0
Total assets		(2,125,704)			(2,207,412)
Current liabilities:
Accounts payable		(13,576)			(6,978)
Accrued liabilities		(468)			0
Current derivative liabilities					0
Current portion of other long-term liabilities		0			0
Total current liabilities		(14,044)			(6,978)
Intercompany debt		(950,916)			(1,155,725)
Long-term debt					0
Bonds payable less debt issuance costs		0			0
Non-current derivative liabilities		0
Other long-term liabilities		(300)			0
Deferred income taxes		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		0			0
Capital in excess of par value		(242,963)			(61,470)
Contributions from Unit		(792)
Accumulated other comprehensive income (loss)		0			0
Retained earnings		(916,689)			(983,239)
Total shareholders' equity attributable to Unit Corporation		(1,160,444)			(1,044,709)
Non-controlling interests in consolidated subsidiaries		0			0
Total shareholders' equity		(1,160,444)			(1,044,709)
Total liabilities and shareholders' equity		(2,125,704)			(2,207,412)
Parent
Current assets:
Cash and cash equivalents		403			510		517	510
Accounts receivable		2,539			154
Materials and supplies		0			0
Current derivative assets		12,870			721
Current income taxes receivable		243			61
Assets held for sale		0
Prepaid expenses and other		5,103			2,925
Total current assets		21,158			4,371
Oil and Gas Property [Abstract]
Proved properties		0			0
Unproved properties not being amortized		0			0
Drilling equipment		0			0
Gas gathering and processing equipment		0			0
Saltwater disposal systems		0			0
Corporate land and building		0			0
Transportation equipment		9,273			9,270
Other		28,584			28,039
Property, plant and equipment, gross, total		37,857			37,309
Less accumulated depreciation, depletion, amortization, and impairment		27,504			21,268
Net property and equipment		10,353			16,041
Intercompany receivable		950,916			1,155,725
Goodwill		0			0
Investments		1,160,444			1,044,709
Other assets		5,115			5,373
Total assets		2,147,986			2,226,219
Current liabilities:
Accounts payable		8,697			13,124
Accrued liabilities		28,230			26,165
Current derivative liabilities					7,763
Current portion of other long-term liabilities		812			657
Total current liabilities		37,739			47,709
Intercompany debt		0			0
Long-term debt					178,000
Bonds payable less debt issuance costs		644,475			642,276
Non-current derivative liabilities		293
Other long-term liabilities		13,134			11,257
Deferred income taxes		60,983			1,480
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		10,414			10,280
Capital in excess of par value		628,108			535,815
Contributions from Unit		0
Accumulated other comprehensive income (loss)		0			0
Retained earnings		752,840			799,402
Total shareholders' equity attributable to Unit Corporation		1,391,362			1,345,497
Non-controlling interests in consolidated subsidiaries		0			0
Total shareholders' equity		1,391,362			1,345,497
Total liabilities and shareholders' equity		2,147,986			2,226,219
Combined Guarantor Subsidiaries
Current assets:
Cash and cash equivalents		208			191		376	325
Accounts receivable		94,526			89,622
Materials and supplies		473			505
Current derivative assets		0			0
Current income taxes receivable		1,811			0
Assets held for sale		22,511
Prepaid expenses and other		3,560			2,370
Total current assets		123,089			92,688
Oil and Gas Property [Abstract]
Proved properties		6,018,568			5,712,813
Unproved properties not being amortized		330,216			296,764
Drilling equipment		1,284,419			1,593,611
Gas gathering and processing equipment		0			0
Saltwater disposal systems		68,339			62,618
Corporate land and building		59,081			59,080
Transportation equipment		17,165			17,423
Other		28,923			25,400
Property, plant and equipment, gross, total		7,806,711			7,767,709
Less accumulated depreciation, depletion, amortization, and impairment		5,790,481			5,807,757
Net property and equipment		2,016,230			1,959,952
Intercompany receivable		0			0
Goodwill		62,808			62,808
Investments		1,500			1,500
Other assets		5,293			6,328
Total assets		2,208,920			2,123,276
Current liabilities:
Accounts payable		122,610			87,514
Accrued liabilities		16,409			19,134
Current derivative liabilities					0
Current portion of other long-term liabilities		6,563			8,501
Total current liabilities		145,582			115,149
Intercompany debt		948,707			870,582
Long-term debt					0
Bonds payable less debt issuance costs		0			0
Non-current derivative liabilities		0
Other long-term liabilities		73,713			77,566
Deferred income taxes		83,765			85,443
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		0			0
Capital in excess of par value		45,921			45,921
Contributions from Unit		0
Accumulated other comprehensive income (loss)		(481)			63
Retained earnings		911,713			928,552
Total shareholders' equity attributable to Unit Corporation		957,153			974,536
Non-controlling interests in consolidated subsidiaries		0			0
Total shareholders' equity		957,153			974,536
Total liabilities and shareholders' equity		2,208,920			2,123,276
Combined Non-Guarantor Subsidiaries
Current assets:
Cash and cash equivalents		5,841			0		$ 0	$ 0
Accounts receivable		36,676			28,714
Materials and supplies		0			0
Current derivative assets		0			0
Current income taxes receivable		0			0
Assets held for sale		0
Prepaid expenses and other		2,693			877
Total current assets		45,210			29,591
Oil and Gas Property [Abstract]
Proved properties		0			0
Unproved properties not being amortized		0			0
Drilling equipment		0			0
Gas gathering and processing equipment		767,388			726,236
Saltwater disposal systems		0			0
Corporate land and building		0			0
Transportation equipment		3,086			2,938
Other		0			0
Property, plant and equipment, gross, total		770,474			729,174
Less accumulated depreciation, depletion, amortization, and impairment		364,741			322,425
Net property and equipment		405,733			406,749
Intercompany receivable		0			0
Goodwill		0			0
Investments		0			0
Other assets		15,908			3,029
Total assets		466,851			439,369
Current liabilities:
Accounts payable		32,214			18,988
Accrued liabilities		5,493			3,224
Current derivative liabilities					0
Current portion of other long-term liabilities		6,875			3,844
Total current liabilities		44,582			26,056
Intercompany debt		2,209			285,143
Long-term debt					0
Bonds payable less debt issuance costs		0			0
Non-current derivative liabilities		0
Other long-term liabilities		14,687			11,380
Deferred income taxes		0			46,554
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		0			0
Capital in excess of par value		197,042			15,549
Contributions from Unit		792
Accumulated other comprehensive income (loss)		0			0
Retained earnings		4,976			54,687
Total shareholders' equity attributable to Unit Corporation		202,810			70,236
Non-controlling interests in consolidated subsidiaries		202,563			0
Total shareholders' equity		405,373			70,236
Total liabilities and shareholders' equity		$ 466,851			$ 439,369
[1]	Unit Corporation's consolidated total assets as of December 31, 2018 include current and long-term assets of its variable interest entity (VIE) (Superior) of $41.7 million and $421.6 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2018 include current and long-term liabilities of the VIE of $42.8 million and $14.7 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 16 – Variable Interest Entity Arrangements.

Supplemental Condensed Consol_4

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Balance Sheets) (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Accounts receivable, allowance for doubtful accounts	$ 2,531	$ 2,450
Common stock, shares issued	54,055,600	52,880,134
Common stock, shares authorized	175,000,000	175,000,000
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Accounts receivable, allowance for doubtful accounts	$ 0	$ 0
Common stock, shares issued	0	0
Common stock, shares authorized	0	0
Parent
Condensed Financial Statements, Captions [Line Items]
Accounts receivable, allowance for doubtful accounts	$ 1,205	$ 0
Common stock, shares issued	54,055,600	52,880,134
Common stock, shares authorized	175,000,000	175,000,000
Combined Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Accounts receivable, allowance for doubtful accounts	$ 1,326	$ 1,245
Common stock, shares issued	0	0
Common stock, shares authorized	0	0
Combined Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Accounts receivable, allowance for doubtful accounts	$ 0	$ 1,205
Common stock, shares issued	0	0
Common stock, shares authorized	0	0

Supplemental Condensed Consol_5

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Operation) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 214,788	$ 220,058	$ 203,303	$ 205,132	$ 204,847	$ 188,488	$ 170,581	$ 175,724	$ 843,281	$ 739,640	$ 602,177
Expenses
Operating costs									430,896	408,872	345,947
Depreciation, depletion, and amortization									243,605	209,257	208,353
Impairments									147,884	0	161,563
General and administrative									38,707	38,087	33,337
Gain on disposition of assets									(704)	(327)	(2,540)
Total operating expenses									860,388	655,889	746,660
Income (loss) from operations									(17,107)	83,751	(144,483)
Interest, net									(33,494)	(38,334)	(39,829)
Gain (loss) on derivatives									(3,184)	14,732	(22,813)
Other									22	21	307
Income (loss) before income taxes									(53,763)	60,170	(206,818)
Income tax expense (benefit)									(13,996)	(57,678)	(71,194)
Equity in net earnings from investment in subsidiaries, net of taxes									0	0	0
Net income (loss)									(39,767)	117,848	(135,624)
Less: net income attributable to non-controlling interest									5,521	0	0
Net income (loss) attributable to Unit Corporation	$ (77,840)	$ 18,899	$ 5,788	$ 7,865	$ 89,155	$ 3,705	$ 9,059	$ 15,929	(45,288)	117,848	(135,624)
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Revenues									(111,177)	(83,325)	(51,915)
Expenses
Operating costs									(108,136)	(81,705)	(51,915)
Depreciation, depletion, and amortization									0	0	0
Impairments									0		0
General and administrative									0	0	0
Gain on disposition of assets									0	0	0
Total operating expenses									(108,136)	(81,705)	(51,915)
Income (loss) from operations									(3,041)	(1,620)	0
Interest, net									0	0	0
Gain (loss) on derivatives									0	0	0
Other									0	0	0
Income (loss) before income taxes									(3,041)	(1,620)	0
Income tax expense (benefit)									0	0	0
Equity in net earnings from investment in subsidiaries, net of taxes									14,904	(134,768)	95,994
Net income (loss)									11,863	(136,388)	95,994
Less: net income attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Unit Corporation									11,863	(136,388)	95,994
Parent
Condensed Financial Statements, Captions [Line Items]
Revenues									0	0	0
Expenses
Operating costs									0	0	0
Depreciation, depletion, and amortization									7,679	7,477	1,835
Impairments									0		0
General and administrative									0	0	0
Gain on disposition of assets									(30)	(850)	18
Total operating expenses									7,649	6,627	1,853
Income (loss) from operations									(7,649)	(6,627)	(1,853)
Interest, net									(32,280)	(37,645)	(38,995)
Gain (loss) on derivatives									(3,184)	14,732	(22,813)
Other									22	21	0
Income (loss) before income taxes									(43,091)	(29,519)	(63,661)
Income tax expense (benefit)									(12,707)	(12,599)	(24,031)
Equity in net earnings from investment in subsidiaries, net of taxes									(14,904)	134,768	(95,994)
Net income (loss)									(45,288)	117,848	(135,624)
Less: net income attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Unit Corporation									(45,288)	117,848	(135,624)
Combined Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Revenues									642,041	545,916	416,307
Expenses
Operating costs									287,704	269,964	214,892
Depreciation, depletion, and amortization									191,092	158,281	160,803
Impairments									147,884		161,563
General and administrative									36,083	29,440	26,158
Gain on disposition of assets									(564)	548	(2,860)
Total operating expenses									662,199	458,233	560,556
Income (loss) from operations									(20,158)	87,683	(144,249)
Interest, net									0	0	0
Gain (loss) on derivatives									0	0	0
Other									0	0	307
Income (loss) before income taxes									(20,158)	87,683	(143,942)
Income tax expense (benefit)									(3,319)	(20,881)	(48,654)
Equity in net earnings from investment in subsidiaries, net of taxes									0	0	0
Net income (loss)									(16,839)	108,564	(95,288)
Less: net income attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Unit Corporation									(16,839)	108,564	(95,288)
Combined Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Revenues									312,417	277,049	237,785
Expenses
Operating costs									251,328	220,613	182,970
Depreciation, depletion, and amortization									44,834	43,499	45,715
Impairments									0		0
General and administrative									2,624	8,647	7,179
Gain on disposition of assets									(110)	(25)	302
Total operating expenses									298,676	272,734	236,166
Income (loss) from operations									13,741	4,315	1,619
Interest, net									(1,214)	(689)	(834)
Gain (loss) on derivatives									0	0	0
Other									0	0	0
Income (loss) before income taxes									12,527	3,626	785
Income tax expense (benefit)									2,030	(24,198)	1,491
Equity in net earnings from investment in subsidiaries, net of taxes									0	0	0
Net income (loss)									10,497	27,824	(706)
Less: net income attributable to non-controlling interest									5,521	0	0
Net income (loss) attributable to Unit Corporation									$ 4,976	$ 27,824	$ (706)

Supplemental Condensed Consol_6

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (39,767)	$ 117,848	$ (135,624)
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39, and $0	(557)	63	0
Other comprehensive income (loss), tax	(181)	39	0
Comprehensive income (loss)	(40,324)	117,911	(135,624)
Less: Comprehensive income attributable to non-controlling interest	5,521	0	0
Comprehensive income (loss) attributable to Unit Corporation	(45,845)	117,911	(135,624)
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	11,863	(136,388)	95,994
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39, and $0	0	0	0
Other comprehensive income (loss), tax	0	0	0
Comprehensive income (loss)	11,863	(136,388)	95,994
Less: Comprehensive income attributable to non-controlling interest	0	0	0
Comprehensive income (loss) attributable to Unit Corporation	11,863	(136,388)	95,994
Parent
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(45,288)	117,848	(135,624)
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39, and $0	0	0	0
Other comprehensive income (loss), tax	0	0	0
Comprehensive income (loss)	(45,288)	117,848	(135,624)
Less: Comprehensive income attributable to non-controlling interest	0	0	0
Comprehensive income (loss) attributable to Unit Corporation	(45,288)	117,848	(135,624)
Combined Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(16,839)	108,564	(95,288)
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39, and $0	(557)	63	0
Other comprehensive income (loss), tax	(181)	39	0
Comprehensive income (loss)	(17,396)	108,627	(95,288)
Less: Comprehensive income attributable to non-controlling interest	0	0	0
Comprehensive income (loss) attributable to Unit Corporation	(17,396)	108,627	(95,288)
Combined Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	10,497	27,824	(706)
Unrealized appreciation (depreciation) on securities, net of tax of ($181), $39, and $0	0	0	0
Other comprehensive income (loss), tax	0	0	0
Comprehensive income (loss)	10,497	27,824	(706)
Less: Comprehensive income attributable to non-controlling interest	5,521	0	0
Comprehensive income (loss) attributable to Unit Corporation	$ 4,976	$ 27,824	$ (706)

Supplemental Condensed Consol_7

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Cash Flow) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$ 347,759	$ 265,956	$ 240,130
INVESTING ACTIVITIES:
Capital expeditures	(446,282)	(255,553)	(186,149)
Producing property and other acquisitions	(29,970)	(58,026)	(564)
Proceeds from disposition of property and equipment	25,910	21,713	74,823
Other	0	(1,500)	919
Net cash provided by (used in) investing activities	(450,342)	(293,366)	(110,971)
FINANCING ACTIVITIES:
Borrowings under line of credit	99,100	343,900	251,398
Payments under line of credit	(277,100)	(326,700)	(371,600)
Intercompany borrowings (advances), net	0	0	0
Payments on capitalized leases	(3,843)	(3,694)	(3,694)
Proceeds from common stock issued, net of issue costs	0	18,623	0
Proceeds from investments of non-contolling interests	300,000	0	0
Contributions from Unit	0
Transaction costs associated with sale of non-controlling interest	(2,503)	0	0
Tax expense from stock compensation	0	0	(376)
Book overdrafts	(7,320)	(4,911)	(4,829)
Net cash provided by (used in) financing activities	108,334	27,218	(129,101)
Net increase (decrease) in cash and cash equivalents	5,751	(192)	58
Cash and cash equivalents, beginning of year	701	893	835
Cash and cash equivalents, end of year	6,452	701	893
Consolidating Adjustments
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	128,872	0	0
INVESTING ACTIVITIES:
Capital expeditures	0	0	0
Producing property and other acquisitions	0	0	0
Proceeds from disposition of property and equipment	0	0	0
Other		0	0
Net cash provided by (used in) investing activities	0	0	0
FINANCING ACTIVITIES:
Borrowings under line of credit	0	0	0
Payments under line of credit	0	0	0
Intercompany borrowings (advances), net	(128,080)	0	0
Payments on capitalized leases	0	0	0
Proceeds from common stock issued, net of issue costs		0
Proceeds from investments of non-contolling interests	0
Contributions from Unit	(792)
Transaction costs associated with sale of non-controlling interest	0
Tax expense from stock compensation			0
Book overdrafts	0	0	0
Net cash provided by (used in) financing activities	(128,872)	0	0
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	0	0	0
Parent
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	(120,317)	(1,683)	1,781
INVESTING ACTIVITIES:
Capital expeditures	236	(3,594)	(3,927)
Producing property and other acquisitions	0	0	0
Proceeds from disposition of property and equipment	30	964	13
Other		0	750
Net cash provided by (used in) investing activities	266	(2,630)	(3,164)
FINANCING ACTIVITIES:
Borrowings under line of credit	97,100	343,900	251,398
Payments under line of credit	(275,100)	(326,700)	(371,600)
Intercompany borrowings (advances), net	204,809	(26,606)	126,797
Payments on capitalized leases	0	0	0
Proceeds from common stock issued, net of issue costs		18,623
Proceeds from investments of non-contolling interests	102,958
Contributions from Unit	0
Transaction costs associated with sale of non-controlling interest	(2,503)
Tax expense from stock compensation			(376)
Book overdrafts	(7,320)	(4,911)	(4,829)
Net cash provided by (used in) financing activities	119,944	4,306	1,390
Net increase (decrease) in cash and cash equivalents	(107)	(7)	7
Cash and cash equivalents, beginning of year	510	517	510
Cash and cash equivalents, end of year	403	510	517
Combined Guarantor Subsidiaries
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	327,075	224,446	197,132
INVESTING ACTIVITIES:
Capital expeditures	(400,990)	(233,254)	(158,983)
Producing property and other acquisitions	(29,970)	(58,026)	(564)
Proceeds from disposition of property and equipment	25,777	20,674	74,694
Other		(1,500)	0
Net cash provided by (used in) investing activities	(405,183)	(272,106)	(84,853)
FINANCING ACTIVITIES:
Borrowings under line of credit	0	0	0
Payments under line of credit	0	0	0
Intercompany borrowings (advances), net	78,125	47,475	(112,228)
Payments on capitalized leases	0	0	0
Proceeds from common stock issued, net of issue costs		0
Proceeds from investments of non-contolling interests	0
Transaction costs associated with sale of non-controlling interest	0
Tax expense from stock compensation			0
Book overdrafts	0	0	0
Net cash provided by (used in) financing activities	78,125	47,475	(112,228)
Net increase (decrease) in cash and cash equivalents	17	(185)	51
Cash and cash equivalents, beginning of year	191	376	325
Cash and cash equivalents, end of year	208	191	376
Combined Non-Guarantor Subsidiaries
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	12,129	43,193	41,217
INVESTING ACTIVITIES:
Capital expeditures	(45,528)	(18,705)	(23,239)
Producing property and other acquisitions	0	0	0
Proceeds from disposition of property and equipment	103	75	116
Other		0	169
Net cash provided by (used in) investing activities	(45,425)	(18,630)	(22,954)
FINANCING ACTIVITIES:
Borrowings under line of credit	2,000	0	0
Payments under line of credit	(2,000)	0	0
Intercompany borrowings (advances), net	(154,854)	(20,869)	(14,569)
Payments on capitalized leases	(3,843)	(3,694)	(3,694)
Proceeds from common stock issued, net of issue costs		0
Proceeds from investments of non-contolling interests	197,042
Contributions from Unit	792
Transaction costs associated with sale of non-controlling interest	0
Tax expense from stock compensation			0
Book overdrafts	0	0	0
Net cash provided by (used in) financing activities	39,137	(24,563)	(18,263)
Net increase (decrease) in cash and cash equivalents	5,841	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	$ 5,841	$ 0	$ 0

Supplemental Oil And Gas Disc_3

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized costs:
Proved properties	$ 6,018,568	$ 5,712,813	$ 5,446,305
Unproved properties not being amortized	330,216	296,764	314,867
Capitalized costs gross	6,348,784	6,009,577	5,761,172
Accumulated depreciation, depletion, amortization, and impairment	(5,124,257)	(4,996,696)	(4,900,304)
Net capitalized costs	1,224,527	1,012,881	860,868
Costs incurred:
Unproved properties acquired	57,430	47,029	21,675
Proved properties acquired	15,158	47,638	564
Exploration	15,907	14,811	17,325
Development	280,692	160,941	80,582
Asset retirement obligation	(7,629)	(3,613)	(30,906)
Total costs incurred	$ 361,558	$ 266,806	$ 89,240

Supplemental Oil And Gas Disc_4

Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Unproved properties acquired and wells in progress	$ 330,216	$ 296,764	$ 314,867
2,018
Unproved properties acquired and wells in progress	60,372
2,017
Unproved properties acquired and wells in progress	46,986
2,016
Unproved properties acquired and wells in progress	21,947
2015 and prior
Unproved properties acquired and wells in progress	$ 200,911

Supplemental Oil And Gas Disc_5

Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Oil and Gas Disclosures [Abstract]
Revenues	$ 429,119	$ 347,285	$ 282,742
Production costs	(131,328)	(113,344)	(103,568)
Depreciation, depletion, amortization, and impairment	(132,923)	(101,326)	(274,155)
Results of operations, income before income taxes	164,868	132,615	(94,981)
Income tax (expense) benefit	(42,915)	(52,078)	32,696
Results of operations for producing activities (excluding corporate overhead and financing costs)	$ 121,953	$ 80,537	$ (62,285)

Supplemental Oil And Gas Disc_6

Supplemental Oil And Gas Disclosures (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) bbl in Thousands, Mcf in Thousands, MBoe in Thousands	12 Months Ended
	Dec. 31, 2018MBoebblMcf	Dec. 31, 2017MBoebblMcf		Dec. 31, 2016MBoeMcfbbl
Proved developed and undeveloped reserves:
Beginning of year (MBoe) | MBoe	149,774	117,774		135,233
Revision of previous estimate (MBoe) | MBoe	(4,165)	11,444	[1]	(8,300)	[1]
Extension and discovery (MBoe) | MBoe	21,033	14,975		5,690
Infill reserves in existing proved fields (MBoe) | MBoe	8,656	16,123		7,504
Purchase of mineral in place (MBoe) | MBoe	2,707	5,768		262
Production (MBoe) | MBoe	(17,070)	(15,996)		(17,277)
Sales (MBoe) | MBoe	(1,254)	(314)		(5,338)
End of year (MBoe) | MBoe	159,681	149,774		117,774
Proved developed reserves:
Beginning of year (MBoe) | MBoe	112,961	99,079		115,296
End of year (MBoe) | MBoe	111,576	112,961		99,079
Proved undeveloped reserves
Beginning of year (MBoe) | MBoe	36,813	18,695		19,937
End of year (MBoe) | MBoe	48,105	36,813		18,695
Oil (bbls)
Proved developed and undeveloped reserves:
Beginning of year	19,513	15,696		16,735
Revision of previous estimates	180	730	[1]	(549)	[1]
Extensions and discoveries	3,250	2,235		1,816
Infill reserves in existing proved fields	1,898	1,632		663
Purchases of minerals in place	701	2,019		114
Production	(2,874)	(2,715)		(2,974)
Sales	(110)	(84)		(109)
End of year	22,558	19,513		15,696
Proved developed reserves:
Beginning of year	14,862	12,724		14,679
End of year	15,192	14,862		12,724
Proved undeveloped reserves
Beginning of year	4,651	2,972		2,056
End of year	7,366	4,651		2,972
Natural Gas Liquids (bbls)
Proved developed and undeveloped reserves:
Beginning of year	45,486	34,482		37,687
Revision of previous estimates	(1,368)	4,325	[1]	(2,473)	[1]
Extensions and discoveries	5,149	4,520		1,588
Infill reserves in existing proved fields	2,795	5,779		2,724
Purchases of minerals in place	856	1,197		43
Production	(4,925)	(4,737)		(5,014)
Sales	(197)	(80)		(73)
End of year	47,796	45,486		34,482
Proved developed reserves:
Beginning of year	33,358	28,502		31,218
End of year	33,515	33,358		28,502
Proved undeveloped reserves
Beginning of year	12,128	5,980		6,469
End of year	14,281	12,128		5,980
Natural gas (Mcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf	508,650	405,579		484,868
Revision of previous estimates | Mcf	(17,859)	38,330	[1]	(31,670)	[1]
Extensions and discoveries | Mcf	75,806	49,321		13,720
Infill reserves in existing proved fields | Mcf	23,778	52,270		24,704
Purchases of minerals in place | Mcf	6,897	15,313		630
Production | Mcf	(55,627)	(51,260)		(55,735)
Sales | Mcf	(5,682)	(903)		(30,938)
End of year | Mcf	535,963	508,650		405,579
Proved developed reserves:
Beginning of year | Mcf	388,446	347,121		416,395
End of year | Mcf	377,216	388,446		347,121
Proved undeveloped reserves
Beginning of year | Mcf	120,204	58,458		68,473
End of year | Mcf	158,747	120,204		58,458
[1]	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

Supplemental Oil And Gas Disc_7

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash flows	$ 3,980,369	$ 3,347,396	$ 2,030,925
Future production costs	(1,479,744)	(1,308,244)	(861,625)
Future development costs	(442,984)	(369,560)	(173,446)
Future income tax expenses	(307,916)	(234,152)	(141,752)
Future net cash flows	1,749,725	1,435,440	854,102
10% annual discount for estimated timing of cash flows	(766,047)	(628,270)	(335,892)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves	$ 983,678	$ 807,170	$ 518,210	$ 589,486
Percentage of annual discount for estimated timing of cash flows	10.00%	10.00%	10.00%

Supplemental Oil And Gas Disc_8

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Reserve Quantities [Line Items]
Sales and transfers of oil and natural gas produced, net of production costs	$ (297,791)	$ (239,953)	$ (173,920)
Net changes in prices and production costs	120,062	236,126	(94,026)
Revisions in quantity estimates and changes in production timing	(33,282)	87,239	(51,979)
Extensions, discoveries, and improved recovery, less related costs	234,172	102,965	84,738
Changes in estimated future development costs	19,535	(5,194)	70,976
Previously estimated cost incurred during the period	63,557	36,044	16,602
Purchases of minerals in place	23,416	51,686	2,652
Sales of minerals in place	(5,004)	(1,447)	(17,248)
Accretion of discount	89,753	57,517	69,069
Net change in income taxes	(31,674)	(33,389)	44,241
Other-net	(6,236)	(2,634)	(22,381)
Net change	176,508	288,960	(71,276)
Beginning of year	807,170	518,210	589,486
End of year	$ 983,678	$ 807,170	$ 518,210

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018$ / Unit
Oil (bbls)
Average Sales Prices	65.56
Natural Gas Liquids (bbls)
Average Sales Prices	37.68
Natural gas (Mcf)
Average Sales Prices	3.10

Schedule II - Valuation And Q_3

Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	$ 2,450	$ 3,773	$ 5,199
Additions charged to costs and expenses	81	348	785
Deductions and net write-offs	0	(1,671)	(2,211)
Balance at end of period	$ 2,531	$ 2,450	$ 3,773