View Filing Data

Accounts receivable (less allowance for doubtful accounts of $2,531 and $2,450 at December 31, 2018 and 2017, respectively)

$ 6,452

$ 701

119,397

111,512

Current derivative asset (Note 13)

473

505

12,870

721

Assets held for sale (Note 2)

2,054

22,511

11,356

6,172

Oil and natural gas properties, on the full cost method:

175,113

119,672

6,018,568

5,712,813

330,216

296,764

1,284,419

1,593,611

767,388

726,236

68,339

62,618

59,081

59,080

29,524

29,631

57,507

53,439

Less accumulated depreciation, depletion, amortization, and impairment

8,615,042

8,534,192

6,182,726

6,151,450

2,432,316

2,382,742

Goodwill (Note 2)

62,808

27,816

16,230

^[1]

2,698,053

2,581,452

Accrued liabilities (Note 6)

149,945

112,648

49,664

48,523

Current derivative liabilities (Note 13)

7,763

Current portion of other long-term liabilities (Note 7)

14,250

13,002

Long-term debt less unamortized discount and debt issuance costs (Note 7)

213,859

181,936

644,475

820,276

Non-current derivative liabilities (Note 13)

293

Other long-term liabilities (Note 7)

101,234

100,203

Deferred income taxes (Note 9)

144,748

133,477

Commitments and contingencies (Note 15)

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued

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

Accumulated other comprehensive income (loss) (net of tax ($155) and $39 at December 31, 2018 and 2017, respectively) (Note 17)

628,108

535,815

(481)

Total shareholders' equity attributable to Unit Corporation

752,840

799,402

1,390,881

1,345,560

Non-controlling interests in consolidated subsidiaries

202,563

1,593,444

1,345,560

Summary Of Significant Accounting Policies

^[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 (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 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 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 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 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 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	12 Months Ended
Organization	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 Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements. 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 property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. 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,

we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.

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 or more years or can be based on terms to drill a specific number of wells. The allocation rules in ASC 606 (called the "series guidance") provide that a contract may contain a single performance obligation composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same method as it relates to the satisfaction of the overall performance obligation. We have determined that the delivery of drilling services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment of service (i.e. hour available to drill) that the drilling contractor promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the drilling contractor would use the same method for measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. 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. On adoption of the standard, no adjustment to opening retained earnings was required.

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, 2018
	(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, 2018		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 to ten years. Under service contracts, as the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs, the performance obligation to gather, transport, or process occurs over time. We typically receive payment within a set number of days following the end of the month and includes payment for all services performed that month. Our overall performance obligation is satisfied at the end of the contract term.

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

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.


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.

Superior will be governed and managed under its Amended and Restated Limited Liability Company Agreement and the Master Services and Operating Agreement (MSA) signed by Superior and an affiliate of Unit, as both agreements may be amended occasionally. Further details are in Note 16 – Variable Interest Entity Arrangements.

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

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-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-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions. The amounts borrowed under the Superior credit agreement bear 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%. The obligations under the Superior credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.

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 years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $4.0 million is included in current portion of other long-term liabilities and the non-current portion of $7.4 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2018. These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $4.1 million and $0.6 million, respectively at December 31, 2018. Annual payments, net of maintenance and interest,

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

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 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

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	12 Months Ended
Employee Benefit Plans	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 year on each anniversary, unless a notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive’s terms and conditions for employment (including position, work location, compensation, and benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an additional three years. The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position.

Transactions With Related Parties

12 Months Ended

Dec. 31, 2018

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

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 year vesting period. During 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at December 31, 2018, the participants are estimated to receive 69% of the 2018, 99% of the 2017, and 200% of the 2016 performance based shares. The CFTA performance measurement at December 31, 2018 for the one-third vesting in 2019 was assessed to vest at 100%. The CFTA performance measurement for future years was assessed to vest at target or 100%.

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 Options at December 31, 2018
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$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

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.Amounts settled during the periods are a loss of $22,803 and a gain of $173, respectively.

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

calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented in Note 8 – Asset Retirement Obligations.Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2016 and 2018, we recorded non-cash impairment charges discussed further in Note 2 – Summary of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as Level 3.

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	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 years. Future capital lease payments under the terms are approximately $6.2 million each year through 2020 and approximately $3.8 million in 2021. Total maintenance and interest remaining related to these leases are $4.1 million and $0.6 million, respectively at December 31, 2018. Annual payments, net of maintenance and interest, 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. 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 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, 2018
	(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

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 ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

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 natural 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 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 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 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 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 Charged to Costs & Expenses		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 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.


	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

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.

Oil and Natural Gas Operations

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.

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

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

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.

Adopted Standards

The additional disclosures required by ASC 606 have been included in Note 3 – Revenue from Contracts with Customers.

we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.

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 Customers (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018
	(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, 2018		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

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

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 (Tables)

12 Months Ended

Dec. 31, 2018

EOG Acquisition

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

_________________________

Excalibur Acquisition

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

_________________________

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]


	2018		2017		2016
Options and SARs	66,500		87,500		199,755
Average exercise price	$	44.42	$	51.34	$	48.79

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-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 Obligation Disclosure [Abstract]

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64930739&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21521-112644

+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

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

_________________________

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 Parties (Tables)

12 Months Ended

Dec. 31, 2018

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 (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 Options at December 31, 2018
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$31.30 - $41.21	38,500	0.9 years	$	37.58
$53.81 - $73.26	28,000	2.3 years	$	53.81

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.Amounts settled during the periods are a loss of $22,803 and a gain of $173, respectively.

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

_________________________

Tabular disclosure of available-for-sale securities which includes, but is not limited to, changes in the cost basis and fair value, fair value and gross unrealized gain (loss), fair values by type of security, contractual maturity and classification, amortized cost basis, contracts to acquire securities to be accounted for as available-for-sale, debt maturities, transfers to trading, change in net unrealized holding gain (loss) net of tax, continuous unrealized loss position fair value, aggregate losses qualitative disclosures, other than temporary impairment (OTTI) losses or other disclosures related to available for sale securities.

Variable Interest Entity Arrangements [Abstract]

Variable Interest Entity Arrangements (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018
	(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

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

Schedule of Accumulated Other Comprehensive Income [Table Text Block]

Equity (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

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 ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

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 natural 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 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 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


	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


	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 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]


	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

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=82851474&loc=d3e511914-122862

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62094-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62395-109447

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=34713648&loc=d3e63071-109448

+ Details

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Tables)

12 Months Ended

Dec. 31, 2018

Summary of Valuation Allowance [Table Text Block]

Allowance for Doubtful Accounts:


Description	Balance at Beginning of Period		Additions Charged to Costs & Expenses		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 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 Accounting Policies (Schedule of Fair Values of the Net Asset (Liabilities)) (Details) $ in Millions	Dec. 31, 2018 USD ($)
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 Accounting Policies (Narrative) (Details)

12 Months Ended

Dec. 31, 2018

USD ($)

rig

contract

Partnerships

MMcf

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

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

Number of contracts, daywork expiring in two years | contract

Book Overdrafts

$ 5,100,000

$ 12,400,000

Concentration of cash

11,000,000.0

11,400,000

147,884,000

$ 161,563,000

Interest Costs Capitalized

22,511,000

16,500,000

15,900,000

15,300,000

Goodwill impairment

Additions to goodwill

$ 0

Percentage fair value exceeds carrying value for goodwill

37.00%

Goodwill deductible for tax purposes

$ 400,000

15,900,000

14,800,000

15,400,000

Average rates used for depreciation, depletion, and amortization per Boe

7.50

6.00

6.24

Future discounted net cash flows discounted

$ 330,216,000

296,764,000

314,867,000

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

Eliminated associated operating expense

19,500,000

11,800,000

Eliminated yielding

$ 3,000,000.0

$ 1,600,000

Number of oil and gas limited partnerships | Partnerships

Federal statutory income tax rate, percent

21.00%

35.00%

Tax benefit from change in enacted tax rate

$ 0

^[1]

$ (81,307,000)

^[1]

Liability recognized to under production

$ (3,331,000)

(3,283,000)

Minimum

Summary Of Significant Accounting Policies [Line Items]

10 days

Operating Lease, Right-of-Use Asset

6 months

Insurance coverage

$ 0

3,000,000.0

Operating Lease, Liability

$ 3,000,000.0

Maximum

Summary Of Significant Accounting Policies [Line Items]

90 days

Operating Lease, Right-of-Use Asset

3 years

Insurance coverage

$ 1,000,000.0

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]

Summary Of Significant Accounting Policies [Line Items]

$ 2,900,000

Drilling Equipment

Minimum depreciation percentage for idle drilling rigs (if idle under 48 months)

20.00%

Impairment of contract drilling equipment, net of tax

$ 147,900,000

$ 111,700,000

Drilling Equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Summary Of Significant Accounting Policies [Line Items]

15 years

Building

Property, Plant and Equipment, Other Types | Minimum

39 years

Summary Of Significant Accounting Policies [Line Items]

Property, Plant and Equipment, Other Types | Maximum

3 years

Summary Of Significant Accounting Policies [Line Items]

15 years

Summary Of Significant Accounting Policies [Line Items]

Non-cash ceiling test write-down net of tax

$ 0

^[2]

$ 0

161,600,000

$ 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]

SCR diesel-electric drilling rigs | Drilling Equipment

Summary Of Significant Accounting Policies [Line Items]

[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 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

$ 423,059

$ 357,744

$ 294,221

131,675

130,789

120,184

^[1]

$ (108,068)

$ 49,216

$ 40,915

$ 38,833

$ 37,211

$ 27,181

$ 24,462

$ 32,657

Adjustments due to ASC606 [Member]

223,730

207,176

185,870

Deferred tax benefit

(10,865)

(57,683)

(71,209)

Net income (loss)

(39,767)

117,848

(135,624)

(17,518)

(17,518)

Amounts without the adoption of ASC606 [Member]

4,970

Deferred tax benefit

1,218

Net income (loss)

3,752

440,577

149,193

218,760

Deferred tax benefit

(12,083)

Net income (loss)

(43,519)

423,059

^[2]

357,744

294,221

136,870

135,532

126,739

291,384

Oil and Natural Gas | Adjustments due to ASC606 [Member]

^[2]

$ 0

Oil and Natural Gas | Amounts without the adoption of ASC606 [Member]

$ 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 natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

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 Customers (Revenue, Remaining Performance Obligation) (Details) - Mid-Stream - Demand fee contracts [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining term of contract	4 years
Remaining impact to revenue	$ (3,282)
2019
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	2,632
2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	(3,781)
2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	(3,507)
2022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	$ 1,374

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 Customers (Narrative) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2018

USD ($)

contract

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Jan. 01, 2018

USD ($)

$ 752,840

$ 799,402

$ 798,128

Adjustments due to ASC606 [Member]

223,730

207,176

$ 185,870

$ 4,970

Minimum

6 months

10 days

Maximum

3 years

90 days

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.

Oil and Natural Gas | Adjustments due to ASC606 [Member]

$ 0

^[1]

Drilling

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

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.

Drilling | Adjustments due to ASC606 [Member]

$ 0

^[1]

Drilling | Long-term Contract with Customer [Member]

Number of daywork contracts | contract

Drilling | Minimum

6 months

Drilling | Minimum | Long-term Contract with Customer [Member]

10 days

2 months

Drilling | Maximum

3 years

90 days

Mid-Stream

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.

Mid-Stream | Adjustments due to ASC606 [Member]

$ 312,417

^[1]

$ 277,049

$ 237,785

Adjustment to opening retained earnings, before tax

$ 2,478

(1,274)

(1,700)

Adjustment to opening retained earnings, after tax

$ (1,300)

Mid-Stream | Minimum

Remaining term of contract

5 years

1 year

Mid-Stream | Maximum

Remaining term of contract

10 years

15 years

[1]	The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

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

Proved oil and natural gas properties

$ 6,018,568

$ 5,712,813

$ 5,446,305

Asset retirement obligation

330,216

296,764

314,867

$ (64,208)

$ (69,444)

$ (70,170)

EOG Acquisition

Proved oil and natural gas properties

$ 54,332

43,745

Total oil and natural gas properties included in the full cost pool

8,650

^[1]

52,395

Gas gathering equipment and other

2,340

Asset retirement obligation

(403)

Fair value of net assets acquired

$ 54,332

Excalibur Acquisition

Proved oil and natural gas properties

$ 29,633

14,546

Total oil and natural gas properties included in the full cost pool

15,502

^[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 - Narrative (Details)
MBoe in Thousands

12 Months Ended

Dec. 06, 2018

USD ($)

MBoe

wells

numberOfDrillingLocations

Apr. 03, 2018

USD ($)

Apr. 03, 2017

USD ($)

MBoe

wells

Dec. 31, 2018

USD ($)

MBoe

rig

Dec. 31, 2017

USD ($)

MBoe

rig

Dec. 31, 2016

USD ($)

MBoe

rig

Dec. 31, 2015

MBoe

Proved Developed Reserves (Volume) | MBoe

111,576

112,961

99,079

115,296

$ 147,884,000

$ 0

$ 161,563,000

EOG Acquisition

Business Acquisition, Effective Date of Acquisition

$ 54,332,000

Jan. 01, 2017

Proved Developed Reserves (Volume) | MBoe

3,200

Natural Gas Gathering System

Excalibur Acquisition

Business Acquisition, Effective Date of Acquisition

$ 29,633,000

Nov. 01, 2018

Proved Developed Reserves (Volume) | MBoe

2,600

Horizontal drilling locations | numberOfDrillingLocations

Acquired land with existing production capacity, percent

82.00%

Hoxbar | EOG Acquisition

Area of Real Estate Property | a

8,300

Proved developed producing wells | wells

Acquired land with existing production capacity, percent

71.00%

Penn Sands | Excalibur Acquisition

Area of Real Estate Property | a

8,667

Wells acquired | wells

Proceeds from divestiture of assets

Other acquisitions

600,000

4,700,000

600,000

22,500,000

18,600,000

67,200,000

$ 0

^[1]

$ 0

$ 161,600,000

Drilling Equipment

Number of rigs sold | rig

Net book value of drilling rigs sold

$ 1,700,000

Gain (loss) on sale of drilling rigs

1,600,000

Impairment of contract drilling equipment, net of tax

$ 147,900,000

$ 0

$ 111,700,000

Mechanical drilling rigs | Drilling Equipment

SCR diesel-electric drilling rigs | Drilling Equipment

Ownership interest in Superior Pipeline Company, L.L.C.

Proceeds from sale of non-controlling interest

Ownership interest sold

50.00%

$ 300,000,000.0

[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 (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

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

635

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

(0.03)

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 (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 (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 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-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-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-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Ending December 31, [Abstract]
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	$ 15,224

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands		12 Months Ended
	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. 03, 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 (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 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

^[1]

(81,307)

^[1]

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 expense (benefit)

$ (13,996)

$ (57,678)

$ (71,194)

[1]	In 2017, the revaluation from the Tax Act.

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 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) (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) $ in Thousands			12 Months Ended
Employee Benefit Plans (Details) $ in Thousands	May 05, 2004 yr	Jan. 01, 1997 week	Dec. 31, 2018 USD ($) yr shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) 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 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 Parties (Narrative) (Details)	12 Months Ended
Transactions With Related Parties (Narrative) (Details)	Dec. 31, 2018 USD ($) Partnerships	Dec. 31, 2017 USD ($) Partnerships	Dec. 31, 2016 USD ($) Partnerships	Nov. 30, 2016 USD ($)	May 31, 2016 USD ($)	Mar. 10, 2016 USD ($)
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 (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	$ 5.0	$ 3.6

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 (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 (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 (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) - Directors Plan	12 Months Ended
	Dec. 31, 2018 $ / shares shares
$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 (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				2,000,000.0
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	$ 15.0
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	$ 0.0
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-designated Hedges Outstanding) (Details)	12 Months Ended
	Dec. 31, 2018 MMBTU $ / Unit bbl
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 Subsequent Non-designated Hedges) (Details) - Subsequent to December 31, 2018 - Apr'19- Oct'19 - Natural gas - If Nymex - Swap	2 Months Ended
	Feb. 22, 2019 MMBTU $ / Unit
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	20,000
Swap Price \| $ / Unit	2.900

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 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]	Amounts settled during the periods are a loss of $22,803 and a gain of $173, respectively.

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 (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 (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 (Schedule Of Quantitative Information About Unobservable Inputs) (Details) - Level 3
$ in Thousands

12 Months Ended

Dec. 31, 2018

USD ($)

$ / 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

Crude Oil | Maximum | Three-way collar

Natural gas | Three-way collar

19.44

Natural gas | Collar

Fair Value | $

$ (334)

^[1]

Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Fair Value | $

$ 372

^[1]

Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Natural gas | Minimum | Collar

Natural gas | Minimum | Three-way collar

Natural gas | Maximum | Collar

Natural gas | Maximum | Three-way collar

0.38

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 (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 (Details)	12 Months Ended
Commitments And Contingencies (Details)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
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
2019	$ 6,168,000
2020	6,168,000
2021	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 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

$ 6,452

$ 701

$ 893

$ 835

119,397

111,512

11,356

6,172

175,113

119,672

Property and Equipment:

767,388

726,236

29,524

29,631

Less accumulated depreciation, depletion, amortization, and impairment

8,615,042

8,534,192

6,182,726

6,151,450

2,432,316

2,382,742

27,816

$ 27,028

16,230

2,698,053

^[1]

2,581,452

^[1]

$ 2,479,303

149,945

112,648

49,664

48,523

14,250

15,750

13,002

Long-term debt less debt issuance costs

213,859

181,936

644,475

820,276

101,234

$ 109,940

$ 100,203

VIE

5,841

33,207

2,693

41,741

Property and Equipment:

767,388

3,086

Less accumulated depreciation, depletion, amortization, and impairment

770,474

364,740

405,734

15,907

463,382

32,214

3,688

6,875

Long-term debt less debt issuance costs

42,777

Schedule of Accumulated Other Comprehensive Income (Loss) [Abstract]

14,687

Total liabilities

$ 57,464

[1]

Variable Interest Entity Arrangements (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($)
Variable Interest Entity [Line Items]
Date Involvement Began	Apr. 03, 2018
Superior Pipeline Company, L.L.C. [Member]
Variable Interest Entity [Line Items]
Date Involvement Began	Apr. 03, 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 Other Comprehensive Income) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Unrealized appreciation (depreciation) on securities, before tax

$ (738)

$ 102

$ 0

Tax benefit (expense)

^[1]

181

(39)

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 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

Unrealized appreciation (depreciation) before reclassifications

^[1]

(557)

Amounts reclassified from accumulated other comprehensive income

Net current-period other comprehensive income (loss)

(557)

Ending Balance

$ (481)

$ 63

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) - 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 (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

$ 423,059

$ 357,744

$ 294,221

196,492

174,720

122,086

223,730

207,176

185,870

$ 214,788

$ 220,058

$ 203,303

$ 205,132

$ 204,847

$ 188,488

$ 170,581

$ 175,724

843,281

739,640

602,177

131,675

130,789

120,184

131,385

122,600

88,154

167,836

155,483

137,609

430,896

408,872

345,947

243,605

209,257

208,353

147,884

161,563

822,385

618,129

715,863

38,707

38,087

33,337

704

327

2,540

(17,107)

83,751

(144,483)

(3,184)

14,732

(22,813)

(33,494)

(38,334)

(39,829)

307

(53,763)

60,170

(206,818)

1,350,830

^[1]

1,127,900

^[2]

1,350,830

^[1]

1,127,900

^[2]

965,159

^[3]

806,611

933,063

806,611

933,063

941,676

461,828

438,571

461,828

438,571

461,600

2,619,269

^[4]

2,499,534

^[5]

2,619,269

^[4]

2,499,534

^[5]

2,368,435

^[6]

55,505

56,854

55,505

56,854

58,188

23,279

^[7]

25,064

^[8]

23,279

^[7]

25,064

^[8]

52,680

^[9]

2,698,053

^[10]

2,581,452

^[10]

2,698,053

^[10]

2,581,452

^[10]

2,479,303

488,780

332,280

142,155

Revenues

423,059

^[11]

357,744

294,221

^[11]

^[11]

423,059

^[11]

357,744

294,221

136,870

135,532

126,739

136,870

135,532

126,739

133,584

101,911

113,811

^[12]

161,563

270,454

237,443

402,113

139

228

(324)

152,744

120,529

(108,216)

152,744

120,529

(108,216)

1,357,779

^[1]

1,134,080

^[2]

1,357,779

^[1]

1,134,080

^[2]

970,238

^[3]

1,357,779

^[4]

1,134,080

^[5]

1,357,779

^[4]

1,134,080

^[5]

970,238

^[6]

^[7]

^[8]

^[7]

^[8]

^[9]

1,357,779

1,134,080

1,357,779

1,134,080

970,238

367,335

270,443

89,562

Drilling

Revenues

^[11]

218,982

^[11]

188,172

122,086

^[11]

218,982

^[11]

188,172

122,086

150,834

134,432

88,154

150,834

134,432

88,154

57,508

56,370

46,992

147,884

^[13]

^[12]

356,226

190,802

135,146

425

(776)

3,184

(136,819)

(3,406)

(9,876)

(136,819)

(3,406)

(9,876)

^[1]

^[2]

^[1]

^[2]

^[3]

806,696

933,063

806,696

933,063

941,676

806,696

^[4]

933,063

^[5]

806,696

^[4]

933,063

^[5]

941,676

^[6]

^[7]

^[8]

^[7]

^[8]

^[9]

806,696

933,063

806,696

933,063

941,676

75,510

36,148

19,134

Mid-Stream

Revenues

^[11]

^[11]

312,417

^[11]

277,049

237,785

312,417

^[11]

277,049

237,785

251,328

220,613

182,969

251,328

220,613

182,969

44,834

43,499

45,715

^[13]

^[12]

296,162

264,112

228,684

110

(302)

16,365

12,962

8,799

(1,214)

15,151

12,962

8,799

^[1]

^[2]

^[1]

^[2]

^[3]

466,851

439,369

466,851

439,369

462,330

466,851

^[4]

439,369

^[5]

466,851

^[4]

439,369

^[5]

462,330

^[6]

^[7]

^[8]

^[7]

^[8]

^[9]

466,851

439,369

466,851

439,369

462,330

44,810

22,168

16,796

Other Segments

Revenues

^[11]

^[11]

^[11]

^[11]

7,679

7,477

1,835

^[13]

^[12]

7,679

7,477

1,835

38,707

38,087

33,337

850

(18)

(46,356)

(44,714)

(35,190)

(3,184)

14,732

(22,813)

(32,280)

(38,334)

(39,829)

307

(81,798)

(68,295)

(97,525)

^[1]

^[2]

^[1]

^[2]

^[3]

^[4]

^[5]

^[4]

^[5]

^[6]

55,505

56,854

55,505

56,854

58,188

25,566

^[7]

25,064

^[8]

25,566

^[7]

25,064

^[8]

52,680

^[9]

81,071

81,918

81,071

81,918

110,868

Intersubsegment Eliminations

1,125

3,521

16,663

Revenues

(22,490)

(13,452)

(88,687)

(69,873)

(51,915)

(111,177)

(83,325)

(51,915)

(5,195)

(4,743)

(6,555)

(19,449)

(11,832)

(83,492)

(65,130)

(45,360)

(108,136)

(81,705)

(51,915)

^[13]

^[12]

(108,136)

(81,705)

(51,915)

(3,041)

(1,620)

(3,041)

(1,620)

(6,949)

^[1]

(6,180)

^[2]

(6,949)

^[1]

(6,180)

^[2]

(5,079)

^[3]

(85)

(5,023)

(798)

(5,023)

(798)

(730)

(12,057)

^[4]

(6,978)

^[5]

(12,057)

^[4]

(6,978)

^[5]

(5,809)

^[6]

(2,287)

^[7]

^[8]

(2,287)

^[7]

^[8]

^[9]

$ (14,344)

$ (6,978)

(14,344)

(6,978)

(5,809)

Net income (loss) attributable to Unit Corporation

$ 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 natural 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 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

$ (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 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

$ 6,452

$ 701

$ 893

$ 835

119,397

111,512

473

505

12,870

721

2,054

22,511

11,356

6,172

175,113

119,672

6,018,568

5,712,813

5,446,305

330,216

296,764

314,867

1,284,419

1,593,611

767,388

726,236

68,339

62,618

59,081

59,080

29,524

29,631

57,507

53,439

Less accumulated depreciation, depletion, amortization, and impairment

8,615,042

8,534,192

6,182,726

6,151,450

2,432,316

2,382,742

62,808

1,500

26,316

14,730

2,698,053

^[1]

2,581,452

^[1]

2,479,303

149,945

112,648

49,664

48,523

7,763

14,250

$ 15,750

13,002

213,859

181,936

178,000

644,475

642,276

293

101,234

109,940

100,203

144,748

133,064

133,477

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued

Common Stock, $0.20 par value, 175,000,000 shares authorized

10,414

10,280

628,108

535,815

(481)

Total shareholders' equity attributable to Unit Corporation

752,840

$ 798,128

799,402

1,390,881

1,345,560

Non-controlling interests in consolidated subsidiaries

202,563

1,593,444

1,345,560

1,194,070

1,313,580

Consolidating Adjustments

^[1]

2,698,053

2,581,452

(14,344)

(6,978)

(14,344)

(6,978)

Less accumulated depreciation, depletion, amortization, and impairment

(950,916)

(1,155,725)

(1,160,444)

(1,044,709)

(2,125,704)

(2,207,412)

(13,576)

(6,978)

(468)

(14,044)

(6,978)

(950,916)

(1,155,725)

(300)

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued

Common Stock, $0.20 par value, 175,000,000 shares authorized

(242,963)

(61,470)

(792)

Total shareholders' equity attributable to Unit Corporation

(916,689)

(983,239)

(1,160,444)

(1,044,709)

Non-controlling interests in consolidated subsidiaries

(1,160,444)

(1,044,709)

(2,125,704)

(2,207,412)

Parent

403

510

517

510

2,539

154

12,870

721

243

5,103

2,925

21,158

4,371

9,273

9,270

28,584

28,039

Less accumulated depreciation, depletion, amortization, and impairment

37,857

37,309

27,504

21,268

10,353

16,041

950,916

1,155,725

1,160,444

1,044,709

5,115

5,373

2,147,986

2,226,219

8,697

13,124

28,230

26,165

7,763

812

657

37,739

47,709

178,000

644,475

642,276

293

13,134

11,257

60,983

1,480

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued

Common Stock, $0.20 par value, 175,000,000 shares authorized

10,414

10,280

628,108

535,815

Total shareholders' equity attributable to Unit Corporation

752,840

799,402

1,391,362

1,345,497

Non-controlling interests in consolidated subsidiaries

1,391,362

1,345,497

Combined Guarantor Subsidiaries

2,147,986

2,226,219

208

191

376

325

94,526

89,622

473

505

1,811

22,511

3,560

2,370

123,089

92,688

6,018,568

5,712,813

330,216

296,764

1,284,419

1,593,611

68,339

62,618

59,081

59,080

17,165

17,423

28,923

25,400

Less accumulated depreciation, depletion, amortization, and impairment

7,806,711

7,767,709

5,790,481

5,807,757

2,016,230

1,959,952

62,808

1,500

5,293

6,328

2,208,920

2,123,276

122,610

87,514

16,409

19,134

6,563

8,501

145,582

115,149

948,707

870,582

73,713

77,566

83,765

85,443

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued

Common Stock, $0.20 par value, 175,000,000 shares authorized

45,921

(481)

Total shareholders' equity attributable to Unit Corporation

911,713

928,552

957,153

974,536

Non-controlling interests in consolidated subsidiaries

957,153

974,536

Combined Non-Guarantor Subsidiaries

2,208,920

2,123,276

5,841

$ 0

36,676

28,714

2,693

877

45,210

29,591

767,388

726,236

3,086

2,938

Less accumulated depreciation, depletion, amortization, and impairment

770,474

729,174

364,741

322,425

405,733

406,749

15,908

3,029

466,851

439,369

32,214

18,988

5,493

3,224

6,875

3,844

44,582

26,056

2,209

285,143

14,687

11,380

46,554

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued

Common Stock, $0.20 par value, 175,000,000 shares authorized

197,042

15,549

792

Total shareholders' equity attributable to Unit Corporation

4,976

54,687

202,810

70,236

Non-controlling interests in consolidated subsidiaries

202,563

405,373

70,236

$ 466,851

$ 439,369

[1]

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 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 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 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 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 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
2018
Unproved properties acquired and wells in progress	60,372
2017
Unproved properties acquired and wells in progress	46,986
2016
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 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 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, 2018

MBoe

bbl

Mcf

Dec. 31, 2017

MBoe

bbl

Mcf

Dec. 31, 2016

MBoe

Mcf

bbl

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

Beginning of year (MBoe) | MBoe

112,961

99,079

115,296

End of year (MBoe) | MBoe

111,576

112,961

99,079

Beginning of year (MBoe) | MBoe

36,813

18,695

19,937

End of year (MBoe) | MBoe

48,105

36,813

18,695

Oil (bbls)

Revision of previous estimates

19,513

15,696

16,735

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)

22,558

19,513

15,696

14,862

12,724

14,679

15,192

14,862

12,724

4,651

2,972

2,056

Natural Gas Liquids (bbls)

7,366

4,651

2,972

Revision of previous estimates

45,486

34,482

37,687

(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

Production

(4,925)

(4,737)

(5,014)

Sales

(197)

(80)

(73)

47,796

45,486

34,482

33,358

28,502

31,218

33,515

33,358

28,502

12,128

5,980

6,469

14,281

12,128

5,980

Natural gas (Mcf)

Revision of previous estimates | Mcf

Beginning of year | Mcf

508,650

405,579

484,868

(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

Beginning of year | Mcf

388,446

347,121

416,395

End of year | Mcf

377,216

388,446

347,121