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Accounts receivable, net of allowance for doubtful accounts of $2,332 and $2,531 at December 31, 2019 and December 31, 2018, respectively

$ 571

$ 6,452

82,656

119,397

Current derivative asset (Note 14)

449

473

633

12,870

Assets held for sale (Note 3)

1,756

2,054

5,908

22,511

13,078

6,602

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

105,051

170,359

6,341,582

6,018,568

252,874

330,216

1,295,713

1,284,419

824,699

767,388

69,692

68,339

59,080

59,081

29,723

29,524

57,992

57,507

Less accumulated depreciation, depletion, amortization, and impairment

8,931,355

8,615,042

6,978,669

6,182,726

Right of use asset (Note 16)

1,952,686

2,432,316

Goodwill (Note 3)

62,808

5,673

26,642

32,570

^[1]

2,090,052

2,698,053

Accrued liabilities (Note 7)

84,481

151,686

46,562

47,923

Current operating lease liability (Note 16)

3,430

Current portion of other long-term liabilities (Note 8)

108,200

17,376

14,250

Long-term debt less debt issuance costs (Note 8)

260,049

213,859

663,216

644,475

Non-current derivative liabilities (Note 14)

293

Operating lease liability (Note 16)

2,071

Other long-term liabilities (Note 8)

95,341

101,234

Deferred income taxes (Note 10)

13,713

144,748

Commitments and contingencies (Note 17)

Shareholders' equity:

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

Common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 and 54,055,600 shares issued as of December 31, 2019 and 2018, respectively

10,591

10,414

Capital in excess of par value

644,152

628,108

Accumulated other comprehensive loss (net of tax ($155) at December 31, 2018) (Note 19)

(481)

Retained earnings

199,135

752,840

Total shareholders' equity attributable to Unit Corporation

853,878

1,390,881

Non-controlling interests in consolidated subsidiaries

201,757

202,563

1,055,635

1,593,444

Summary Of Significant Accounting Policies

^[1]

$ 2,090,052

$ 2,698,053

[1]

Unit Corporation's consolidated total assets as of December 31, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. 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 $40.1 million and $423.3 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 18 – Variable Interest Entity Arrangements.

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 2,332	$ 2,531
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	55,443,393	54,055,600
Other Comprehensive Income (Loss), Tax	$ 0	$ (155)
VIE Current assets pledged	28,800	40,100
VIE Non-current assets pledged	434,300	423,300
VIE Current liabilities, no recourse	32,200	42,800
VIE Non-current liabilities, no recourse	$ 26,000	$ 14,700

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Revenues	$ 674,634	$ 843,281	$ 739,640
Operating costs:
Operating costs	384,728	430,896	408,872
Depreciation, depletion, and amortization	275,573	243,605	209,257
Impairments (Note 3)	625,716	147,884	0
General and administrative	38,246	38,707	38,087
(Gain) loss on disposition of assets	3,502	(704)	(327)
Total operating expenses	1,327,765	860,388	655,889
Income (loss) from operations	(653,131)	(17,107)	83,751
Other income (expense):
Interest, net	(37,012)	(33,494)	(38,334)
Gain (loss) on derivatives	4,225	(3,184)	14,732
Other	(236)	22	21
Total other income (expense)	(33,023)	(36,656)	(23,581)
Income (loss) before income taxes	(686,154)	(53,763)	60,170
Income tax expense (benefit):
Current	(1,281)	(3,131)	5
Deferred	(131,045)	(10,865)	(57,683)
Total income taxes	(132,326)	(13,996)	(57,678)
Net income (loss)	(553,828)	(39,767)	117,848
Net income attributable to non-controlling interest	51	5,521	0
Net income (loss) attributable to Unit Corporation	$ (553,879)	$ (45,288)	$ 117,848
Net income (loss) attributable to Unit Corporation per common share (Note 6):
Basic	$ (10.48)	$ (0.87)	$ 2.31
Diluted	$ (10.48)	$ (0.87)	$ 2.28
Oil and Natural Gas
Revenues:
Revenues	$ 325,797	$ 423,059	$ 357,744
Operating costs:
Operating costs	135,124	131,675	130,789
Contract drilling
Revenues:
Revenues	168,383	196,492	174,720
Operating costs:
Operating costs	115,998	131,385	122,600
Gas gathering and processing
Revenues:
Revenues	180,454	223,730	207,176
Operating costs:
Operating costs	$ 133,606	$ 167,836	$ 155,483

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (553,828)	$ (39,767)	$ 117,848
Other comprehensive income (loss), net of taxes:
Unrealized gain (loss) on securities, net of tax of $0, ($181), and $39	0	(557)	63
Reclassification adjustment for write-down of securities, net of tax of ($47), $0, and $0	481	0	0
Unrealized loss on securities, tax	0	(181)	39
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	(47)	0	0
Comprehensive income (loss)	(553,347)	(40,324)	117,911
Less: Comprehensive income attributable to non-controlling interest	51	5,521	0
Comprehensive income (loss) attributable to Unit Corporation	$ (553,398)	$ (45,845)	$ 117,911

Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Capital In Excess of Par Value	Accumulated Other Comprehensive Loss	Retained Earnings	Non-controlling Interest in Consolidated Subsidiaries
Beginning 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
Reclassification adjustment for write-down of securities	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
Reclassification adjustment for write-down of securities	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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect adjustment for adoption of ASUs	174	0	0	0	174	0
Net income (loss)	(553,828)				(553,879)	51
Total comprehensive income (loss)	(553,347)
Reclassification adjustment for write-down of securities	481	0	0	481	0	0
Distributions to non-controlling interest	(918)	0	0	0	0	(918)
Activity in employee compensation plans	16,282	177	16,044	0	0	61
Ending balance at Dec. 31, 2019	$ 1,055,635	$ 10,591	$ 644,152	$ 0	$ 199,135	$ 201,757

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock Issued During Period, Shares, New Issues	0	0	787,547
Activity in employee compensation plans (shares)	1,387,793	1,175,466	598,269
Unrealized loss on securities, tax	$ 0	$ (181)	$ 39
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	$ (47)	$ 0	$ 0

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
OPERATING ACTIVITIES:
Net income (loss)	$ (553,828)	$ (39,767)	$ 117,848
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	275,573	243,605	209,257
Impairments (Note 3)	625,716	147,884	0
Amortization of debt issuance costs and debt discount (Note 8)	2,241	2,198	2,159
(Gain) loss on derivatives (Note 14)	(4,225)	3,184	(14,732)
Derivative Instruments Not Designated Amount Paid (Received) During Period	16,196	(22,803)	173
(Gain) loss on disposition of assets	3,502	(704)	(327)
Deferred tax benefit (Note 10)	(131,045)	(10,865)	(57,683)
Employee stock compensation plans	12,932	22,899	17,747
Bad debt expense	527	81	348
ARO liability accretion (Note 9)	2,343	2,393	2,886
Contract assets and liabilities, net (Note 4)	2,577	4,970	0
Other, net	1,766	2,032	(865)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	33,323	(7,967)	(27,941)
Materials and supplies	24	32	2,835
Prepaid expenses and other	195	(4,950)	1,527
Accounts payable	(15,558)	28,013	8,192
Accrued liabilities	3,142	(5,465)	6,996
Income taxes	298	(1,993)	38
Contract advances	(1,149)	(90)	1,630
Net cash provided by operating activities	269,396	352,747	270,088
INVESTING ACTIVITIES:
Capital expeditures	(406,665)	(446,282)	(255,553)
Producing property and other oil and natural gas acquisitions	(3,653)	(29,970)	(58,026)
Payments to Acquire Other Property, Plant, and Equipment	(16,109)	0	0
Proceeds from disposition of property and equipment	31,864	25,910	21,713
Other	0	0	(1,500)
Net cash used in investing activities	(394,563)	(450,342)	(293,366)
FINANCING ACTIVITIES:
Borrowings under line of credit	493,500	99,100	343,900
Payments under line of credit	(368,800)	(277,100)	(326,700)
Payments on finance leases	(4,001)	(3,843)	(3,694)
Proceeds from common stock issued, net of issue costs (Note 19)	0	0	18,623
Proceeds from investments of non-contolling interests	0	300,000	0
Payments Related to Tax Withholding for Share-based Compensation	(4,158)	(4,988)	(4,132)
Transaction costs associated with sale of non-controlling interest	0	(2,503)	0
Payments to Noncontrolling Interests	(918)	0	0
Bank overdrafts (Note 3)	3,663	(7,320)	(4,911)
Net cash provided by financing activities	119,286	103,346	23,086
Net increase (decrease) in cash and cash equivalents	(5,881)	5,751	(192)
Cash and cash equivalents, beginning of year	6,452	701	893
Cash and cash equivalents, end of year	571	6,452	701
Supplemental disclosure of cash flow information:
Interest paid (net of capitalization)	33,694	34,535	33,931
Income taxes	273	3,600	0
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	54,549	(18,119)	(20,574)
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	$ (76)	$ 7,629	$ 3,613

Organization	12 Months Ended
Organization	Dec. 31, 2019
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, New Mexico, Wyoming, North Dakota, and to a lesser extent in Colorado. 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.

Liquidity and Ability to Continue as a Going Concern	12 Months Ended
Liquidity and Ability to Continue as a Going Concern	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Substantial Doubt about Going Concern [Text Block]	UNIT LIQUIDITY AND ABILITY TO CONTINUE AS A GOING CONCERN As a result of the sustained commodity price decline and our substantial debt burden, we do not believe that we will be able to satisfy our commitments and debt repayments over the next twelve months. This conclusion is based on the following principal conditions which are explained in further detail below. •Inability to meet anticipated commitments due to recurring losses, negative working capital and limited access to liquidity. •A forecasted covenant violation of the Unit credit agreement for the quarter ending June 30, 2020. •The expected acceleration of the amounts outstanding under the Unit credit agreement from October 18, 2023 to November 16, 2020. The company has incurred significant losses and is in a negative working capital position at December 31, 2019. Additionally, our cash balance as of December 31, 2019 was $0.6 million and, effective January 17, 2020, the company’s borrowing base under the Unit credit facility was reduced to $200.0 million of which $108.2 million has been borrowed. On March 11, 2020, the Company entered into a Standstill agreement with regards to the Unit credit facility which delays the scheduled borrowing base redetermination date for the facility from April 1, 2020 to April 15, 2020. Once the borrowing base is redetermined, the company anticipates that the borrowing base will be further reduced, potentially below the current amount outstanding under the credit facility. Such a reduction would prevent the company from further accessing the facility. Additionally, under the Standstill agreement, the company is prevented from withdrawing more than an additional $15.0 million between March 11, 2020 and the expiration of the agreement on April 15, 2020, which further reduces the company’s ability to access liquidity during the term of the agreement. Due to our further anticipated losses, negative working capital position and lack of access to liquidity under the credit agreement, we do not anticipate that forecasted cash and available credit capacity will be sufficient to meet our commitments as they come due over the next twelve months. Additionally, once the amounts outstanding on our 2021 Senior Notes are classified as current on our June 30, 2020 balance sheet, we will be in violation of the current ratio covenant in our credit agreement. If we are unable to cure the covenant violation, renegotiate the terms of the credit agreement or obtain a waiver, the covenant violation would result in all amounts outstanding under the Unit credit agreement becoming due and payable during the third quarter of 2020 (after we file our second quarter Form 10-Q). The covenant violation would also cause a cross-default of the indenture on our 2021 Senior Notes, which would make those notes immediately due and payable. The amounts outstanding as of December 31, 2019 on our Unit credit agreement and 2021 Senior Notes are $108.2 million and $650.0 million, respectively. If we are unable to avoid the anticipated credit violation or otherwise obtain a waiver, we will be unable to pay these amounts when due. In addition, the October 18, 2023 scheduled maturity date of the loans under the Unit credit agreement will accelerate to November 16, 2020 to the extent that, on or before that date, all the 2021 Senior Notes are not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (the “Credit Agreement Extension Condition”). On November 5, 2019, the company filed with the SEC a registration statement on Form S-4 (the Registration Statement) to commence an offer to exchange (the Exchange Offer) any and all of the existing 2021 Senior Notes for new notes with terms and conditions that would satisfy the Credit Agreement Extension Condition. However, there can be no assurance that the company will be able to complete the Exchange Offer as contemplated, if at all. Due to the Credit Agreement Extension Condition, the company's debt associated with the Unit credit agreement is reflected as a current liability in its consolidated balance sheet as of December 31, 2019. The classification as a current liability is based on the uncertainty regarding the company's ability to repay or refinance the 2021 Senior Notes before November 16, 2020. Based on our current forecasted cash flows and cash on hand, we will not be able to pay the outstanding amount of the Unit credit agreement if the maturity is accelerated. Inability to pay the amount outstanding under the credit agreement would cause a covenant violation and also create cross-default with the indenture of the 2021 Senior Notes, which would also become due and payable. If we are unable to pay the balance of the Unit credit agreement upon acceleration, we would be required to file for protection under Chapter 11 of the U.S. Bankruptcy Code (Chapter 11). Based on our evaluation of the conditions described above, substantial doubt exists about our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. In order to alleviate the conditions that give rise to substantial doubt about our ability to continue as a going concern, the company is currently undertaking a number of actions, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, (iv) exploring potential business transactions, and (v) negotiating with existing debt holders to restructure existing debts. We believe that even after taking these actions, we will not have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with our debt covenants. We have engaged financial and legal advisors to, among other things, assist with analyzing various strategic alternatives, to include a potential reorganization under Chapter 11, to address our liquidity and capital structure. However, there can be no assurance that we will be able to restructure our financial obligations on terms acceptable to the company and our creditors, and there can be no assurance that we will generate the necessary liquidity to satisfy these obligations when they come due.

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

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 18 – 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, 2019, all of our contracts were daywork contracts of which 14

were multi-well and had durations which ranged from two months to three years, 10 of which expire in 2020 and four expiring in 2021 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 Bank 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. Bank 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, 2019 and 2018, bank overdrafts were $8.7 million and $5.1 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:


	2019		2018		2017
Oil and Natural Gas:
CVR Refining, LP	14	%	14	%	2	%
Valero Energy Corporation	9	%	10	%	9	%
Energy Transfer Partners (formerly Sunoco Logistics Partners)	5	%	3	%	10	%
Drilling:
EOG Resources, Inc.	12	%	5	%	—	%
QEP Resources, Inc.	12	%	16	%	26	%
Slawson Exploration Company, Inc	11	%	10	%	6	%
Mid-Stream:
ONEOK, Inc.	33	%	45	%	36	%
Range Resources Corporation	13	%	7	%	9	%
Centerpoint Energy Service, Inc.	10	%	5	%	4	%

We had a concentration of cash of $1.7 million and $11.0 million at December 31, 2019 and 2018, 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, 2019 and determined there was no material risk at that time. At December 31, 2019, 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:


	December 31, 2019
	(In millions)
Bank of Montreal	$	0.4
Bank of America Merrill Lynch	0.2
Total net assets	$	0.6

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 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.

During the third quarter of 2019, we determined a triggering event had occurred within our contract drilling reporting unit due to a decline in the number of drilling rigs being used and the overall market performance of the contract drilling industry. As a result, we performed a recoverability test on long-lived assets within the segment. Based on the results of the undiscounted future cash flows of the asset group, the undiscounted projected future cash flows of the asset group exceeded the group's carrying value as of September 30, 2019 and therefore no long-lived asset impairment was recorded for the group.

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. The plan included a strategic decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs 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 use based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, in December 2018, 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, 2019 is $5.9 million. These assets include seven drilling rigs and equipment that will be marketed for sale throughout the next twelve months. As of December 31, 2019, we determined that $10.8 million of the assets held for sale would not be sold in the next twelve months and were moved back to long-lived assets. 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 2019 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 2019, 2018, and 2017, interest of approximately $16.2 million, $16.5 million, and $15.9 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For 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. Due to the triggering event within the contract drilling reporting unit, we performed an interim goodwill impairment test as of September 30, 2019. Based on the projected discounted cash flows, we recognized a goodwill impairment charge of $62.8 million, pre-tax ($59.8 million, net of tax) which represented the total goodwill previously reported on our consolidated balance sheets. No goodwill impairment was recorded for the years ended December 31, 2018, or 2017. There were no additions to goodwill in 2019, 2018, or 2017.

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 $16.5 million, $15.9 million, and $14.8 million were capitalized in 2019, 2018, and 2017, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $9.66, $7.50, and $6.00 per Boe in 2019, 2018, and 2017, 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 $252.9 million are excluded from the DD&A calculation.

During the fourth quarter 2019, we reassessed estimated salvage values associated with our oil and natural gas operations. Based on market conditions for our industry as well as the substantial doubt that exists for our ability to continue as a going concern, we revised these estimates downward for a total adjustment of $39.7 million ($25.6 million discounted for our full cost ceiling test) to salvage value estimates.

No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved. Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $73.9 million and $10.5 million in 2019 and 2017, respectively of costs being added to the total of our capitalized costs being amortized. We did not have any in 2018. In 2019, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million net of tax) due to the reduction of the 12-month average commodity prices and the removal of proved undeveloped reserves due to the uncertainty regarding our ability to finance future capital expenditures. 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 $15.8 million, $22.5 million, and $13.4 million during 2019, 2018, and 2017, respectively, from our contract drilling segment and eliminated the associated operating expense of $14.2 million, $19.5 million, and $11.8 million during 2019, 2018, and 2017, respectively, yielding $1.6 million, $3.0 million, and$1.6 million during 2019, 2018, and 2017, respectively, as a reduction to the carrying value of our oil and natural gas properties.

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 was a general partner in 13 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees owned the interests in most of these partnerships. We shared in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimbursed us for certain administrative costs incurred on behalf of the partnerships. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.

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. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the 2017 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, 2019 balancing position to be approximately 3.4 Bcf on under-produced properties and approximately 3.5 Bcf on over-produced properties. We have recorded a receivable of $3.6 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 $3.8 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

Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable and certain debt securities, with a current expected credit loss model. The amendment will be effective for reporting periods after December 15, 2019. We have evaluated the impact this will have on our consolidated financial statements by reviewing our accounts receivable accounts and our historic credit losses. This standard will not have a material impact on our financial statements.

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.

Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to reduce the cost and complexity related to the accounting for income taxes. The amendment will be effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. We are evaluating what impact this standard will have on our consolidated financial statements.

Adopted Standards

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 is effective for years beginning after December 15, 2018, and interim periods within those years. This amendment did not have an impact on our financial statements.

We adopted ASC 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.

The additional disclosures required by ASC 842 have been included in Note 16 – Leases.

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. We have early adopted this amendment in the third quarter of 2019. We performed our goodwill assessment and booked the impairment for the difference between fair value and book value.

Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer

REVENUE FROM CONTRACTS 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 20 – 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—are 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.

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 two 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, 2019, we had 21 contract drilling contracts (14 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.

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 as of December 31, 2019.


Contract	Remaining Term of Contract	2020		2021		2022		2023 and beyond	Total Remaining Impact to Revenue

Demand fee contracts	3-9 years	$	(3,775)	$	(3,501)	$	1,380	36	$	(5,860)

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). Revenue recognized for these demand fees was $2.6 million and $5.0 million in 2019 and 2018, respectively.


	December 31, 2019		December 31, 2018		Change
	(In thousands)
Contract assets	$	12,921	$	13,164	$	(243)
Contract liabilities	7,061		9,881		(2,820)
Contract assets (liabilities), net	$	5,860	$	3,283	$	2,577

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

Oil and Natural Gas

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 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.


Purchase Price
Total consideration given	$	29,633

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.

For 2019, we had approximately $3.7 million in acquisitions.

Mid-Stream

In December 2019, we closed on an acquisition for $16.1 million that included approximately 572 miles of pipeline and related compressor stations. The transaction closed on December 30, 2019 with an effective date of December 01, 2019 and was accounted for as an asset acquisition.

Divestitures

Oil and Natural Gas

We had non-core asset sales with proceeds, net of related expenses, of $21.8 million, $22.5 million, and $18.6 million, in 2019, 2018, and 2017, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.

Contract Drilling

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. The plan included a strategic decision to focus on our new BOSS drilling rigs and specific SCR drilling rigs 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 use based on the estimated market value from third-party assessments (Level 3 fair value measurement) less cost to sell. Based on these estimates, in December 2018, we recorded a non-cash write-down of approximately $147.9 million, pre-tax ($111.7 million, net of tax). During 2019, we sold six of these drilling rigs and some of the other equipment to unaffiliated third parties. The proceeds of those sales, less costs to sell, was more than the applicable $5.7 million net book value resulting in a gain of $1.1 million. As of December 31, 2019, we determined that $10.8 million of the assets held for sale would not be sold in the next twelve months and were moved back to long-lived assets. Seven drilling rigs and equipment will be marketed for sale throughout the next twelve months and remain classified as assets held for sale. The net book value of those assets is $5.9 million

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 18 – Variable Interest Entity Arrangements.

Earnings (Loss) Per Share

12 Months Ended

Dec. 31, 2019

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, 2017:
Basic earnings attributable to Unit Corporation per common share	$	117,848	51,113	$	2.31
Effect of dilutive stock options and restricted stock	—		635	(0.03)
Diluted earnings 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 stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(45,288)	51,981	$	(0.87)
For the year ended December 31, 2019:
Basic loss attributable to Unit Corporation per common share	(553,879)		52,849	$	(10.48)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(553,879)	52,849	$	(10.48)

Due to the net loss for the years ended December 31, 2018 and 2019, approximately 934,000 and 428,000, respectively, weighted average shares related to stock options and restricted stock 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 (loss) per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31:


	2019		2018		2017
Stock options	42,000		66,500		87,500
Average exercise price	$	48.56	$	44.42	$	51.34

Accrued Liabilities

12 Months Ended

Dec. 31, 2019

Accrued Liabilities [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following as of December 31:


	2019		2018
	(In thousands)
Employee costs	$	17,832	$	20,315
Lease operating expenses	9,200		12,756
Interest payable	6,562		6,635
Third-party credits	3,691		2,129
Taxes	3,450		1,378
Other	5,827		4,710
Total accrued liabilities	$	46,562	$	47,923

Long-Term Debt And Other Long-Term Liabilities

12 Months Ended

Dec. 31, 2019

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:


	2019		2018
	(In thousands)
Current portion of long-term debt:
Unit credit agreement with an average interest rate of 4.0% at December 31, 2019	$	108,200	$	—
Long-term debt:
Superior credit agreement with an average interest rate of 3.9% at December 31, 2019	16,500		—
6.625% senior subordinated notes due 2021	650,000		650,000
Total principal amount	$	666,500	$	650,000
Less: unamortized discount	(971)		(1,623)
Less: debt issuance costs, net	(2,313)		(3,902)
Total long-term debt	$	663,216	$	644,475

Unit Credit Agreement. We have engaged in discussions with the lenders under our Senior Credit Agreement (Unit credit agreement) to enter into an amendment to the Unit credit agreement to, among other things, permit the issuance of new Second Lien Senior Secured Notes (the New Notes), the incurrence of guarantees of the New Notes and the grant of liens securing the New Notes, each of which is currently not permitted under the Unit credit agreement. Due to the Credit Agreement Extension Condition, the company's debt associated with the Unit credit agreement is reflected as a current liability in its consolidated balance sheet as of December 31, 2019. The classification as a current liability is based on the uncertainty regarding the company's ability to repay or refinance the 2021 Senior Notes before November 16, 2020.

Our Unit credit agreement is scheduled to mature on the earlier of (a) October 18, 2023, (b) November 16, 2020, to the extent that, on or before that date, all senior subordinated notes (the Notes) are not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023, and (c) any earlier date on which the commitment amounts under the Unit credit agreement are reduced to zero or otherwise terminated. Under that 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 amount of $1.0 billion. Effective September 26, 2019, our elected commitment amount and borrowing base are both $275.0 million. 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. Under the mortgages covering such oil and gas properties, Unit Petroleum has also pledged as collateral certain items of its personal property.

On May 2, 2018, 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. Effective September 26, 2019, our borrowing base was reduced from $425.0 million to $275.0 million.

Effective January 17, 2020, our elected commitment amount and borrowing base were reduced to $200.0 million.

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. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest is payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty.

We can use borrowings to finance general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets up to certain limits, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, 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 and with certain limited exceptions, on any of our properties, except in favor of 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, 2019, we were in compliance with these covenants.

Superior Credit Agreement. On May 10, 2018, Superior signed 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. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index.

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. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of December 31, 2019, Superior complied with these 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.

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, 2019.

If an event of default occurs under the Unit credit agreement that accelerates the maturity of at least $25.0 million of borrowings, then it will cause a default under the 2011 Indenture which may in turn accelerate the maturity of the Notes.

On November 5, 2019, we filed with the SEC a registration statement on Form S-4 (the Registration Statement) with respect to an offer to exchange (the Exchange Offer) any and all of our existing Notes for the New Notes, on the terms and conditions in the Registration Statement, and the related consent solicitation. The Registration Statement is not yet effective.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following as of December 31:


	2019		2018
	(In thousands)
ARO liability	$	66,627	$	64,208
Workers’ compensation	11,510		12,738
Finance lease obligations	7,379		11,380
Contract liability	7,061		9,881
Separation benefit plans	10,122		8,814
Deferred compensation plan	6,180		5,132
Gas balancing liability	3,838		3,331
	112,717		115,484
Less current portion	17,376		14,250
Total other long-term liabilities	$	95,341	$	101,234

Estimated annual principal payments under the terms of debt and other long-term liabilities from 2020 through 2024 are $125.6 million, $659.3 million, $45.1 million, $19.5 million, and $2.0 million, respectively.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

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:


	2019		2018
	(In thousands)
ARO liability, January 1:	$	64,208	$	69,444
Accretion of discount	2,343		2,393
Liability incurred	4,373		2,632
Liability settled	(3,261)		(4,493)
Liability sold	(2,953)		(281)
Revision of estimates ⁽¹⁾	1,917		(5,487)
ARO liability, December 31:	66,627		64,208
Less current portion	2,920		1,437
Total long-term ARO liability	$	63,707	$	62,771

_________________________

1.Plugging liability estimates were revised in both 2019 and 2018 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, 2019

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.

During the third quarter of 2019, we recognized a goodwill impairment charge of $62.8 million. Approximately $50.3 million of this amount was not deductible for income taxes resulting in a reduction of our effective tax rate and reduction of our income tax benefit of approximately $12.3 million for 2019.

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:


	2019		2018		2017
	(In thousands)
Income tax expense (benefit) computed by applying the statutory rate	$	(144,092)	$	(11,290)	$	21,059
State income tax expense (benefit), net of federal benefit	(21,733)		(1,882)		1,655
Deferred tax liability revaluation ⁽¹⁾	—		—		(81,307)
Restricted stock shortfall	347		424		1,867
Non-controlling interest in Superior	(11)		(1,138)		—
Goodwill impairment	12,346		—		—
Valuation allowance	19,654		—		—
Statutory depletion and other	1,163		(110)		(952)
Income tax benefit	$	(132,326)	$	(13,996)	$	(57,678)

__________________________

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

For the periods indicated, the total provision for income taxes consisted of the following:


	2019		2018		2017
	(In thousands)
Current taxes:
Federal	$	(918)	$	(1,835)	$	—
State	(363)		(1,296)		5
	(1,281)		(3,131)		5
Deferred taxes:
Federal	(108,440)		(8,741)		(62,788)
State	(22,605)		(2,124)		5,105
	(131,045)		(10,865)		(57,683)
Total provision	$	(132,326)	$	(13,996)	$	(57,678)

Deferred tax assets and liabilities are comprised of the following at December 31:


	2019		2018
	(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals	$	31,822	$	27,953
Net operating loss carryforward	246,927		152,112
Alternative minimum tax and research and development tax credit carryforward	2,656		3,574
	281,405		183,639
Deferred tax liability:
Depreciation, depletion, amortization, and impairment	(226,034)		(291,542)
Investment in Superior	(49,430)		(36,845)
Net deferred tax asset (liability)	5,941		(144,748)
Valuation allowance	(19,654)		—
Current deferred tax asset	—		—
Non-current—deferred tax liability	$	(13,713)	$	(144,748)

A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. To the extent a valuation allowance is established or is increased or decreased during a period, there is a corresponding expense or reduction of expense within the tax provision in the consolidated statement of operations.

During the year ended December 31, 2019, in evaluating whether it was more likely than not that the company's deferred tax assets were realizable through future net income, we considered all available positive and negative evidence, including (i) our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition, (ii) our ability to recover net operating loss carryforward deferred tax assets in future years, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) future revenue and operating cost projections that indicate the company will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures and (vii) current market prices for oil, NGL and natural gas. Based on all the evidence available, we determined it was more likely than not that the deferred tax asset for net operating loss carryforwards were not fully realizable. As of December 31, 2019, a total valuation allowance of $19.7 million has been recorded.

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, 2019, we have expected federal net operating loss carryforwards of approximately $980.8 million of which $584.2 million will expire from 2021 to 2037.

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2019
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 310,797, 184,203, and 155,822 shares of common stock and recognized expense of $5.2 million, $5.1 million, and $4.4 million in 2019, 2018, and 2017, respectively. In 2020, the contribution under the plan for 2019 was made in cash instead of shares of common stock. We provide a salary deferral plan for our executives (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, 2019 and 2018 was $6.2 million and $5.1 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral. Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments, and the circumstances under which employees become eligible to receive benefits. On December 8, 2015, we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $3.8 million, $3.6 million, and $2.7 million in 2019, 2018, and 2017, 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, 2019

Transactions With Related Parties

TRANSACTIONS WITH RELATED PARTIESUnit Petroleum Company served 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 partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.

Amounts received in the years ended December 31, from both public and private Partnerships for which Unit was a general partner are as follows:


	2019		2018		2017
	(In thousands)
Well supervision and other fees	$	1	$	158	$	172
General and administrative expense reimbursement	—		—		—

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.

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 several states. 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 $0.4 million, $0.9 million, and $0.7 million during 2019, 2018, and 2017, 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, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

STOCK-BASED COMPENSATION

For restricted stock awards, we had:


	2019		2018		2017
	(In millions)
Recognized stock compensation expense	$	12.8	$	17.8	$	13.3
Capitalized stock compensation cost for our oil and natural gas properties	2.4		2.1		1.8
Tax benefit on stock based compensation	3.1		4.4		5.0

The remaining unrecognized compensation cost related to unvested awards at December 31, 2019 is approximately $13.1 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 0.7 of a year.

The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) 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

In 2017, all of the remaining SARs were forfeited. There were no SARs granted or vested during 2019, 2018, or 2017. The SARs expired after 10 years from the date of the grant, and there were no outstanding shares at December 31, 2019.

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, 2017	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
Granted	927,173	500,256	1,427,429	16.09
Vested	(570,107)	(233,835)	(803,942)	15.56
Forfeited	(98,301)	(33,172)	(131,473)	19.36
Nonvested at December 31, 2019	1,527,648	841,374	2,369,022	$	18.95


Non-Employee Directors	Number of Shares	Weighted Average Price
Nonvested at January 1, 2017	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
Granted	72,784	12.09
Vested	(61,141)	15.49
Forfeited	—	—
Nonvested at December 31, 2019	118,688	$	14.83

The time vested restricted stock awards granted are being recognized over a three year vesting period. Each year, 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, 2019, the participants are estimated to receive 3% of the 2019, 45% of the 2018, and 0% of the 2017 performance based shares. The CFTA performance measurement at December 31, 2019 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 2019, 2018, and 2017 at the grant date was $22.6 million, $24.7 million, and $17.4 million, respectively. The aggregate intrinsic value of the 865,083 shares of restricted stock that vested in 2019 on their vesting date was $11.9 million. The aggregate intrinsic value of the 2,487,710 shares of restricted stock outstanding subject to vesting at December 31, 2019 was $1.7 million with a weighted average remaining life of 1.0 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.

Activity pertaining to the Directors’ Plan is as follows:


	Number of Shares	Weighted Average Exercise Price
Outstanding at January 1, 2017	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
Granted	—	—
Exercised	—	—
Forfeited	(24,500)	37.31
Outstanding at December 31, 2019	42,000	$	48.56


	Outstanding and Exercisable Options at December 31, 2019
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$41.21	17,500	0.3 years	$	41.21
$53.81	24,500	1.3 years	$	53.81

There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2019. The remaining weighted average remaining contractual term is 0.9 years.

Derivatives

12 Months Ended

Dec. 31, 2019

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, 2019, our derivative transactions consisted of the following types of hedges:

•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.

•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, 2019, the following non-designated hedges were outstanding:

Term

Commodity

Contracted Volume

Weighted Average

Fixed Price for Swaps

Contracted Market

Jan'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Jan'20 - Dec'20

Natural gas - basis swap

20,000 MMBtu/day

$(0.455)

PEPL

Jan'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Jan'20 - Dec'20

Natural gas - three-way collar

30,000 MMBtu/day

$2.50 - $2.20 - $2.80

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	2019		2018
		(In thousands)
Commodity derivatives:
Current	Current derivative assets	$	633	$	12,870
Long-term	Non-current derivative assets	—		—
Total derivative assets		$	633	$	12,870


		Derivative Liabilities Fair Value
	Balance Sheet Location	2019		2018
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	—	$	—
Long-term	Non-current derivative liabilities	27		293
Total derivative liabilities		$	27	$	293

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
				2019		2018
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	4,225	$	(3,184)
Total		$	4,225	$	(3,184)

_________________________

1.Amounts settled during the periods are a gain of $16,196 and a loss of $22,803, respectively.

Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTSFair 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 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, 2019
	Level 2		Level 3		Effect of Netting		Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	177	$	1,204	$	(748)	$	633
Liabilities	(775)		—		748		(27)
	$	(598)	$	1,204	$	—	$	606


	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

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, 2019.

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, 2019		December 31, 2018
	(In thousands)
Beginning of period	$	10,630	$	(206)
Total gains or losses:
Included in earnings	(1,494)		4,159
Settlements	(7,932)		6,677
End of period	$	1,204	$	10,630
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	(9,426)	$	10,836

The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2019:

Commodity ⁽¹⁾

Fair Value

Valuation Technique

Unobservable Input

Range

(In thousands)

Natural gas three-way collar

1,204

Discounted cash flow

Forward commodity price curve

$0.00 - $0.39

_________________________

1.The commodity contracts detailed in this category include non-exchange-traded natural gas three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.

Based on our valuation at December 31, 2019, 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, 2019, 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 at December 31, 2019 would approximate its fair value. This debt would be classified as Level 2.

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, 2019 and December 31, 2018 were $646.7 million and $644.5 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2019 and December 31, 2018 were $357.5 million and $600.5 million, respectively. These Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the company’s AROs is presented in Note 9 – 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 2018 and 2019, we recorded non-cash impairment charges discussed further in Note 3 – Summary

Of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as Level 3.

Leases

12 Months Ended

Dec. 31, 2019

Variable Interest Entity Arrangements [Abstract]

Leases

LEASES

Operating Leases under ASC 840

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through December 2021. We own our corporate headquarters in Tulsa, Oklahoma. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. As of December 31, 2018, future minimum rental payments under the terms of the leases under ASC 840 were approximately $4.6 million, $1.7 million, and $0.4 million in 2019 through 2021, respectively.

Operating Leases under ASC 842

Adoption of Accounting Standards Codification (ASC) Topic 842, “Leases." We adopted Topic 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.

We determine whether a contract is or contains a lease at inception of the contract based on whether an identified asset exists and whether we have the right to obtain substantially all the benefit of the assets and to control its use over the full term of the agreement. When available, we use the rate implicit in the lease to discount lease payments to present value; however, most of our leases do not provide a readily determinable implicit rate. Therefore, we must estimate our incremental borrowing rate considering both the revolving credit rates and a credit notching approach to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees and no restrictions or covenants included in our lease agreements. Certain of our leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput or actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets.

Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of another asset in accordance with other U.S. GAAP. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the company’s short-term lease commitments. As of December 31, 2019, we had an average working interest of 95% in our operated properties.

Practical Expedients and Policies Elected. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things, allowed us to carry forward the historical lease classification; and the land easement expedient, which allowed us to apply the guidance prospectively at adoption for land easements on existing agreements. We applied the short-term policy election, which allowed us to exclude from recognition on the balance sheet leases with an initial term of 12 months or less. We considered quantitative and qualitative factors when determining the application of the practical expedient that allowed us not to separate lease and non-lease components and are accounting for the agreements as a single lease component.

We routinely enter into related party agreements between our three segments. These agreements have been evaluated under the guidance of ASC 842. Routinely, our oil and natural gas segment contracts for the use of drilling equipment from our drilling segment.

We have determined that the contracting of our drilling segment's drilling rigs will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract per the lessor practical expedient.

Adoption. Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Consolidated Balance Sheet of $3.7 million and $3.5 million, respectively, as of January 1, 2019, which represents noncash operating activity. The immaterial difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases remained substantially unchanged.

Leases. We lease certain office space, land and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in our lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include options to purchase the leased property.

The following table shows supplemental cash flow information related to leases for the year ended December 31, 2019:


	Amount
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	4,034
Financing cash flows for finance leases	4,001
Lease liabilities recognized in exchange for new operating lease right of use assets	5

The following table shows information about our lease assets and liabilities included in our Consolidated Balance Sheet as of December 31, 2019:

Classification on the Consolidated Balance Sheet

December 31,
2019

(In thousands)

Assets

Operating right of use assets

Right of use assets

5,673

Finance right of use assets

Property, plant, and equipment, net

17,396

Total right of use assets

23,069

Liabilities

Current liabilities:

Operating lease liabilities

Current operating lease liabilities

3,430

Finance lease liabilities

Current portion of other long-term liabilities

4,164

Non-current liabilities:

Operating lease liabilities

2,071

Finance lease liabilities

Other long-term liabilities

3,215

Total lease liabilities

12,880

The following table shows certain information related to the lease costs for our finance and operating leases for the year indicated:


	2019

Components of total lease cost:
Amortization of finance leased assets	$	4,001
Interest on finance lease liabilities	382
Operating lease cost	4,034
Short-term lease cost ⁽¹⁾	38,868
Variable lease cost	351
Total lease cost	$	47,636

_______________________

1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $25.1 million.

The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:


	Weighted Average Remaining Lease Term	Weighted Average Discount Rate ⁽¹⁾
	(In years)
Operating leases	1.9	6.13%
Finance leases	1.7	4.00%

_______________________

1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our operating lease liabilities as of December 31, 2019:


	Amount
	(In thousands)
Ending January 1,
2021	$	3,670
2022	1,614
2023	419
2024	73
2025	12
2026 and beyond	75
Total future payments	5,863
Less: Interest	362
Present value of future minimum operating lease payments	5,501
Less: Current portion	3,430
Total long-term operating lease payments	$	2,071

Finance Leases

During 2014, our mid-stream segment entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our finance lease obligations of $4.2 million is included in current portion of other long-term liabilities and the non-current portion of $3.2 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2019. These finance leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $2.3 million and $0.3 million, respectively at December 31, 2019. Annual payments, net of maintenance and interest, average $4.4 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 finance leases at December 31, 2019 are as follows:


	Amount
Ending January 1,	(In thousands)
2021	$	6,194
2022	3,774
Total future payments	9,968
Less payments related to:
Maintenance	2,336
Interest	253
Present value of future minimum payments	7,379
Less: Current portion	4,164
Total long-term finance lease payments	$	3,215

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES The employee oil and gas limited partnerships required, 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 were limited to 20% of the units outstanding. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest. 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. During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is included in our future drilling plans. For each dollar of the $150.0 million that we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. At December 31, 2019, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.7 million. Total spent towards the $150.0 million as of December 31, 2019 was $24.7 million. For 2019, we have committed to purchase approximately $0.9 million of new pipe and equipment. We have firm transportation commitments to transport our natural gas from various systems for approximately $2.8 million over the next twelve months and $0.7 million for the two years thereafter. 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, 2019

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, 2019.

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 $255,970. 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, 2019		December 31, 2018
	(In thousands)
Current assets:
Cash and cash equivalents	$	—	$	5,841
Accounts receivable	21,073		33,207
Prepaid expenses and other	7,686		1,049
Total current assets	28,759		40,097
Property and equipment:
Gas gathering and processing equipment	824,699		767,388
Transportation equipment	3,390		3,086
	828,089		770,474
Less accumulated depreciation, depletion, amortization, and impairment	407,144		364,740
Net property and equipment	420,945		405,734
Right of use assets	3,948		—
Other assets	9,442		17,551
Total assets	$	463,094	$	463,382

Current liabilities:
Accounts payable	$	18,511	$	32,214
Accrued liabilities	4,198		3,688
Current operating lease liability	2,407		—
Current portion of other long-term liabilities	7,060		6,875
Total current liabilities	32,176		42,777
Long-term debt less debt issuance costs	16,500		—
Operating lease liability	1,404		—
Other long-term liabilities	8,126		14,687
Total liabilities	$	58,206	$	57,464

Equity	12 Months Ended
Equity	Dec. 31, 2019
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.

Industry Segment Information

12 Months Ended

Dec. 31, 2019

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, 2019
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	325,797	$	—	$	—	$	—	$	—	$	325,797
Contract drilling	—		184,192		—		—		(15,809)		168,383
Gas gathering and processing	—		—		227,939		—		(47,485)		180,454
Total revenues	325,797		184,192		227,939		—		(63,294)		674,634
Expenses:
Operating costs:
Oil and natural gas	140,026		—		—		—		(4,902)		135,124
Contract drilling	—		130,188		—		—		(14,190)		115,998
Gas gathering and processing	—		—		176,189		—		(42,583)		133,606
Total operating costs	140,026		130,188		176,189		—		(61,675)		384,728
Depreciation, depletion, and amortization	168,651		51,552		47,663		7,707		—		275,573
Impairments ⁽²⁾	559,867		62,809		3,040		—		—		625,716
Total expenses	868,544		244,549		226,892		7,707		(61,675)		1,286,017
General and administrative	—		—		—		38,246		—		38,246
(Gain) loss on disposition of assets	(199)		3,872		(160)		(11)		—		3,502
Income (loss) from operations	(542,548)		(64,229)		1,207		(45,942)		(1,619)		(653,131)
Gain on derivatives	—		—		—		4,225		—		4,225
Interest expense, net	—		—		(1,546)		(35,466)		—		(37,012)
Other	(481)		(605)		827		23		—		(236)
Income (loss) before income taxes	$	(543,029)	$	(64,834)	$	488	$	(77,160)	$	(1,619)	$	(686,154)

Identifiable assets:
Oil and natural gas ⁽³⁾	$	851,662	$	—	$	—	$	—	$	(4,264)	$	847,398
Contract drilling	—		708,510		—		—		(42)		708,468
Gas gathering and processing	—		—		463,699		—		(4,255)		459,444
Total identifiable assets ⁽⁴⁾	851,662		708,510		463,699		—		(8,561)		2,015,310
Corporate land and building	—		—		—		54,155		—		54,155
Other corporate assets ⁽⁵⁾	—		—		—		23,092		(2,505)		20,587
Total assets	$	851,662	$	708,510	$	463,699	$	77,247	$	(11,066)	$	2,090,052

Capital expenditures:	$	268,622	$	40,636	$	64,438	$	673	$	—	$	374,369

_______________________

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.We incurred non-cash ceiling test write-down of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax).

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, 2018
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other		Eliminations		Total Consolidated
	(In thousands)
Revenues:
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 ⁽¹⁾	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.

Selected Quarterly Financial Information

12 Months Ended

Dec. 31, 2019

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)
2018
Revenues	$	205,132	$	203,303	$	220,058		$	214,788
Gross income (loss) ⁽¹⁾	$	38,833	$	40,915	$	49,216		$	(108,068)
Net income (loss) attributable to Unit Corporation	$	7,865	$	5,788	$	18,899		$	(77,840)	⁽²⁾
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)
2019
Revenues ⁽³⁾	$	189,691	$	165,146	$	155,439		$	164,358
Gross income (loss) ⁽¹⁾	$	24,095	$	813	$	(242,308)		$	(393,983)
Net loss attributable to Unit Corporation	$	(3,504)	$	(8,509)	$	(206,886)	⁽⁴⁾	$	(334,980)	⁽⁵⁾
Net loss attributable to Unit Corporation per common share:
Basic	$	(0.07)	$	(0.16)	$	(3.91)		$	(6.33)
Diluted	$	(0.07)	$	(0.16)	$	(3.91)		$	(6.33)

_________________________

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.In the fourth quarter of 2018, we recorded an impairment for contract drilling equipment that included a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

3.In 2019, revenues dropped significantly each quarter due to lower commodity prices, production, and drilling rig utilization.

4.During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax).

5.During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax).

Supplemental Condensed Consolidated Financial Information

12 Months Ended

Dec. 31, 2019

Condensed Financial Information 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 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 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, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	503	$	68	$	—	$	—	$	571
Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216)	2,645		64,805		24,653		(9,447)		82,656
Materials and supplies	—		449		—		—		449
Current derivative asset	633		—		—		—		633
Current income tax receivable	1,756		—		—		—		1,756
Assets held for sale	—		5,908		—		—		5,908
Prepaid expenses and other	2,019		3,373		7,686		—		13,078
Total current assets	7,556		74,603		32,339		(9,447)		105,051
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	—		6,341,582		—		—		6,341,582
Unproved properties not being amortized	—		252,874		—		—		252,874
Drilling equipment	—		1,295,713		—		—		1,295,713
Gas gathering and processing equipment	—		—		824,699		—		824,699
Saltwater disposal systems	—		69,692		—		—		69,692
Corporate land and building	—		59,080		—		—		59,080
Transportation equipment	9,712		16,621		3,390		—		29,723
Other	28,927		29,065		—		—		57,992
	38,639		8,064,627		828,089		—		8,931,355
Less accumulated depreciation, depletion, amortization, and impairment	33,794		6,537,731		407,144		—		6,978,669
Net property and equipment	4,845		1,526,896		420,945		—		1,952,686
Intercompany receivable	1,048,785		—		—		(1,048,785)		—

Investments	865,252		—		—		(865,252)		—

Right of use asset	46		1,733		3,948		(54)		5,673
Other assets	8,107		9,094		9,441		—		26,642
Total assets	$	1,934,591	$	1,612,326	$	466,673	$	(1,923,538)	$	2,090,052


	December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,259	$	61,002	$	18,511	$	(7,291)	$	84,481
Accrued liabilities	28,003		14,024		6,691		(2,156)		46,562
Current operating lease liability	20		1,009		2,407		(6)		3,430
Current portion of long-term debt	108,200		—		—		—		108,200
Current portion of other long-term liabilities	3,003		7,313		7,060		—		17,376
Total current liabilities	151,485		83,348		34,669		(9,453)		260,049
Intercompany debt	—		1,047,599		1,186		(1,048,785)		—
Long-term debt less debt issuance costs	646,716		—		16,500		—		663,216
Non-current derivative liabilities	27		—		—		—		27
Operating lease liability	25		690		1,404		(48)		2,071
Other long-term liabilities	12,553		74,662		8,126		—		95,341
Deferred income taxes	68,150		(54,437)		—		—		13,713









Total shareholders' equity	1,055,635		460,464		404,788		(865,252)		1,055,635

Total liabilities and shareholders’ equity	$	1,934,591	$	1,612,326	$	466,673	$	(1,923,538)	$	2,090,052


	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)	2,328		94,737		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	1,993		3,560		1,049		—		6,602
Total current assets	17,837		123,300		43,566		(14,344)		170,359
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	950,871		—		—		(950,871)		—
Goodwill	—		62,808		—		—		62,808
Investments	1,362,526		—		—		(1,362,526)		—
Other assets	8,225		6,793		17,552		—		32,570
Total assets	$	2,349,812	$	2,209,131	$	466,851	$	(2,327,741)	$	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	$	9,466	$	122,608	$	32,215	$	(12,603)	$	151,686
Accrued liabilities	27,505		16,539		5,620		(1,741)		47,923

Current portion of other long-term liabilities	812		6,563		6,875		—		14,250
Total current liabilities	37,783		145,710		44,710		(14,344)		213,859
Intercompany debt	—		948,790		2,081		(950,871)		—

Long-term debt less debt issuance costs	644,475		—		—		—		644,475
Non-current derivative liabilities	293		—		—		—		293
Other long-term liabilities	12,834		73,713		14,687		—		101,234
Deferred income taxes	60,983		83,765		—		—		144,748









Total shareholders' equity	1,593,444		957,153		405,373		(1,362,526)		1,593,444
Total liabilities and shareholders’ equity	$	2,349,812	$	2,209,131	$	466,851	$	(2,327,741)	$	2,698,053

Condensed Consolidating Statements of Operations


	Year Ended December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	494,180	$	227,939	$	(47,485)	$	674,634
Expenses:
Operating costs	—		256,024		176,189		(47,485)		384,728
Depreciation, depletion, and amortization	7,707		220,203		47,663		—		275,573
Impairments	—		622,676		3,040		—		625,716
General and administrative	—		38,246		—		—		38,246
(Gain) loss on disposition of assets	(11)		3,673		(160)		—		3,502
Total operating expenses	7,696		1,140,822		226,732		(47,485)		1,327,765
Income (loss) from operations	(7,696)		(646,642)		1,207		—		(653,131)
Interest, net	(35,466)		—		(1,546)		—		(37,012)
Gain on derivatives	4,225		—		—		—		4,225
Other	786		(1,086)		64		—		(236)
Loss before income taxes	(38,151)		(647,728)		(275)		—		(686,154)
Income tax expense (benefit)	7,238		(139,564)		—		—		(132,326)
Equity in net earnings from investment in subsidiaries, net of taxes	(508,439)		—		—		508,439		—
Net loss	(553,828)		(508,164)		(275)		508,439		(553,828)
Less: net income attributable to non-controlling interest	51		—		51		(51)		51
Net loss attributable to Unit Corporation	$	(553,879)	$	(508,164)	$	(326)	$	508,490	$	(553,879)


	Year Ended December 31, 2018
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	619,551	$	312,417	$	(88,687)	$	843,281
Expenses:
Operating costs	—		268,255		251,328		(88,687)		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		642,750		298,676		(88,687)		860,388
Income (loss) from operations	(7,649)		(23,199)		13,741		—		(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)		(23,199)		12,527		—		(53,763)
Income tax expense (benefit)	(11,962)		(4,064)		2,030		—		(13,996)
Equity in net earnings from investment in subsidiaries, net of taxes	(8,638)		—		—		(8,638)		—
Net income (loss)	(39,767)		(19,135)		10,497		(8,638)		(39,767)
Less: net income attributable to non-controlling interest	5,521		—		5,521		(5,521)		5,521
Net income (loss) attributable to Unit Corporation	$	(45,288)	$	(19,135)	$	4,976	$	(3,117)	$	(45,288)


	Year Ended December 31, 2017
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	534,084	$	277,049	$	(71,493)	$	739,640
Expenses:
Operating costs	—		258,132		220,613		(69,873)		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		446,401		272,734		(69,873)		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

Condensed Consolidating Statements of Comprehensive Income (Loss)


	Year Ended December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net loss	$	(553,828)	$	(508,164)	$	(275)	$	508,439	$	(553,828)
Other comprehensive loss, net of taxes:
Reclassification adjustment for write-down of securities, net of tax of ($47)	—		481		—		—		481
Comprehensive loss	(553,828)		(507,683)		(275)		508,439		(553,347)
Less: Comprehensive income attributable to non-controlling interests	51		—		51		(51)		51
Comprehensive loss attributable to Unit Corporation	$	(553,879)	$	(507,683)	$	(326)	$	508,490	$	(553,398)


	Year Ended December 31, 2018
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	(39,767)	$	(19,135)	$	10,497	$	(8,638)	$	(39,767)
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax of ($181)	—		(557)		—		—		(557)
Comprehensive income	(39,767)		(19,692)		10,497		(8,638)		(40,324)
Less: Comprehensive income attributable to non-controlling interests	5,521		—		5,521		(5,521)		5,521
Comprehensive income (loss) attributable to Unit Corporation	$	(45,288)	$	(19,692)	$	4,976	$	(3,117)	$	(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 income on securities, net of tax of $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

Condensed Consolidating Statements of Cash Flows


	Year Ended December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(9,681)	$	217,883	$	48,856	$	12,338	$	269,396
INVESTING ACTIVITIES:
Capital expenditures	65		(355,258)		(51,472)		—		(406,665)
Producing property and other oil and natural gas acquisitions	—		(3,653)		—		—		(3,653)
Other acquisitions	—		—		(16,109)		—		(16,109)
Proceeds from disposition of property and equipment	11		31,153		700		—		31,864
Net cash provided by (used in) investing activities	76		(327,758)		(66,881)		—		(394,563)
FINANCING ACTIVITIES:
Borrowings under credit agreements	400,600		—		92,900		—		493,500
Payments under credit agreements	(292,400)		—		(76,400)		—		(368,800)
Intercompany borrowings (advances), net	(97,455)		109,735		58		(12,338)		—
Payments on finance leases	—		—		(4,001)		—		(4,001)
Employee taxes paid by withholding shares	(4,158)		—		—		—		(4,158)
Distributions to non-controlling interest	919		—		(1,837)		—		(918)



Bank overdrafts	2,199		—		1,464		—		3,663
Net cash provided by financing activities	9,705		109,735		12,184		(12,338)		119,286
Net increase in cash and cash equivalents	100		(140)		(5,841)		—		(5,881)
Cash and cash equivalents, beginning of period	403		208		5,841		—		6,452
Cash and cash equivalents, end of period	$	503	$	68	$	—	$	—	$	571


	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	$	(310,120)	$	324,696	$	12,257	$	325,914	$	352,747
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 used in investing activities	266		(405,183)		(45,425)		—		(450,342)
FINANCING ACTIVITIES:
Borrowings under credit agreement	97,100		—		2,000		—		99,100
Payments under credit agreement	(275,100)		—		(2,000)		—		(277,100)
Intercompany borrowings (advances), net	202,558		80,504		(154,982)		(128,080)		—
Payments on finance leases	—		—		(3,843)		—		(3,843)
Proceeds from investments in non-controlling interest	300,000		—		197,042		(197,042)		300,000
Employee taxes paid by withholding shares	(4,988)		—		—		—		(4,988)
Transaction costs associated with sale of non-controlling interest	(2,503)		—		—		—		(2,503)

Bank overdrafts	(7,320)		—		—		—		(7,320)
Net cash provided by (used in) financing activities	309,747		80,504		39,009		(325,914)		103,346
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 operating activities	$	3,458	$	223,437	$	43,193	$	—	$	270,088
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 provided by (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	(27,615)		48,484		(20,869)		—		—
Payments on finance leases	—		—		(3,694)		—		(3,694)
Proceeds from common stock issued, net of issue costs	18,623		—		—		—		18,623
Employee taxes paid by withholding shares	(4,132)		—		—		—		(4,132)

Bank overdrafts	(4,911)		—		—		—		(4,911)
Net cash used in financing activities	(835)		48,484		(24,563)		—		23,086
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

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events [Text Block]	SUBSEQUENT EVENTSOn March 11, 2020, we entered into a Standstill and Amendment Agreement (Standstill Agreement) with the lenders and administrative agent party to the Unit credit agreement. The Standstill Agreement, among other things, provides that during the standstill period (as defined below), the administrative agent and lenders under the Unit credit agreement agree to temporarily standstill from making any final determination in connection with the pending scheduled redetermination of the borrowing base that was, under the Unit credit agreement, otherwise scheduled to be made on or about April 1, 2020, and from otherwise exercising certain of their respective rights and remedies under the Unit credit agreement. The standstill period will begin after the effective date of the Standstill Agreement and will continue until the earlier of: (i) the receipt by any credit party from the administrative agent of notice of the occurrence of any termination event and (ii) 3:00 p.m. central time on April 15, 2020. “Termination event” is defined under the Standstill Agreement to include the occurrence of any one or more of the following: (i) any representation or warranty made or deemed to have been made by any credit party under the Standstill Agreement being false, misleading or erroneous in any material respect when made or deemed to have been made, (ii) any credit party failing to perform, observe or comply with any covenant, agreement or term contained in the Standstill Agreement in any material respect or (iii) any default which is not cured within five (5) business days or event of default occurring under the Unit credit agreement. Under the Standstill Agreement, we are prevented from withdrawing more than an additional $15.0 million, in the aggregate, net of repayments, and we have agreed to make repayments using any excess cash, among certain other conditions.

Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2019

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:


	2019		2018		2017
	(In thousands)
Capitalized costs:
Proved properties	$	6,341,582	$	6,018,568	$	5,712,813
Unproved properties	252,874		330,216		296,764
	6,594,456		6,348,784		6,009,577
Accumulated depreciation, depletion, amortization, and impairment	(5,846,177)		(5,124,257)		(4,996,696)
Net capitalized costs	$	748,279	$	1,224,527	$	1,012,881
Cost incurred:
Unproved properties acquired	$	34,668	$	57,430	$	47,029
Proved properties acquired	3,653		15,158		47,638
Exploration	16,480		15,907		14,811
Development	211,443		280,692		160,941
Asset retirement obligation	76		(7,629)		(3,613)
Total costs incurred	$	266,320	$	361,558	$	266,806

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2019, by the year in which such costs were incurred:


	2019		2018		2017		2016 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	22,621	$	54,780	$	47,646	$	127,827	252,874

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:


	2019		2018		2017
	(In thousands)
Revenues	$	314,925	$	411,601	$	347,285
Production costs	(116,051)		(113,810)		(107,332)
Depreciation, depletion, amortization, and impairment	(727,529)		(132,923)		(96,392)
	(528,655)		164,868		143,561
Income tax (expense) benefit	101,952		(42,915)		(56,376)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	(426,703)	$	121,953	$	87,185

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)
2017
Proved developed and undeveloped reserves:
Beginning of year	15,696	34,482	405,579	117,774
Revision of previous estimates	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 ⁽¹⁾	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
2019
Proved developed and undeveloped reserves:
Beginning of year	22,558	47,796	535,963	159,681
Revision of previous estimates ⁽²⁾	(8,263)	(20,961)	(234,852)	(68,366)
Extensions and discoveries ⁽²⁾	703	845	8,798	3,015
Infill reserves in existing proved fields	271	434	4,806	1,506
Purchases of minerals in place	183	101	1,316	503
Production	(3,208)	(4,773)	(53,064)	(16,825)
Sales	(48)	(412)	(42,780)	(7,590)
End of year	12,196	23,030	220,187	71,924
Proved developed reserves:
Beginning of year	15,192	33,515	377,216	111,576
End of year	12,196	23,030	220,187	71,924
Proved undeveloped reserves:
Beginning of year	7,366	14,281	158,747	48,105
End of year	—	—	—	—

_________________________

1.Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

2.Revisions of previous estimates and extensions and discoveries decreased primarily due to the removal of proved undeveloped reserves due to uncertainty regarding our ability to finance the development of our proved undeveloped reserves over a five-year period and from lower commodity 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:


	2019		2018		2017
	(In thousands)
Future cash flows	$	1,386,777	$	3,980,369	$	3,347,396
Future production costs	(698,357)		(1,479,744)		(1,308,244)
Future development costs	—		(442,984)		(369,560)
Future income tax expenses	(321)		(307,916)		(234,152)
Future net cash flows	688,099		1,749,725		1,435,440
10% annual discount for estimated timing of cash flows	(226,390)		(766,047)		(628,270)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	461,709	$	983,678	$	807,170

The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:


	2019		2018		2017
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(200,233)	$	(297,791)	$	(239,953)
Net changes in prices and production costs	(508,066)		120,062		236,126
Revisions in quantity estimates and changes in production timing	(338,994)		(33,282)		87,239
Extensions, discoveries, and improved recovery, less related costs	53,123		234,172		102,965
Changes in estimated future development costs	311,190		19,535		(5,194)
Previously estimated cost incurred during the period	64,362		63,557		36,044
Purchases of minerals in place	6,416		23,416		51,686
Sales of minerals in place	(25,813)		(5,004)		(1,447)
Accretion of discount	110,571		89,753		57,517
Net change in income taxes	121,708		(31,674)		(33,389)
Changes in timing and other	(116,233)		(6,236)		(2,634)
Net change	(521,969)		176,508		288,960
Beginning of year	983,678		807,170		518,210
End of year	$	461,709	$	983,678	$	807,170

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, 2019, future cash flows were computed by applying the unescalated 12-month average prices of $55.69 per barrel for oil, $23.19 per barrel for NGLs, and $2.58 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, 2019

SEC Schedule, 12-09, 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, 2019	$	2,531	$	527	$	(726)	$	2,332
Year ended December 31, 2018	$	2,450	$	81	$	—	$	2,531
Year ended December 31, 2017	$	3,773	$	348	$	(1,671)	$	2,450

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2019

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 18 – 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, 2019, all of our contracts were daywork contracts of which 14 were multi-well and had durations which ranged from two months to three years, 10 of which expire in 2020 and four expiring in 2021 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 Bank 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. Bank 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, 2019 and 2018, bank overdrafts were $8.7 million and $5.1 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:


	2019		2018		2017
Oil and Natural Gas:
CVR Refining, LP	14	%	14	%	2	%
Valero Energy Corporation	9	%	10	%	9	%
Energy Transfer Partners (formerly Sunoco Logistics Partners)	5	%	3	%	10	%
Drilling:
EOG Resources, Inc.	12	%	5	%	—	%
QEP Resources, Inc.	12	%	16	%	26	%
Slawson Exploration Company, Inc	11	%	10	%	6	%
Mid-Stream:
ONEOK, Inc.	33	%	45	%	36	%
Range Resources Corporation	13	%	7	%	9	%
Centerpoint Energy Service, Inc.	10	%	5	%	4	%

We had a concentration of cash of $1.7 million and $11.0 million at December 31, 2019 and 2018, respectively with one bank.


	December 31, 2019
	(In millions)
Bank of Montreal	$	0.4
Bank of America Merrill Lynch	0.2
Total net assets	$	0.6

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

Capitalized Interest

During 2019, 2018, and 2017, interest of approximately $16.2 million, $16.5 million, and $15.9 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill

Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For 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. Due to the triggering event within the contract drilling reporting unit, we performed an interim goodwill impairment test as of September 30, 2019. Based on the projected discounted cash flows, we recognized a goodwill impairment charge of $62.8 million, pre-tax ($59.8 million, net of tax) which represented the total goodwill previously reported on our consolidated balance sheets. No goodwill impairment was recorded for the years ended December 31, 2018, or 2017. There were no additions to goodwill in 2019, 2018, or 2017.

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 $16.5 million, $15.9 million, and $14.8 million were capitalized in 2019, 2018, and 2017, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $9.66, $7.50, and $6.00 per Boe in 2019, 2018, and 2017, 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 $252.9 million are excluded from the DD&A calculation.

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 was a general partner in 13 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees owned the interests in most of these partnerships. We shared in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimbursed us for certain administrative costs incurred on behalf of the partnerships. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.

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. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the 2017 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, 2019 balancing position to be approximately 3.4 Bcf on under-produced properties and approximately 3.5 Bcf on over-produced properties. We have recorded a receivable of $3.6 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 $3.8 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

Adopted Standards

The additional disclosures required by ASC 842 have been included in Note 16 – Leases.

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

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:


	2019		2018		2017
Oil and Natural Gas:
CVR Refining, LP	14	%	14	%	2	%
Valero Energy Corporation	9	%	10	%	9	%
Energy Transfer Partners (formerly Sunoco Logistics Partners)	5	%	3	%	10	%
Drilling:
EOG Resources, Inc.	12	%	5	%	—	%
QEP Resources, Inc.	12	%	16	%	26	%
Slawson Exploration Company, Inc	11	%	10	%	6	%
Mid-Stream:
ONEOK, Inc.	33	%	45	%	36	%
Range Resources Corporation	13	%	7	%	9	%
Centerpoint Energy Service, Inc.	10	%	5	%	4	%

Schedule of Fair Values of the Net Assets (Liabilities) [Table Text Block]

At December 31, 2019, 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:


	December 31, 2019
	(In millions)
Bank of Montreal	$	0.4
Bank of America Merrill Lynch	0.2
Total net assets	$	0.6

Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2019

Adoption of ASC606 [Line Items]

Revenue, Remaining Performance Obligation


Contract	Remaining Term of Contract	2020		2021		2022		2023 and beyond	Total Remaining Impact to Revenue

Demand fee contracts	3-9 years	$	(3,775)	$	(3,501)	$	1,380	36	$	(5,860)

Contract with Customer, Asset and Liability

Revenue recognized for these demand fees was $2.6 million and $5.0 million in 2019 and 2018, respectively.


	December 31, 2019		December 31, 2018		Change
	(In thousands)
Contract assets	$	12,921	$	13,164	$	(243)
Contract liabilities	7,061		9,881		(2,820)
Contract assets (liabilities), net	$	5,860	$	3,283	$	2,577

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2019

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.


Purchase Price
Total consideration given	$	29,633

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, 2019

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, 2017:
Basic earnings attributable to Unit Corporation per common share	$	117,848	51,113	$	2.31
Effect of dilutive stock options and restricted stock	—		635	(0.03)
Diluted earnings 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 stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(45,288)	51,981	$	(0.87)
For the year ended December 31, 2019:
Basic loss attributable to Unit Corporation per common share	(553,879)		52,849	$	(10.48)
Effect of dilutive stock options and restricted stock	—		—	—
Diluted loss attributable to Unit Corporation per common share	$	(553,879)	52,849	$	(10.48)

Schedule of Antidilutive Securities Excluded from Computation of Earnings (Loss) Per Share [Table Text Block]


	2019		2018		2017
Stock options	42,000		66,500		87,500
Average exercise price	$	48.56	$	44.42	$	51.34

Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Accrued Liabilities [Abstract]

Accrued Liabilities [Table Text Block]

Accrued liabilities consisted of the following as of December 31:


	2019		2018
	(In thousands)
Employee costs	$	17,832	$	20,315
Lease operating expenses	9,200		12,756
Interest payable	6,562		6,635
Third-party credits	3,691		2,129
Taxes	3,450		1,378
Other	5,827		4,710
Total accrued liabilities	$	46,562	$	47,923

Long-Term Debt And Other Long-Term Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

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:


	2019		2018
	(In thousands)
Current portion of long-term debt:
Unit credit agreement with an average interest rate of 4.0% at December 31, 2019	$	108,200	$	—
Long-term debt:
Superior credit agreement with an average interest rate of 3.9% at December 31, 2019	16,500		—
6.625% senior subordinated notes due 2021	650,000		650,000
Total principal amount	$	666,500	$	650,000
Less: unamortized discount	(971)		(1,623)
Less: debt issuance costs, net	(2,313)		(3,902)
Total long-term debt	$	663,216	$	644,475

Other Long Term Liabilities [Table Text Block]

Other long-term liabilities consisted of the following as of December 31:


	2019		2018
	(In thousands)
ARO liability	$	66,627	$	64,208
Workers’ compensation	11,510		12,738
Finance lease obligations	7,379		11,380
Contract liability	7,061		9,881
Separation benefit plans	10,122		8,814
Deferred compensation plan	6,180		5,132
Gas balancing liability	3,838		3,331
	112,717		115,484
Less current portion	17,376		14,250
Total other long-term liabilities	$	95,341	$	101,234

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

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-Subparagraph (SX 210.4-08.(e),(f))
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+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Schedule Of Asset Retirement Obligations [Table Text Block]

The following table shows certain information about our AROs for the periods indicated:


	2019		2018
	(In thousands)
ARO liability, January 1:	$	64,208	$	69,444
Accretion of discount	2,343		2,393
Liability incurred	4,373		2,632
Liability settled	(3,261)		(4,493)
Liability sold	(2,953)		(281)
Revision of estimates ⁽¹⁾	1,917		(5,487)
ARO liability, December 31:	66,627		64,208
Less current portion	2,920		1,437
Total long-term ARO liability	$	63,707	$	62,771

_________________________

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

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:


	2019		2018		2017
	(In thousands)
Income tax expense (benefit) computed by applying the statutory rate	$	(144,092)	$	(11,290)	$	21,059
State income tax expense (benefit), net of federal benefit	(21,733)		(1,882)		1,655
Deferred tax liability revaluation ⁽¹⁾	—		—		(81,307)
Restricted stock shortfall	347		424		1,867
Non-controlling interest in Superior	(11)		(1,138)		—
Goodwill impairment	12,346		—		—
Valuation allowance	19,654		—		—
Statutory depletion and other	1,163		(110)		(952)
Income tax benefit	$	(132,326)	$	(13,996)	$	(57,678)

__________________________

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:


	2019		2018		2017
	(In thousands)
Current taxes:
Federal	$	(918)	$	(1,835)	$	—
State	(363)		(1,296)		5
	(1,281)		(3,131)		5
Deferred taxes:
Federal	(108,440)		(8,741)		(62,788)
State	(22,605)		(2,124)		5,105
	(131,045)		(10,865)		(57,683)
Total provision	$	(132,326)	$	(13,996)	$	(57,678)

Schedule Of Deferred Tax Assets And Liabilities [Table Text Block]

Deferred tax assets and liabilities are comprised of the following at December 31:


	2019		2018
	(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals	$	31,822	$	27,953
Net operating loss carryforward	246,927		152,112
Alternative minimum tax and research and development tax credit carryforward	2,656		3,574
	281,405		183,639
Deferred tax liability:
Depreciation, depletion, amortization, and impairment	(226,034)		(291,542)
Investment in Superior	(49,430)		(36,845)
Net deferred tax asset (liability)	5,941		(144,748)
Valuation allowance	(19,654)		—
Current deferred tax asset	—		—
Non-current—deferred tax liability	$	(13,713)	$	(144,748)

Transactions With Related Parties (Tables)

12 Months Ended

Dec. 31, 2019

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 was a general partner are as follows:


	2019		2018		2017
	(In thousands)
Well supervision and other fees	$	1	$	158	$	172
General and administrative expense reimbursement	—		—		—

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule Of Restricted Stock Awards [Table Text Block]

For restricted stock awards, we had:


	2019		2018		2017
	(In millions)
Recognized stock compensation expense	$	12.8	$	17.8	$	13.3
Capitalized stock compensation cost for our oil and natural gas properties	2.4		2.1		1.8
Tax benefit on stock based compensation	3.1		4.4		5.0

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, 2017	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
Granted	927,173	500,256	1,427,429	16.09
Vested	(570,107)	(233,835)	(803,942)	15.56
Forfeited	(98,301)	(33,172)	(131,473)	19.36
Nonvested at December 31, 2019	1,527,648	841,374	2,369,022	$	18.95


Non-Employee Directors	Number of Shares	Weighted Average Price
Nonvested at January 1, 2017	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
Granted	72,784	12.09
Vested	(61,141)	15.49
Forfeited	—	—
Nonvested at December 31, 2019	118,688	$	14.83

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, 2017	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
Granted	—	—
Exercised	—	—
Forfeited	(24,500)	37.31
Outstanding at December 31, 2019	42,000	$	48.56

Shares Authorized Under Nonemployee Director Option Plans By Exercise Price Range [Table Text Block]


	Outstanding and Exercisable Options at December 31, 2019
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$41.21	17,500	0.3 years	$	41.21
$53.81	24,500	1.3 years	$	53.81

Derivatives (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Non-designated Hedges Outstanding [Table Text Block]

At December 31, 2019, the following non-designated hedges were outstanding:

Term

Commodity

Contracted Volume

Weighted Average

Fixed Price for Swaps

Contracted Market

Jan'20 - Dec'20

Natural gas - basis swap

30,000 MMBtu/day

$(0.275)

NGPL TEXOK

Jan'20 - Dec'20

Natural gas - basis swap

20,000 MMBtu/day

$(0.455)

PEPL

Jan'21 - Dec'21

Natural gas - basis swap

30,000 MMBtu/day

$(0.215)

NGPL TEXOK

Jan'20 - Dec'20

Natural gas - three-way collar

30,000 MMBtu/day

$2.50 - $2.20 - $2.80

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	2019		2018
		(In thousands)
Commodity derivatives:
Current	Current derivative assets	$	633	$	12,870
Long-term	Non-current derivative assets	—		—
Total derivative assets		$	633	$	12,870


		Derivative Liabilities Fair Value
	Balance Sheet Location	2019		2018
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	—	$	—
Long-term	Non-current derivative liabilities	27		293
Total derivative liabilities		$	27	$	293

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
				2019		2018
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	4,225	$	(3,184)
Total		$	4,225	$	(3,184)

_________________________

1.Amounts settled during the periods are a gain of $16,196 and a loss of $22,803, respectively.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Recurring Fair Value Measurements [Table Text Block]

The following tables set forth our recurring fair value measurements:


	December 31, 2019
	Level 2		Level 3		Effect of Netting		Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	177	$	1,204	$	(748)	$	633
Liabilities	(775)		—		748		(27)
	$	(598)	$	1,204	$	—	$	606


	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

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, 2019		December 31, 2018
	(In thousands)
Beginning of period	$	10,630	$	(206)
Total gains or losses:
Included in earnings	(1,494)		4,159
Settlements	(7,932)		6,677
End of period	$	1,204	$	10,630
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	(9,426)	$	10,836

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, 2019:

Commodity ⁽¹⁾

Fair Value

Valuation Technique

Unobservable Input

Range

(In thousands)

Natural gas three-way collar

1,204

Discounted cash flow

Forward commodity price curve

$0.00 - $0.39

_________________________

Leases (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental cash flow information related to leases

The following table shows supplemental cash flow information related to leases for the year ended December 31, 2019:


	Amount
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	4,034
Financing cash flows for finance leases	4,001
Lease liabilities recognized in exchange for new operating lease right of use assets	5

Schedule of lease assets and liabilities

The following table shows information about our lease assets and liabilities included in our Consolidated Balance Sheet as of December 31, 2019:

Classification on the Consolidated Balance Sheet

December 31,
2019

(In thousands)

Assets

Operating right of use assets

Right of use assets

5,673

Finance right of use assets

Property, plant, and equipment, net

17,396

Total right of use assets

23,069

Liabilities

Current liabilities:

Operating lease liabilities

Current operating lease liabilities

3,430

Finance lease liabilities

Current portion of other long-term liabilities

4,164

Non-current liabilities:

Operating lease liabilities

2,071

Finance lease liabilities

Other long-term liabilities

3,215

Total lease liabilities

12,880

Schedule of lease costs

The following table shows certain information related to the lease costs for our finance and operating leases for the year indicated:


	2019

Components of total lease cost:
Amortization of finance leased assets	$	4,001
Interest on finance lease liabilities	382
Operating lease cost	4,034
Short-term lease cost ⁽¹⁾	38,868
Variable lease cost	351
Total lease cost	$	47,636

_______________________

1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $25.1 million.

Schedule of weighted average discount rate for leases

The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:


	Weighted Average Remaining Lease Term	Weighted Average Discount Rate ⁽¹⁾
	(In years)
Operating leases	1.9	6.13%
Finance leases	1.7	4.00%

_______________________

1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

Operating leases

The following table sets forth the maturity of our operating lease liabilities as of December 31, 2019:


	Amount
	(In thousands)
Ending January 1,
2021	$	3,670
2022	1,614
2023	419
2024	73
2025	12
2026 and beyond	75
Total future payments	5,863
Less: Interest	362
Present value of future minimum operating lease payments	5,501
Less: Current portion	3,430
Total long-term operating lease payments	$	2,071

Finance leases

Future payments required under the finance leases at December 31, 2019 are as follows:


	Amount
Ending January 1,	(In thousands)
2021	$	6,194
2022	3,774
Total future payments	9,968
Less payments related to:
Maintenance	2,336
Interest	253
Present value of future minimum payments	7,379
Less: Current portion	4,164
Total long-term finance lease payments	$	3,215

Variable Interest Entity Arrangements (Tables)

12 Months Ended

Dec. 31, 2019

Variable Interest Entity Arrangements [Abstract]

Schedule of Assets and Liabilities

The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows:


	December 31, 2019		December 31, 2018
	(In thousands)
Current assets:
Cash and cash equivalents	$	—	$	5,841
Accounts receivable	21,073		33,207
Prepaid expenses and other	7,686		1,049
Total current assets	28,759		40,097
Property and equipment:
Gas gathering and processing equipment	824,699		767,388
Transportation equipment	3,390		3,086
	828,089		770,474
Less accumulated depreciation, depletion, amortization, and impairment	407,144		364,740
Net property and equipment	420,945		405,734
Right of use assets	3,948		—
Other assets	9,442		17,551
Total assets	$	463,094	$	463,382

Current liabilities:
Accounts payable	$	18,511	$	32,214
Accrued liabilities	4,198		3,688
Current operating lease liability	2,407		—
Current portion of other long-term liabilities	7,060		6,875
Total current liabilities	32,176		42,777
Long-term debt less debt issuance costs	16,500		—
Operating lease liability	1,404		—
Other long-term liabilities	8,126		14,687
Total liabilities	$	58,206	$	57,464

Revenue From Different Segments [Table Text Block]

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.

+ References + Details

Industry Segment Information (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

The following table provides certain information about the operations of each of our segments:


	Year Ended December 31, 2019
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other		Eliminations		Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	325,797	$	—	$	—	$	—	$	—	$	325,797
Contract drilling	—		184,192		—		—		(15,809)		168,383
Gas gathering and processing	—		—		227,939		—		(47,485)		180,454
Total revenues	325,797		184,192		227,939		—		(63,294)		674,634
Expenses:
Operating costs:
Oil and natural gas	140,026		—		—		—		(4,902)		135,124
Contract drilling	—		130,188		—		—		(14,190)		115,998
Gas gathering and processing	—		—		176,189		—		(42,583)		133,606
Total operating costs	140,026		130,188		176,189		—		(61,675)		384,728
Depreciation, depletion, and amortization	168,651		51,552		47,663		7,707		—		275,573
Impairments ⁽²⁾	559,867		62,809		3,040		—		—		625,716
Total expenses	868,544		244,549		226,892		7,707		(61,675)		1,286,017
General and administrative	—		—		—		38,246		—		38,246
(Gain) loss on disposition of assets	(199)		3,872		(160)		(11)		—		3,502
Income (loss) from operations	(542,548)		(64,229)		1,207		(45,942)		(1,619)		(653,131)
Gain on derivatives	—		—		—		4,225		—		4,225
Interest expense, net	—		—		(1,546)		(35,466)		—		(37,012)
Other	(481)		(605)		827		23		—		(236)
Income (loss) before income taxes	$	(543,029)	$	(64,834)	$	488	$	(77,160)	$	(1,619)	$	(686,154)

Identifiable assets:
Oil and natural gas ⁽³⁾	$	851,662	$	—	$	—	$	—	$	(4,264)	$	847,398
Contract drilling	—		708,510		—		—		(42)		708,468
Gas gathering and processing	—		—		463,699		—		(4,255)		459,444
Total identifiable assets ⁽⁴⁾	851,662		708,510		463,699		—		(8,561)		2,015,310
Corporate land and building	—		—		—		54,155		—		54,155
Other corporate assets ⁽⁵⁾	—		—		—		23,092		(2,505)		20,587
Total assets	$	851,662	$	708,510	$	463,699	$	77,247	$	(11,066)	$	2,090,052

Capital expenditures:	$	268,622	$	40,636	$	64,438	$	673	$	—	$	374,369

_______________________

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.

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, 2018
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other		Eliminations		Total Consolidated
	(In thousands)
Revenues:
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 ⁽¹⁾	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.

Selected Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2019

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)
2018
Revenues	$	205,132	$	203,303	$	220,058		$	214,788
Gross income (loss) ⁽¹⁾	$	38,833	$	40,915	$	49,216		$	(108,068)
Net income (loss) attributable to Unit Corporation	$	7,865	$	5,788	$	18,899		$	(77,840)	⁽²⁾
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)
2019
Revenues ⁽³⁾	$	189,691	$	165,146	$	155,439		$	164,358
Gross income (loss) ⁽¹⁾	$	24,095	$	813	$	(242,308)		$	(393,983)
Net loss attributable to Unit Corporation	$	(3,504)	$	(8,509)	$	(206,886)	⁽⁴⁾	$	(334,980)	⁽⁵⁾
Net loss attributable to Unit Corporation per common share:
Basic	$	(0.07)	$	(0.16)	$	(3.91)		$	(6.33)
Diluted	$	(0.07)	$	(0.16)	$	(3.91)		$	(6.33)

_________________________

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.In the fourth quarter of 2018, we recorded an impairment for contract drilling equipment that included a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

3.In 2019, revenues dropped significantly each quarter due to lower commodity prices, production, and drilling rig utilization.

5.During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax).

Supplemental Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheets


	December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	503	$	68	$	—	$	—	$	571
Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216)	2,645		64,805		24,653		(9,447)		82,656
Materials and supplies	—		449		—		—		449
Current derivative asset	633		—		—		—		633
Current income tax receivable	1,756		—		—		—		1,756
Assets held for sale	—		5,908		—		—		5,908
Prepaid expenses and other	2,019		3,373		7,686		—		13,078
Total current assets	7,556		74,603		32,339		(9,447)		105,051
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	—		6,341,582		—		—		6,341,582
Unproved properties not being amortized	—		252,874		—		—		252,874
Drilling equipment	—		1,295,713		—		—		1,295,713
Gas gathering and processing equipment	—		—		824,699		—		824,699
Saltwater disposal systems	—		69,692		—		—		69,692
Corporate land and building	—		59,080		—		—		59,080
Transportation equipment	9,712		16,621		3,390		—		29,723
Other	28,927		29,065		—		—		57,992
	38,639		8,064,627		828,089		—		8,931,355
Less accumulated depreciation, depletion, amortization, and impairment	33,794		6,537,731		407,144		—		6,978,669
Net property and equipment	4,845		1,526,896		420,945		—		1,952,686
Intercompany receivable	1,048,785		—		—		(1,048,785)		—

Investments	865,252		—		—		(865,252)		—

Right of use asset	46		1,733		3,948		(54)		5,673
Other assets	8,107		9,094		9,441		—		26,642
Total assets	$	1,934,591	$	1,612,326	$	466,673	$	(1,923,538)	$	2,090,052


	December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,259	$	61,002	$	18,511	$	(7,291)	$	84,481
Accrued liabilities	28,003		14,024		6,691		(2,156)		46,562
Current operating lease liability	20		1,009		2,407		(6)		3,430
Current portion of long-term debt	108,200		—		—		—		108,200
Current portion of other long-term liabilities	3,003		7,313		7,060		—		17,376
Total current liabilities	151,485		83,348		34,669		(9,453)		260,049
Intercompany debt	—		1,047,599		1,186		(1,048,785)		—
Long-term debt less debt issuance costs	646,716		—		16,500		—		663,216
Non-current derivative liabilities	27		—		—		—		27
Operating lease liability	25		690		1,404		(48)		2,071
Other long-term liabilities	12,553		74,662		8,126		—		95,341
Deferred income taxes	68,150		(54,437)		—		—		13,713









Total shareholders' equity	1,055,635		460,464		404,788		(865,252)		1,055,635

Total liabilities and shareholders’ equity	$	1,934,591	$	1,612,326	$	466,673	$	(1,923,538)	$	2,090,052


	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)	2,328		94,737		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	1,993		3,560		1,049		—		6,602
Total current assets	17,837		123,300		43,566		(14,344)		170,359
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	950,871		—		—		(950,871)		—
Goodwill	—		62,808		—		—		62,808
Investments	1,362,526		—		—		(1,362,526)		—
Other assets	8,225		6,793		17,552		—		32,570
Total assets	$	2,349,812	$	2,209,131	$	466,851	$	(2,327,741)	$	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	$	9,466	$	122,608	$	32,215	$	(12,603)	$	151,686
Accrued liabilities	27,505		16,539		5,620		(1,741)		47,923

Current portion of other long-term liabilities	812		6,563		6,875		—		14,250
Total current liabilities	37,783		145,710		44,710		(14,344)		213,859
Intercompany debt	—		948,790		2,081		(950,871)		—

Long-term debt less debt issuance costs	644,475		—		—		—		644,475
Non-current derivative liabilities	293		—		—		—		293
Other long-term liabilities	12,834		73,713		14,687		—		101,234
Deferred income taxes	60,983		83,765		—		—		144,748









Total shareholders' equity	1,593,444		957,153		405,373		(1,362,526)		1,593,444
Total liabilities and shareholders’ equity	$	2,349,812	$	2,209,131	$	466,851	$	(2,327,741)	$	2,698,053

Condensed Consolidating Statements of Operations


	Year Ended December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	494,180	$	227,939	$	(47,485)	$	674,634
Expenses:
Operating costs	—		256,024		176,189		(47,485)		384,728
Depreciation, depletion, and amortization	7,707		220,203		47,663		—		275,573
Impairments	—		622,676		3,040		—		625,716
General and administrative	—		38,246		—		—		38,246
(Gain) loss on disposition of assets	(11)		3,673		(160)		—		3,502
Total operating expenses	7,696		1,140,822		226,732		(47,485)		1,327,765
Income (loss) from operations	(7,696)		(646,642)		1,207		—		(653,131)
Interest, net	(35,466)		—		(1,546)		—		(37,012)
Gain on derivatives	4,225		—		—		—		4,225
Other	786		(1,086)		64		—		(236)
Loss before income taxes	(38,151)		(647,728)		(275)		—		(686,154)
Income tax expense (benefit)	7,238		(139,564)		—		—		(132,326)
Equity in net earnings from investment in subsidiaries, net of taxes	(508,439)		—		—		508,439		—
Net loss	(553,828)		(508,164)		(275)		508,439		(553,828)
Less: net income attributable to non-controlling interest	51		—		51		(51)		51
Net loss attributable to Unit Corporation	$	(553,879)	$	(508,164)	$	(326)	$	508,490	$	(553,879)


	Year Ended December 31, 2018
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	619,551	$	312,417	$	(88,687)	$	843,281
Expenses:
Operating costs	—		268,255		251,328		(88,687)		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		642,750		298,676		(88,687)		860,388
Income (loss) from operations	(7,649)		(23,199)		13,741		—		(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)		(23,199)		12,527		—		(53,763)
Income tax expense (benefit)	(11,962)		(4,064)		2,030		—		(13,996)
Equity in net earnings from investment in subsidiaries, net of taxes	(8,638)		—		—		(8,638)		—
Net income (loss)	(39,767)		(19,135)		10,497		(8,638)		(39,767)
Less: net income attributable to non-controlling interest	5,521		—		5,521		(5,521)		5,521
Net income (loss) attributable to Unit Corporation	$	(45,288)	$	(19,135)	$	4,976	$	(3,117)	$	(45,288)


	Year Ended December 31, 2017
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Revenues	$	—	$	534,084	$	277,049	$	(71,493)	$	739,640
Expenses:
Operating costs	—		258,132		220,613		(69,873)		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		446,401		272,734		(69,873)		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

Condensed Consolidating Statement of Comprehensive Income (Loss)

Condensed Consolidating Statements of Comprehensive Income (Loss)


	Year Ended December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net loss	$	(553,828)	$	(508,164)	$	(275)	$	508,439	$	(553,828)
Other comprehensive loss, net of taxes:
Reclassification adjustment for write-down of securities, net of tax of ($47)	—		481		—		—		481
Comprehensive loss	(553,828)		(507,683)		(275)		508,439		(553,347)
Less: Comprehensive income attributable to non-controlling interests	51		—		51		(51)		51
Comprehensive loss attributable to Unit Corporation	$	(553,879)	$	(507,683)	$	(326)	$	508,490	$	(553,398)


	Year Ended December 31, 2018
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
Net income (loss)	$	(39,767)	$	(19,135)	$	10,497	$	(8,638)	$	(39,767)
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax of ($181)	—		(557)		—		—		(557)
Comprehensive income	(39,767)		(19,692)		10,497		(8,638)		(40,324)
Less: Comprehensive income attributable to non-controlling interests	5,521		—		5,521		(5,521)		5,521
Comprehensive income (loss) attributable to Unit Corporation	$	(45,288)	$	(19,692)	$	4,976	$	(3,117)	$	(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 income on securities, net of tax of $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

Condensed Consolidating Statements of Cash Flows


	Year Ended December 31, 2019
	Parent		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Consolidating Adjustments		Total Consolidated
	(In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(9,681)	$	217,883	$	48,856	$	12,338	$	269,396
INVESTING ACTIVITIES:
Capital expenditures	65		(355,258)		(51,472)		—		(406,665)
Producing property and other oil and natural gas acquisitions	—		(3,653)		—		—		(3,653)
Other acquisitions	—		—		(16,109)		—		(16,109)
Proceeds from disposition of property and equipment	11		31,153		700		—		31,864
Net cash provided by (used in) investing activities	76		(327,758)		(66,881)		—		(394,563)
FINANCING ACTIVITIES:
Borrowings under credit agreements	400,600		—		92,900		—		493,500
Payments under credit agreements	(292,400)		—		(76,400)		—		(368,800)
Intercompany borrowings (advances), net	(97,455)		109,735		58		(12,338)		—
Payments on finance leases	—		—		(4,001)		—		(4,001)
Employee taxes paid by withholding shares	(4,158)		—		—		—		(4,158)
Distributions to non-controlling interest	919		—		(1,837)		—		(918)



Bank overdrafts	2,199		—		1,464		—		3,663
Net cash provided by financing activities	9,705		109,735		12,184		(12,338)		119,286
Net increase in cash and cash equivalents	100		(140)		(5,841)		—		(5,881)
Cash and cash equivalents, beginning of period	403		208		5,841		—		6,452
Cash and cash equivalents, end of period	$	503	$	68	$	—	$	—	$	571


	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	$	(310,120)	$	324,696	$	12,257	$	325,914	$	352,747
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 used in investing activities	266		(405,183)		(45,425)		—		(450,342)
FINANCING ACTIVITIES:
Borrowings under credit agreement	97,100		—		2,000		—		99,100
Payments under credit agreement	(275,100)		—		(2,000)		—		(277,100)
Intercompany borrowings (advances), net	202,558		80,504		(154,982)		(128,080)		—
Payments on finance leases	—		—		(3,843)		—		(3,843)
Proceeds from investments in non-controlling interest	300,000		—		197,042		(197,042)		300,000
Employee taxes paid by withholding shares	(4,988)		—		—		—		(4,988)
Transaction costs associated with sale of non-controlling interest	(2,503)		—		—		—		(2,503)

Bank overdrafts	(7,320)		—		—		—		(7,320)
Net cash provided by (used in) financing activities	309,747		80,504		39,009		(325,914)		103,346
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 operating activities	$	3,458	$	223,437	$	43,193	$	—	$	270,088
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 provided by (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	(27,615)		48,484		(20,869)		—		—
Payments on finance leases	—		—		(3,694)		—		(3,694)
Proceeds from common stock issued, net of issue costs	18,623		—		—		—		18,623
Employee taxes paid by withholding shares	(4,132)		—		—		—		(4,132)

Bank overdrafts	(4,911)		—		—		—		(4,911)
Net cash used in financing activities	(835)		48,484		(24,563)		—		23,086
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

Supplemental Oil And Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2019

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:


	2019		2018		2017
	(In thousands)
Capitalized costs:
Proved properties	$	6,341,582	$	6,018,568	$	5,712,813
Unproved properties	252,874		330,216		296,764
	6,594,456		6,348,784		6,009,577
Accumulated depreciation, depletion, amortization, and impairment	(5,846,177)		(5,124,257)		(4,996,696)
Net capitalized costs	$	748,279	$	1,224,527	$	1,012,881
Cost incurred:
Unproved properties acquired	$	34,668	$	57,430	$	47,029
Proved properties acquired	3,653		15,158		47,638
Exploration	16,480		15,907		14,811
Development	211,443		280,692		160,941
Asset retirement obligation	76		(7,629)		(3,613)
Total costs incurred	$	266,320	$	361,558	$	266,806

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, 2019, by the year in which such costs were incurred:


	2019		2018		2017		2016 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	22,621	$	54,780	$	47,646	$	127,827	252,874

Results Of Operations For Producing Activities [Table Text Block]

The results of operations for producing activities are as follows:


	2019		2018		2017
	(In thousands)
Revenues	$	314,925	$	411,601	$	347,285
Production costs	(116,051)		(113,810)		(107,332)
Depreciation, depletion, amortization, and impairment	(727,529)		(132,923)		(96,392)
	(528,655)		164,868		143,561
Income tax (expense) benefit	101,952		(42,915)		(56,376)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	(426,703)	$	121,953	$	87,185

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)
2017
Proved developed and undeveloped reserves:
Beginning of year	15,696	34,482	405,579	117,774
Revision of previous estimates	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 ⁽¹⁾	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
2019
Proved developed and undeveloped reserves:
Beginning of year	22,558	47,796	535,963	159,681
Revision of previous estimates ⁽²⁾	(8,263)	(20,961)	(234,852)	(68,366)
Extensions and discoveries ⁽²⁾	703	845	8,798	3,015
Infill reserves in existing proved fields	271	434	4,806	1,506
Purchases of minerals in place	183	101	1,316	503
Production	(3,208)	(4,773)	(53,064)	(16,825)
Sales	(48)	(412)	(42,780)	(7,590)
End of year	12,196	23,030	220,187	71,924
Proved developed reserves:
Beginning of year	15,192	33,515	377,216	111,576
End of year	12,196	23,030	220,187	71,924
Proved undeveloped reserves:
Beginning of year	7,366	14,281	158,747	48,105
End of year	—	—	—	—

_________________________

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]


	2019		2018		2017
	(In thousands)
Future cash flows	$	1,386,777	$	3,980,369	$	3,347,396
Future production costs	(698,357)		(1,479,744)		(1,308,244)
Future development costs	—		(442,984)		(369,560)
Future income tax expenses	(321)		(307,916)		(234,152)
Future net cash flows	688,099		1,749,725		1,435,440
10% annual discount for estimated timing of cash flows	(226,390)		(766,047)		(628,270)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	461,709	$	983,678	$	807,170

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:


	2019		2018		2017
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(200,233)	$	(297,791)	$	(239,953)
Net changes in prices and production costs	(508,066)		120,062		236,126
Revisions in quantity estimates and changes in production timing	(338,994)		(33,282)		87,239
Extensions, discoveries, and improved recovery, less related costs	53,123		234,172		102,965
Changes in estimated future development costs	311,190		19,535		(5,194)
Previously estimated cost incurred during the period	64,362		63,557		36,044
Purchases of minerals in place	6,416		23,416		51,686
Sales of minerals in place	(25,813)		(5,004)		(1,447)
Accretion of discount	110,571		89,753		57,517
Net change in income taxes	121,708		(31,674)		(33,389)
Changes in timing and other	(116,233)		(6,236)		(2,634)
Net change	(521,969)		176,508		288,960
Beginning of year	983,678		807,170		518,210
End of year	$	461,709	$	983,678	$	807,170

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.

+ References + Details

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.

+ References + Details

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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+ Details

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

12 Months Ended

Dec. 31, 2019

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, 2019	$	2,531	$	527	$	(726)	$	2,332
Year ended December 31, 2018	$	2,450	$	81	$	—	$	2,531
Year ended December 31, 2017	$	3,773	$	348	$	(1,671)	$	2,450

Liquidity and Ability to Continue as a Going Concern (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Jan. 17, 2020	Sep. 26, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Conditions that raised substantial doubt about going concern	This conclusion is based on the following principal conditions which are explained in further detail below.•Inability to meet anticipated commitments due to recurring losses, negative working capital and limited access to liquidity.•A forecasted covenant violation of the Unit credit agreement for the quarter ending June 30, 2020.•The expected acceleration of the amounts outstanding under the Unit credit agreement from October 18, 2023 to November 16, 2020.
Cash and cash equivalents	$ 571			$ 6,452	$ 701	$ 893
Unit credit agreement with an average interest rate of 4.0% at December 31, 2019	108,200			0
Aggregate principal amount	$ 650,000			650,000
Substantial Doubt about Going Concern, Management's Evaluation	Based on our evaluation of the conditions described above, substantial doubt exists about our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.
Management's plans to alleviate the substantial doubt about going concern	In order to alleviate the conditions that give rise to substantial doubt about our ability to continue as a going concern, the company is currently undertaking a number of actions, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, (iv) exploring potential business transactions, and (v) negotiating with existing debt holders to restructure existing debts. We believe that even after taking these actions, we will not have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with our debt covenants. We have engaged financial and legal advisors to, among other things, assist with analyzing various strategic alternatives, to include a potential reorganization under Chapter 11, to address our liquidity and capital structure. However, there can be no assurance that we will be able to restructure our financial obligations on terms acceptable to the company and our creditors, and there can be no assurance that we will generate the necessary liquidity to satisfy these obligations when they come due.
Unit Credit Agreement [Member]
Unit credit agreement with an average interest rate of 4.0% at December 31, 2019	$ 108,200			0
Unit Credit Agreement [Member] \| Line Of Credit Facility Commitment Amount
Credit facility current credit amount			$ 275,000	$ 425,000
Unit Credit Agreement [Member] \| Line Of Credit Facility Commitment Amount \| Subsequent Event
Credit facility current credit amount		$ 200,000

Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CVR Refining, LP \| Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	14.00%	14.00%	2.00%
Valero Energy Corporation \| Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	9.00%	10.00%	9.00%
Energy Transfer Partners (formerly Sunoco Logistics Partners) \| Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	5.00%	3.00%	10.00%
EOG Resources, Inc. \| Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	12.00%	5.00%	0.00%
QEP Resources, Inc. \| Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	12.00%	16.00%	26.00%
Slawson Exploration Company, Inc \| Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	11.00%	10.00%	6.00%
ONEOK, Inc. \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	33.00%	45.00%	36.00%
Range Resources Corporation \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	13.00%	7.00%	9.00%
Centerpoint Energy Service, Inc. \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	5.00%	4.00%

Summary Of Significant Accounting Policies (Schedule of Fair Values of the Net Asset (Liabilities)) (Details) $ in Millions	Dec. 31, 2019 USD ($)
Derivative Counterparty [Line Items]
Total net assets	$ 0.6
Bank of Montreal
Derivative Counterparty [Line Items]
Total net assets	0.4
Bank of America Merrill Lynch
Derivative Counterparty [Line Items]
Total net assets	$ 0.2

Summary Of Significant Accounting Policies (Narrative) (Details)

3 Months Ended

12 Months Ended

Dec. 31, 2019

USD ($)

MMcf

Sep. 30, 2019

USD ($)

Dec. 31, 2019

USD ($)

Partnerships

contract

rig

MMcf

Dec. 31, 2018

USD ($)

rig

Dec. 31, 2017

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 18 – Variable Interest Entity Arrangements.

Number of contracts, daywork expiring in one year | contract

Number of contracts, daywork expiring in two years | contract

Bank Overdrafts

$ 8,700,000

$ 5,100,000

Concentration of cash

1,700,000

11,000,000.0

Reclassification from held-for-sale back to held and use

5,908,000

22,511,000

10,800,000

Interest Costs Capitalized

16,200,000

16,500,000

$ 15,900,000

Goodwill, Impairment Loss, Net of Tax

62,800,000

59,800,000

Additions to goodwill

16,500,000

15,900,000

14,800,000

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

9.66

7.50

6.00

Future discounted net cash flows discounted

252,874,000

$ 252,874,000

330,216,000

296,764,000

10.00%

Unproved properties included in amortization

73,900,000

$ 73,900,000

10,500,000

Ceiling test wrtie-down

390,100,000

$ 169,300,000

559,400,000

Non-cash ceiling test write-down net of tax

294,500,000

$ 127,900,000

422,400,000

Revenues from transactions with operating segments of same entity

15,800,000

22,490,000

13,400,000

Eliminated associated operating expense

14,200,000

19,500,000

11,800,000

Eliminated yielding

$ 1,600,000

$ 2,990,000

$ 1,600,000

Number of oil and gas limited partnerships | Partnerships

Repurchase of limited units outstanding amount

$ 600,000

Federal statutory income tax rate, percent

21.00%

35.00%

Tax benefit from change in enacted tax rate

^[1]

$ 0

$ (81,307,000)

Liability recognized to under production

(3,838,000)

$ (3,838,000)

(3,331,000)

Drilling

Summary Of Significant Accounting Policies [Line Items]

Number of daywork contracts | contract

Impairment of Drilling Equipment

147,900,000

Impairment of contract drilling equipment, net of tax

$ 111,700,000

Number of drilling rigs in assets held for sale | rig

Minimum

Summary Of Significant Accounting Policies [Line Items]

10 days

Summary Of Significant Accounting Policies [Line Items]

2 months

Insurance coverage

$ 0

Minimum | Drilling

10 days

Summary Of Significant Accounting Policies [Line Items]

2 months

Maximum

90 days

Summary Of Significant Accounting Policies [Line Items]

3 years

Insurance coverage

$ 1,000,000.0

Maximum | Drilling

90 days

Under-Produced Properties

3 years

Summary Of Significant Accounting Policies [Line Items]

Natural gas balancing (MMcf) | MMcf

3,400

Over-Produced Properties

Summary Of Significant Accounting Policies [Line Items]

Natural gas balancing (MMcf) | MMcf

3,500

Natural Gas Balancing

Summary Of Significant Accounting Policies [Line Items]

Summary Of Significant Accounting Policies [Line Items]

$ 3,600,000

Drilling Equipment

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

20.00%

Number of drilling rigs removed from service | rig

Impairment of Drilling Equipment

$ 0

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]

Long-term Contract with Customer [Member] | Drilling

15 years

Summary Of Significant Accounting Policies [Line Items]

Number of daywork contracts | contract

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

Summary Of Significant Accounting Policies [Line Items]

Mechanical drilling rigs | Drilling Equipment

2 months

Summary Of Significant Accounting Policies [Line Items]

Number of drilling rigs removed from service | rig

SCR diesel-electric drilling rigs | Drilling Equipment

Summary Of Significant Accounting Policies [Line Items]

Number of drilling rigs removed from service | rig

Salvage Value [Member]

Summary Of Significant Accounting Policies [Line Items]

Change in Accounting Estimate, Description

Change in estimate for salvage value

$ 39,700,000

Change in estimate for salvage value, discounted

$ 25,600,000

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

Revenue from Contracts with Customers (Revenue, Remaining Performance Obligation) (Details) - Mid-Stream $ in Thousands	Dec. 31, 2019 USD ($)
Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	$ (5,860)
2020 \| Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	(3,775)
2021 \| Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	(3,501)
2022 \| Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	1,380
2023 and beyond \| Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining impact to revenue	$ 36
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31 \| Minimum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining term of contract	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31 \| Minimum \| Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining term of contract	3 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31 \| Maximum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining term of contract	15 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31 \| Maximum \| Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining term of contract	9 years

Revenue from Contracts with Customers (Contract with Customer, Asset and Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Adoption of ASC606 [Line Items]
Contract liability	$ 7,061	$ 9,881
Change in contact assets and liabilities, net	(2,577)	(4,970)	$ 0
Mid-Stream
Adoption of ASC606 [Line Items]
Contract Assets	12,921	13,164
Change in contract assets	(243)
Contract liability	7,061	9,881
Change in contract liabilities	(2,820)
Contract assets (liabilities), net	5,860	3,283
Change in contact assets and liabilities, net	$ (2,577)	$ (5,000)

Revenue from Contracts with Customers (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) contract	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jan. 01, 2018 USD ($)
Segment Reporting Information [Line Items]
Retained earnings	$ 199,135	$ 752,840
Change in contact assets and liabilities, net	$ (2,577)	(4,970)	$ 0
Minimum
Segment Reporting Information [Line Items]
Contact duration	2 months
Number of days for drilling of one well	10 days
Maximum
Segment Reporting Information [Line Items]
Contact duration	3 years
Number of days for drilling of one well	90 days
Oil and Natural Gas
Segment Reporting Information [Line Items]
Revenue Satisfied at Point in Time, Transfer of Control	Revenues from sales we make are recognized when our customer obtains control of the sold product. For sales to other mid-stream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer.
Oil and Natural Gas \| Adjustments due to ASC606 [Member]
Segment Reporting Information [Line Items]
Retained earnings				$ 0
Drilling
Segment Reporting Information [Line Items]
Revenue Satisfied over Time, Method Used	At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under this new standard allow us to recognize revenues associated with our drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Those liabilities will generally only arise in relation to upfront mobilization fees paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue.
Number of daywork contracts \| contract	21
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]
Segment Reporting Information [Line Items]
Retained earnings				0
Drilling \| Long-term Contract with Customer [Member]
Segment Reporting Information [Line Items]
Number of daywork contracts \| contract	14
Drilling \| Minimum
Segment Reporting Information [Line Items]
Contact duration	2 months
Number of days for drilling of one well	10 days
Drilling \| Minimum \| Long-term Contract with Customer [Member]
Segment Reporting Information [Line Items]
Contact duration	2 months
Drilling \| Maximum
Segment Reporting Information [Line Items]
Contact duration	3 years
Number of days for drilling of one well	90 days
Mid-Stream
Segment Reporting Information [Line Items]
Revenue Satisfied over Time, Method Used	Contract terms range from a single month to terms spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.
Revenue, Practical Expedient, Initial Application and Transition, Qualitative Assessment	As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee.
Change in contact assets and liabilities, net	$ (2,577)	$ (5,000)
Mid-Stream \| Adjustments due to ASC606 [Member]
Segment Reporting Information [Line Items]
Adjustment to opening retained earnings, before tax				(1,700)
Adjustment to opening retained earnings, after tax				$ (1,300)
Mid-Stream \| Minimum
Segment Reporting Information [Line Items]
Contact duration	5 years
Mid-Stream \| Maximum
Segment Reporting Information [Line Items]
Contact duration	10 years

Acquisitions and Divestitures (Fair Value of Acquired Assets and Liabilities) (Details) - USD ($)
$ in Thousands

Dec. 06, 2018

Apr. 03, 2017

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Proved oil and natural gas properties

$ 6,341,582

$ 6,018,568

$ 5,712,813

Asset retirement obligation

252,874

330,216

296,764

$ (66,627)

$ (64,208)

$ (69,444)

EOG Acquisition

Total consideration given

$ 54,332

Proved oil and natural gas properties

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

Total consideration given

$ 29,633

Proved oil and natural gas properties

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, $ in Thousands				12 Months Ended
	Dec. 06, 2018 USD ($) a MBoe numberOfDrillingLocations wells	Apr. 03, 2018 USD ($)	Apr. 03, 2017 USD ($) a MBoe wells	Dec. 31, 2019 USD ($) MBoe rig milesOfPipeline	Dec. 31, 2018 USD ($) MBoe rig	Dec. 31, 2017 USD ($) MBoe rig	Dec. 31, 2016 MBoe
Acquisitions and Divestitures [Line Items]
Proved Developed Reserves (Volume) \| MBoe				71,924	111,576	112,961	99,079
Net book value of drilling rigs sold				$ 5,700
Gain (loss) on sale of drilling rigs				1,100
Reclassification from held-for-sale back to held and use				10,800
Assets held for sale				5,908	$ 22,511
Variable Interest Entity, Date Involvement Began		Apr. 03, 2018
EOG Acquisition
Acquisitions and Divestitures [Line Items]
Total consideration given			$ 54,332
Business Acquisition, Effective Date of Acquisition			Jan. 01, 2017
Proved Developed Reserves (Volume) \| MBoe			3,200
Natural Gas Gathering System			1
Excalibur Acquisition
Acquisitions and Divestitures [Line Items]
Total consideration given	$ 29,633
Business Acquisition, Effective Date of Acquisition	Nov. 01, 2018
Proved Developed Reserves (Volume) \| MBoe	2,600
Horizontal drilling locations \| numberOfDrillingLocations	30
Acquired land with existing production capacity, percent	82.00%
Hoxbar \| EOG Acquisition
Acquisitions and Divestitures [Line Items]
Area of Real Estate Property \| a			8,300
Proved developed producing wells \| wells			47
Acquired land with existing production capacity, percent			71.00%
Penn Sands \| Excalibur Acquisition
Acquisitions and Divestitures [Line Items]
Area of Real Estate Property \| a	8,667
Wells acquired \| wells	44
Oil and Natural Gas
Acquisitions and Divestitures [Line Items]
Other acquisitions				3,700	600	$ 4,700
Proceeds from divestiture of assets				$ 21,800	$ 22,500	$ 18,600
Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of rigs sold \| rig				6		0
Number of drilling rigs removed from service \| rig					41
Impairment of Drilling Equipment						$ 0
Mid-Stream
Acquisitions and Divestitures [Line Items]
Business Acquisition, Effective Date of Acquisition				Dec. 01, 2019
Other acquisitions				$ 16,100
Pipeline acquired \| milesOfPipeline				572
Mechanical drilling rigs \| Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of drilling rigs removed from service \| rig					29
SCR diesel-electric drilling rigs \| Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of drilling rigs removed from service \| rig					12
Ownership interest in Superior Pipeline Company, L.L.C.
Acquisitions and Divestitures [Line Items]
Proceeds from sale of non-controlling interest		$ 300,000
Superior Pipeline Company, L.L.C. \| Ownership interest in Superior Pipeline Company, L.L.C.
Acquisitions and Divestitures [Line Items]
Ownership interest sold		50.00%

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, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Earnings Per Share [Abstract]

Income (loss) of basic earnings (loss) attributable to Unit Corporation per common share

$ (334,980)

^[1]

$ (206,886)

^[2]

$ (8,509)

$ (3,504)

$ (77,840)

^[3]

$ 18,899

$ 5,788

$ 7,865

$ (553,879)

$ (45,288)

$ 117,848

Income (loss) of effect of dilutive stock options and restricted stock

Income (loss) of diluted earnings (loss) attributable to Unit Corporation per common share

$ (553,879)

$ (45,288)

$ 117,848

Weighted shares of basic earnings (loss) attributable to Unit Corporation per common share

52,849

51,981

51,113

Weighted shares of effect of dilutive stock options and restricted stock

635

Weighted shares of diluted earnings (loss) attributable to Unit Corporation per common share

52,849

51,981

51,748

Per share amount of basic earnings (loss) attributable to Unit Corporation per common share

$ (6.33)

$ (3.91)

$ (0.16)

$ (0.07)

$ (1.49)

$ 0.36

$ 0.11

$ 0.15

$ (10.48)

$ (0.87)

$ 2.31

Per share amount of effect of dilutive stock options and restricted stock

(0.03)

Per share amount of diluted earnings (loss) attributable to Unit Corporation per common share

$ (6.33)

$ (3.91)

$ (0.16)

$ (0.07)

$ (1.49)

$ 0.36

$ 0.11

$ 0.15

$ (10.48)

$ (0.87)

$ 2.28

[1]	During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax).
[2]	During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax).
[3]	In the fourth quarter of 2018, we recorded an impairment for contract drilling equipment that included a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

Earnings (Loss) Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options	42,000	66,500	87,500
Average Exercise Price	$ 48.56	$ 44.42	$ 51.34

Earnings (Loss) Per Share (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Stock options and restricted stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share due to net loss	428,000	934,000

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accrued Liabilities [Abstract]
Employee costs	$ 17,832	$ 20,315
Lease operating expenses	9,200	12,756
Interest payable	6,562	6,635
Third-party credits	3,691	2,129
Taxes	3,450	1,378
Other	5,827	4,710
Total accrued liabilities	$ 46,562	$ 47,923

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current portion of long-term debt:
Unit credit agreement with an average interest rate of 4.0% at December 31, 2019	$ 108,200	$ 0
Long-term debt:
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	666,500	650,000
Less: unamortized discount	(971)	(1,623)
Less: debt issuance costs, net	(2,313)	(3,902)
Total long-term debt	663,216	644,475
Superior Credit Agreement [Member]
Long-term debt:
Superior credit agreement with an average interest rate of 3.9% at December 31, 2019	$ 16,500	$ 0
Line of Credit Facility, Interest Rate at Period End	3.90%	0.00%
Unit Credit Agreement [Member]
Current portion of long-term debt:
Unit credit agreement with an average interest rate of 4.0% at December 31, 2019	$ 108,200	$ 0
Long-term debt:
Line of Credit Facility, Interest Rate at Period End	4.00%	0.00%

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Long-term debt and other long-term liabilites [Abstract]
ARO liability	$ 66,627	$ 64,208	$ 69,444
Workers' compensation	11,510	12,738
Finance lease obligations	7,379	11,380
Contract liability	7,061	9,881
Separation benefit plans	10,122	8,814
Deferred compensation plan	6,180	5,132
Gas balancing liability	3,838	3,331
Other liabilities	112,717	115,484
Current portion of other long-term liabilities	17,376	14,250
Other long-term liabilities	$ 95,341	$ 101,234

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands		12 Months Ended
	May 02, 2018	Dec. 31, 2019	Jan. 17, 2020	Sep. 26, 2019	Dec. 31, 2018	Apr. 02, 2018
Debt Instrument [Line Items]
Oil and Gas Property, Full Cost Method, Discount Percentage		10.00%
Aggregate principal amount		$ 650,000			$ 650,000
Interest percentage of senior subordinated notes		6.625%
Debt Instrument, Maturity Date		May 15, 2021
Principal Payments Year One		$ 125,600
Principal Payments Year Two		659,300
Principal Payments Year Three		45,100
Principal Payments Year Four		19,500
Principal Payments Year Five		2,000
Senior Notes 6.625% Due 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal amount		$ 650,000
Interest percentage of senior subordinated notes		6.625%
Debt Instrument, Maturity Date		May 15, 2021
Deducting fees for debt issuance		$ 14,700
Senior notes repurchase price in percentage		101.00%
Senior Notes, Covenant Compliance		We were in compliance with all covenants of the Notes
Debt Instrument, Subjective Acceleration Clause		If an event of default occurs under the Unit credit agreement that accelerates the maturity of at least $25.0 million of borrowings, then it will cause a default under the 2011 Indenture which may in turn accelerate the maturity of the Notes.
Unit Credit Agreement [Member]
Debt Instrument [Line Items]
Credit facility maturity date		October 18, 2023
Credit Facility Maximum Credit Amount						$ 1,000,000
Commitment fee percentage under credit facility		0.375%
Origination, agency and syndication fees		$ 3,300
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
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		As of December 31, 2019, we were in compliance with these covenants.
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				$ 275,000	$ 425,000
Unit Credit Agreement [Member] \| Line Of Credit Facility Commitment Amount \| Subsequent Event
Debt Instrument [Line Items]
Credit facility current credit amount			$ 200,000
Unit Credit Agreement [Member] \| Line Of Credit Facility Lender Determined Amount
Debt Instrument [Line Items]
Credit facility current credit amount				$ 275,000
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]
Credit Facility Maximum Credit Amount		$ 250,000
Credit facility current credit amount		$ 200,000
Commitment fee percentage under credit facility		0.375%
Origination, agency and syndication fees		$ 1,700
Covenant Compliance		As of December 31, 2019, Superior complied with these 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, 2019

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

ARO liability, January 1:

$ 64,208

$ 69,444

Accretion of discount

2,343

2,393

Liability incurred

4,373

2,632

Liability settled

(3,261)

(4,493)

Liability sold

(2,953)

(281)

Revision of estimates

^[1]

1,917

(5,487)

ARO liability, December 31:

66,627

64,208

Less current portion

2,920

1,437

Total long-term ARO liability

$ 63,707

$ 62,771

[1]	Plugging liability estimates were revised in both 2019 and 2018 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, 2019

Dec. 31, 2018

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income tax expense (benefit) computed by applying the statutory rate

$ (144,092)

$ (11,290)

$ 21,059

State income tax expense (benefit), net of federal benefit

(21,733)

(1,882)

1,655

Deferred tax liability revaluation

^[1]

(81,307)

Restricted stock shortfall

347

424

1,867

Non-controlling interest in Superior

(11)

(1,138)

Statutory depletion and other

12,346

Valuation allowance

19,654

1,163

(110)

(952)

Operating Loss Carryforwards [Line Items]

$ (132,326)

$ (13,996)

$ (57,678)

[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, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Current taxes, Federal	$ (918)	$ (1,835)	$ 0
Current taxes, State	(363)	(1,296)	5
Current taxes	(1,281)	(3,131)	5
Deferred taxes, Federal	(108,440)	(8,741)	(62,788)
Deferred taxes, State	(22,605)	(2,124)	5,105
Deferred taxes	(131,045)	(10,865)	(57,683)
Total provision	$ (132,326)	$ (13,996)	$ (57,678)

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Allowance for losses and nondeductible accruals	$ 31,822	$ 27,953
Net operating loss carryforward	246,927	152,112
Alternative minimum tax and research and development tax credit carryforward	2,656	3,574
Deferred tax assets, total	281,405	183,639
Depreciation, depletion, amortization, and impairment	(226,034)	(291,542)
Investment in Superior	(49,430)	(36,845)
Net deferred tax asset (liability)	5,941	(144,748)
Valuation allowance	(19,654)	0
Current deferred tax asset	0	0
Non-current-deferred tax liability	$ (13,713)	$ (144,748)

Income Taxes (Narrative) (Details) - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Federal statutory income tax rate, percent

21.00%

35.00%

Tax benefit from change in enacted tax rate

^[1]

$ 0

$ (81,307,000)

(132,326,000)

(13,996,000)

(57,678,000)

Nondeductible expense from goodwill impairment

62,800,000

50,300,000

Deductible expense from goodwill impairment

$ 12,346,000

$ 0

Valuation Allowance, Commentary

Valuation allowance

$ (19,654,000)

$ 0

Operating loss carryforwards

980,800,000

Operating loss carryforwards subject to expiration

$ 584,200,000

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, 2019 USD ($) yr shares	Dec. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($) shares
Defined Benefit Plan Disclosure [Line Items]
Recognized stock compensation expense			$ 12,800	$ 17,800	$ 13,300
Deferred compensation plan			$ 6,180	$ 5,132
Employee Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution of shares, common stock \| shares			310,797	184,203	155,822
Recognized stock compensation expense			$ 5,200	$ 5,100	$ 4,400
Separation Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service period, years		20 years
Maximum period benefit, weeks \| week		104
Separation benefit plans expense			$ 3,800	$ 3,600	$ 2,700
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Well supervision and other fees	$ 1	$ 158	$ 172
General and administrative expense reimbursement	$ 0	$ 0	$ 0

Transactions With Related Parties (Narrative) (Details)	12 Months Ended
Transactions With Related Parties (Narrative) (Details)	Dec. 31, 2019 USD ($) Partnerships	Dec. 31, 2018 USD ($) Partnerships	Dec. 31, 2017 USD ($)	Dec. 31, 2016 Partnerships
Related Party Transaction [Line Items]
Number of oil and gas limited partnerships for employee investment \| Partnerships	13
Partnerships dissolved \| Partnerships	0	0		2
Repurchase of limited units outstanding amount \| $	$ 600,000
G. Bailey Peyton IV
Related Party Transaction [Line Items]
Payments for royalties \| $	$ 400,000	$ 900,000	$ 700,000
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) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Recognized stock compensation expense	$ 12.8	$ 17.8	$ 13.3
Capitalized stock compensation cost for our oil and natural gas properties	2.4	2.1	1.8
Tax benefit on stock based compensation	$ 3.1	$ 4.4	$ 5.0

Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	1,877,008	1,363,987	1,301,865
Weighted average price, beginning balance	$ 19.70	$ 21.25	$ 23.32
Number of shares, granted	1,427,429	1,234,943	659,172
Weighted average price, granted	$ 16.09	$ 20.52	$ 26.07
Number of shares, vested	(803,942)	(679,814)	(517,689)
Weighted average price, vested	$ 15.56	$ 24.30	$ 29.87
Number of shares, forfeited	(131,473)	(42,108)	(79,361)
Weighted average price, forfeited	$ 19.36	$ 19.80	$ 38.87
Number of shares, ending balance	2,369,022	1,877,008	1,363,987
Weighted average price, ending balance	$ 18.95	$ 19.70	$ 21.25
Restricted Stock - Non-employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	107,045	117,714	111,816
Weighted average price, beginning balance	$ 17.07	$ 16.03	$ 17.21
Number of shares, granted	72,784	44,312	49,104
Weighted average price, granted	$ 12.09	$ 19.86	$ 17.92
Number of shares, vested	(61,141)	(54,981)	(43,206)
Weighted average price, vested	$ 15.49	$ 17.08	$ 21.24
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$ 0	$ 0	$ 0
Number of shares, ending balance	118,688	107,045	117,714
Weighted average price, ending balance	$ 14.83	$ 17.07	$ 16.03
Time Vested \| Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	1,268,883	915,558	929,737
Number of shares, granted	927,173	844,498	485,799
Number of shares, vested	(570,107)	(470,171)	(455,570)
Number of shares, forfeited	(98,301)	(21,002)	(44,408)
Number of shares, ending balance	1,527,648	1,268,883	915,558
Performance Shares \| Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	608,125	448,429	372,128
Number of shares, granted	500,256	390,445	173,373
Number of shares, vested	(233,835)	(209,643)	(62,119)
Number of shares, forfeited	(33,172)	(21,106)	(34,953)
Number of shares, ending balance	841,374	608,125	448,429

Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) - Directors Plan - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	66,500	87,500	108,500
Weighted average price, beginning balance	$ 44.42	$ 51.34	$ 52.56
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	(24,500)	(21,000)	(21,000)
Weighted average price, forfeited	$ 37.31	$ 73.26	$ 57.63
Number of shares, ending balance	42,000	66,500	87,500
Weighted average price, ending balance	$ 48.56	$ 44.42	$ 51.34

Stock-Based Compensation (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) - Directors Plan	12 Months Ended
	Dec. 31, 2019 $ / shares shares
$41.21
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding and exercisable options, number of shares \| shares	17,500
Outstanding and exercisable options weighted average remaining contractual life, years	3 months 18 days
Outstanding and exercisable options, weighted average exercise price \| $ / shares	$ 41.21
$53.81
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding and exercisable options, number of shares \| shares	24,500
Outstanding and exercisable options weighted average remaining contractual life, years	1 year 3 months 18 days
Outstanding and exercisable options, weighted average exercise price \| $ / shares	$ 53.81

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 13.1
Unrecognized compensation cost, expect to be capitalized	$ 1.9
Weighted average years over which this cost will be recognized	8 months 12 days
Incentive Stock Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance				2,000,000.0
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, granted	0	0	0
Shares vested	0	0	0
Number of shares, ending balance	0	0	0
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	2,487,710
Vesting Period	3 years
Grant date fair value	$ 22.6	$ 24.7	$ 17.4
Number of shares, vested	(865,083)
Exercised intrinsic value	$ 11.9
Exercisable options intrinsic value	$ 1.7
Restricted stock weighted average remaining contractual term, years	1 year
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	10 months 24 days
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] \| 2019 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	3.00%
Cash flow to total assets performance [Member] \| 2018 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	45.00%
Cash flow to total assets performance [Member] \| 2017 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	0.00%
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) - Natural gas	12 Months Ended
	Dec. 31, 2019 $ / Unit MMBoe
Basis Swap \| PEPL \| Jan'20 - Dec'20
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBoe	20,000
Swap price	(0.455)
Basis Swap \| NGPL Texok \| Jan'20 - Dec'20
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBoe	30,000
Swap price	(0.275)
Basis Swap \| NGPL Texok \| Jan'21 - Dec'21
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBoe	30,000
Swap price	(0.215)
Three-way collar \| If Nymex \| Jan'20 - Dec'20
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBoe	30,000
Floor Price	2.50
Ceiling Price	2.80
Subfloor Price	2.20

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative assets	$ 633	$ 12,870
Non-current derivative assets	0	0
Total derivatives assets	633	12,870
Current derivative liabilities	0	0
Non-current derivative liabilities	27	293
Total derivative liabilities	$ 27	$ 293

Derivatives (Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) on Derivatives

$ 4,225

$ (3,184)

Cash receipts (payments) on derivatives settled

16,196

(22,803)

Commodity Contract

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) on Derivatives

^[1]

$ 4,225

$ (3,184)

[1]	Amounts settled during the periods are a gain of $16,196 and a loss of $22,803, respectively.

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	$ 600
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	633	$ 12,870
Liabilities	(27)	(293)
Financial assets (liabilities)	606	12,577
Commodity Contract \| Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	177	3,225
Liabilities	(775)	(1,278)
Financial assets (liabilities)	(598)	1,947
Commodity Contract \| Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	1,204	10,964
Liabilities	0	(334)
Financial assets (liabilities)	1,204	10,630
Commodity Contract \| Effect of Netting
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	(748)	(1,319)
Liabilities	748	1,319
Financial assets (liabilities)	$ 0	$ 0

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Beginning of period	$ 10,630	$ (206)
Included in earnings	(1,494)	4,159
Settlements	(7,932)	6,677
End of period	1,204	10,630
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$ (9,426)	$ 10,836

Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) - Natural gas - Level 3 - Three-way collar
$ in Thousands

12 Months Ended

Dec. 31, 2019

USD ($)

$ / Unit

Fair Value | $

$ 1,204

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Minimum

Average Forward Price

Maximum

Average Forward Price

0.39

[1]	The commodity contracts detailed in this category include non-exchange-traded natural gas three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
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	646,700	$ 644,500
Estimated fair value of long-term debt	$ 357,500	$ 600,500

Leases (Supplemental cash flow information related to leases) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Leases [Abstract]
Operating cash flows for operating leases	$ 4,034
Financing cash flows for finance leases	4,001
Lease liabilities recognized in exchange for new operating lease right of use assets	$ 5

Leases (Schedule of lease assets and liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Right of use asset	$ 5,673	$ 0
Finance right of use assets	17,396
Total right of use assets	23,069
Current operating lease liabilities	3,430	0
Current portion of other long-term liabilities	4,164
Operating lease liability (Note 16)	2,071	$ 0
Finance lease liabilities	3,215
Total lease liabilities	$ 12,880

Leases (Schedule of lease costs) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2019

USD ($)

Amortization of finance leased assets

$ 4,001

Interest on finance lease liabilities

382

Operating lease cost

4,034

Short-term lease cost

38,868

^[1]

Variable lease cost

351

Total lease cost

$ 47,636

[1]	Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $25.1 million.

Leases (Schedule of weighted average discount rate for leases) (Details)

Dec. 31, 2019

Operating Lease, Weighted Average Remaining Lease Term

1 year 10 months 24 days

Operating Lease, Weighted Average Discount Rate, Percent

6.13%

^[1]

Finance Lease, Weighted Average Remaining Lease Term

1 year 8 months 12 days

Finance Lease, Weighted Average Discount Rate, Percent

4.00%

^[1]

[1]	Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

Leases (Operating leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Ending January 1,
2021	$ 3,670
2022	1,614
2023	419
2024	73
2025	12
2026 and beyond	75
Total future payments	5,863
Less: Interest	362
Present value of future minimum operating lease payments	5,501
Less: Current portion	(3,430)	$ 0
Long-term operating lease payments	$ 2,071	$ 0

Leases (Financing leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Ending January 1,
2021	$ 6,194
2022	3,774
Total future payments	9,968
Less payment related to:
Maintenance	2,336
Interest	253
Finance lease obligations	7,379	$ 11,380
Current portion of finance leases	4,164
Total long-term finance lease payments	$ 3,215

Leases (Narrative) (Details) $ in Thousands	12 Months Ended
Leases (Narrative) (Details) $ in Thousands	Dec. 31, 2019 USD ($)	Jan. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)
Adoption of ASC842 [Line Items]
Operating leases under ASC 840 future minimum payments due in next year			$ 4,600
Operating leases under ASC 840 future minimum payments due in two years			1,700
Operating leases under ASC 840 future minimum payments due in three years			400
Average working interest in operated properties	95.00%
Right of use asset	$ 5,673		$ 0
Total operating lease liability	$ 5,501
Number of compressors under capital lease agreement	20
Finance lease term	7 years
Current portion of finance leases	$ 4,164
Total long-term finance lease payments	$ 3,215
Discount rate finance leases	4.00%
Maintenance	$ 2,336
Interest	253
Finance leases, future minimum payments, average annual payment	$ 4,400
Finance lease fair market value percentage for purchase	10.00%
Accounting Standards Update 2016-02 [Member]
Adoption of ASC842 [Line Items]
Right of use asset		$ 3,700
Total operating lease liability		$ 3,500

Commitments And Contingencies (Details)	12 Months Ended
Commitments And Contingencies (Details)	Dec. 31, 2019 USD ($)
Other Commitments [Line Items]
Repurchase of limited units outstanding	20.00%
Repurchase of limited units outstanding amount	$ 600,000
Mid-Stream
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	2,800,000
Other Commitment, Due in Second and Third Year	700,000
Oil and Natural Gas
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 900,000
Oil and Natural Gas \| Capital Addition Purchase Commitments [Member]
Other Commitments [Line Items]
Long-term Purchase Commitment, Description	as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is included in our future drilling plans. For each dollar of the $150.0 million that we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. At December 31, 2019, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.7 million.
Long-term purchase commitment, purchases made	$ 24,700,000

Variable Interest Entity Arrangements (Schedule of Assets and Liabilities) (Details) - USD ($)
$ in Thousands

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 571

$ 6,452

$ 701

$ 893

82,656

119,397

13,078

6,602

105,051

170,359

Property and Equipment:

824,699

767,388

29,723

29,524

Less accumulated depreciation, depletion, amortization, and impairment

8,931,355

8,615,042

6,978,669

6,182,726

1,952,686

2,432,316

5,673

26,642

32,570

2,090,052

^[1]

2,698,053

^[1]

$ 2,581,452

84,481

151,686

46,562

47,923

3,430

17,376

14,250

260,049

213,859

663,216

644,475

2,071

95,341

101,234

VIE

5,841

21,073

33,207

7,686

1,049

28,759

40,097

Property and Equipment:

824,699

767,388

3,390

3,086

Less accumulated depreciation, depletion, amortization, and impairment

828,089

770,474

407,144

364,740

420,945

405,734

3,948

9,442

17,551

463,094

463,382

18,511

32,214

4,198

3,688

2,407

7,060

6,875

32,176

42,777

16,500

1,404

8,126

14,687

Total liabilities

$ 58,206

$ 57,464

[1]

Variable Interest Entity Arrangements (Narrative) (Details) - USD ($)		12 Months Ended
	Apr. 03, 2018	Dec. 31, 2019
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		$ 255,970
Superior Pipeline Company, L.L.C. [Member] \| SP Investor Holdings, LLC [Member]
Variable Interest Entity [Line Items]
Ownership percentage		50.00%

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	May 02, 2018	Apr. 04, 2017
Class of Stock [Line Items]
Common stock, par value	$ 0.2	$ 0.2
Common stock, shares issued	55,443,393	54,055,600
Proceeds from common stock issued, net of issue costs	$ 0	$ 0	$ 18,623
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

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Revenues:

$ 674,634

$ 843,281

$ 739,640

384,728

430,896

408,872

275,573

243,605

209,257

625,716

147,884

1,286,017

822,385

618,129

38,246

38,707

38,087

3,502

(704)

(327)

(653,131)

(17,107)

83,751

4,225

(3,184)

14,732

(37,012)

(33,494)

(38,334)

(236)

(686,154)

(53,763)

60,170

847,398

^[1]

1,350,830

^[2]

1,127,900

^[3]

708,468

806,611

933,063

459,444

461,828

438,571

2,015,310

^[4]

2,619,269

^[5]

2,499,534

^[6]

54,155

55,505

56,854

20,587

^[7]

23,279

^[8]

25,064

^[9]

2,090,052

^[10]

2,698,053

^[10]

2,581,452

374,369

488,780

332,280

Oil and Natural Gas

Revenues:

325,797

423,059

357,744

135,124

131,675

130,789

Revenues:

168,383

196,492

174,720

115,998

131,385

122,600

Revenues:

180,454

223,730

207,176

133,606

167,836

155,483

Oil and Natural Gas

Revenues:

325,797

^[11]

423,059

357,744

140,026

136,870

135,532

168,651

133,584

101,911

559,867

^[12]

^[13]

868,544

270,454

237,443

(199)

(139)

(228)

(542,548)

152,744

120,529

(481)

(543,029)

152,744

120,529

851,662

^[1]

1,357,779

^[2]

1,134,080

^[3]

851,662

^[4]

1,357,779

^[5]

1,134,080

^[6]

^[7]

^[8]

^[9]

851,662

1,357,779

1,134,080

Oil and Natural Gas | Oil and Natural Gas

268,622

367,335

270,443

Revenues:

325,797

^[11]

423,059

^[14]

357,744

Oil and Natural Gas | Contract drilling

140,026

136,870

135,532

Revenues:

^[11]

^[14]

Oil and Natural Gas | Gas gathering and processing

Revenues:

^[11]

^[14]

Revenues:

184,192

^[11]

218,982

188,172

130,188

150,834

134,432

51,552

57,508

56,370

62,809

^[12]

147,884

^[13]

244,549

356,226

190,802

3,872

(425)

776

(64,229)

(136,819)

(3,406)

(605)

(64,834)

(136,819)

(3,406)

^[1]

^[2]

^[3]

708,510

806,696

933,063

708,510

^[4]

806,696

^[5]

933,063

^[6]

^[7]

^[8]

^[9]

708,510

806,696

933,063

Drilling | Oil and Natural Gas

40,636

75,510

36,148

Revenues:

^[11]

^[14]

Drilling | Contract drilling

Revenues:

184,192

^[11]

218,982

^[14]

188,172

Drilling | Gas gathering and processing

130,188

150,834

134,432

Revenues:

^[11]

^[14]

Revenues:

227,939

^[11]

312,417

277,049

176,189

251,328

220,613

47,663

44,834

43,499

3,040

^[12]

^[13]

226,892

296,162

264,112

(160)

(110)

(25)

1,207

16,365

12,962

(1,546)

(1,214)

827

488

15,151

12,962

^[1]

^[2]

^[3]

463,699

466,851

439,369

463,699

^[4]

466,851

^[5]

439,369

^[6]

^[7]

^[8]

^[9]

463,699

466,851

439,369

Mid-Stream | Oil and Natural Gas

64,438

44,810

22,168

Revenues:

^[11]

^[14]

Mid-Stream | Contract drilling

Revenues:

^[11]

^[14]

Mid-Stream | Gas gathering and processing

Revenues:

227,939

^[11]

312,417

^[14]

277,049

176,189

251,328

220,613

Revenues:

^[11]

7,707

7,679

7,477

^[12]

^[13]

7,707

7,679

7,477

38,246

38,707

38,087

(11)

(30)

(850)

(45,942)

(46,356)

(44,714)

4,225

(3,184)

14,732

(35,466)

(32,280)

(38,334)

(77,160)

(81,798)

(68,295)

^[1]

^[2]

^[3]

^[4]

^[5]

^[6]

54,155

55,505

56,854

23,092

^[7]

25,566

^[8]

25,064

^[9]

77,247

81,071

81,918

Other Segments | Oil and Natural Gas

673

1,125

3,521

Revenues:

^[11]

^[14]

Other Segments | Contract drilling

Revenues:

^[11]

^[14]

Other Segments | Gas gathering and processing

Revenues:

^[11]

^[14]

Intersubsegment Eliminations

Revenues:

(63,294)

(111,177)

(83,325)

(61,675)

(108,136)

(81,705)

^[12]

^[13]

(61,675)

(108,136)

(81,705)

(1,619)

(3,041)

(1,620)

(1,619)

(3,041)

(1,620)

(4,264)

^[1]

(6,949)

^[2]

(6,180)

^[3]

(42)

(85)

(4,255)

(5,023)

(798)

(8,561)

^[4]

(12,057)

^[5]

(6,978)

^[6]

(2,505)

^[7]

(2,287)

^[8]

^[9]

(11,066)

(14,344)

(6,978)

Intersubsegment Eliminations | Oil and Natural Gas

Revenues:

^[11]

^[14]

Intersubsegment Eliminations | Contract drilling

(4,902)

(5,195)

(4,743)

Revenues:

(15,809)

^[11]

(22,490)

^[14]

(13,452)

Intersubsegment Eliminations | Gas gathering and processing

(14,190)

(19,449)

(11,832)

Revenues:

(47,485)

^[11]

(88,687)

^[14]

(69,873)

$ (42,583)

$ (83,492)

$ (65,130)

[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]	Other 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, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. 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 $40.1 million and $423.3 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 18 – 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 $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 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.
[14]	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.

Selected Quarterly Financial Information (Details) - USD ($)

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

$ 164,358,000

^[1]

$ 155,439,000

^[1]

$ 165,146,000

^[1]

$ 189,691,000

^[1]

$ 214,788,000

$ 220,058,000

$ 203,303,000

$ 205,132,000

$ 674,634,000

$ 843,281,000

$ 739,640,000

Gross income (loss)

^[2]

(393,983,000)

(242,308,000)

813,000

24,095,000

(108,068,000)

49,216,000

40,915,000

38,833,000

Net income (loss) attributable to Unit Corporation per common share:

$ (334,980,000)

^[3]

$ (206,886,000)

^[4]

$ (8,509,000)

$ (3,504,000)

$ (77,840,000)

^[5]

$ 18,899,000

$ 5,788,000

$ 7,865,000

$ (553,879,000)

$ (45,288,000)

$ 117,848,000

Basic

$ (6.33)

$ (3.91)

$ (0.16)

$ (0.07)

$ (1.49)

$ 0.36

$ 0.11

$ 0.15

$ (10.48)

$ (0.87)

$ 2.31

Diluted

$ (6.33)

$ (3.91)

$ (0.16)

$ (0.07)

$ (1.49)

$ 0.36

$ 0.11

$ 0.15

$ (10.48)

$ (0.87)

$ 2.28

Ceiling test wrtie-down

$ 390,100,000

$ 169,300,000

$ 559,400,000

$ 0

Non-cash ceiling test write-down net of tax

$ 294,500,000

$ 127,900,000

422,400,000

Goodwill, Impairment Loss, Net of Tax

62,800,000

$ 0

$ 59,800,000

Drilling

Net income (loss) attributable to Unit Corporation per common share:

Impairment of Drilling Equipment

$ 147,900,000

[1]	In 2019, revenues dropped significantly each quarter due to lower commodity prices, production, and drilling rig utilization.
[2]	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).
[3]	During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax).
[4]	During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax).
[5]	In the fourth quarter of 2018, we recorded an impairment for contract drilling equipment that included a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Balance Sheets) (Details) - USD ($)
$ in Thousands

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 571

$ 6,452

$ 701

$ 893

82,656

119,397

449

473

633

12,870

1,756

2,054

5,908

22,511

13,078

6,602

105,051

170,359

6,341,582

6,018,568

5,712,813

252,874

330,216

296,764

1,295,713

1,284,419

824,699

767,388

69,692

68,339

59,080

59,081

29,723

29,524

57,992

57,507

Less accumulated depreciation, depletion, amortization, and impairment

8,931,355

8,615,042

6,978,669

6,182,726

1,952,686

2,432,316

62,808

5,673

26,642

32,570

2,090,052

^[1]

2,698,053

^[1]

2,581,452

84,481

151,686

46,562

47,923

3,430

Current derivative liabilities

108,200

17,376

14,250

260,049

213,859

663,216

644,475

293

2,071

95,341

101,234

13,713

144,748

1,055,635

1,593,444

1,345,560

1,194,070

Consolidating Adjustments

^[1]

2,090,052

2,698,053

(9,447)

(14,344)

(9,447)

(14,344)

Less accumulated depreciation, depletion, amortization, and impairment

(1,048,785)

(950,871)

Goodwill

Investments

(865,252)

(1,362,526)

(54)

(1,923,538)

(2,327,741)

(7,291)

(12,603)

(2,156)

(1,741)

(6)

(9,453)

(14,344)

(1,048,785)

(950,871)

(48)

(865,252)

(1,362,526)

(1,923,538)

(2,327,741)

Parent

503

403

510

517

2,645

2,328

633

12,870

1,756

243

2,019

1,993

7,556

17,837

9,712

9,273

28,927

28,584

Less accumulated depreciation, depletion, amortization, and impairment

38,639

37,857

33,794

27,504

4,845

10,353

1,048,785

950,871

Goodwill

Investments

865,252

1,362,526

8,107

8,225

1,934,591

2,349,812

12,259

9,466

28,003

27,505

108,200

3,003

812

151,485

37,783

646,716

644,475

293

12,553

12,834

68,150

60,983

1,055,635

1,593,444

Combined Guarantor Subsidiaries

1,934,591

2,349,812

208

191

376

64,805

94,737

449

473

1,811

5,908

22,511

3,373

3,560

74,603

123,300

6,341,582

6,018,568

252,874

330,216

1,295,713

1,284,419

69,692

68,339

59,080

59,081

16,621

17,165

29,065

28,923

Less accumulated depreciation, depletion, amortization, and impairment

8,064,627

7,806,711

6,537,731

5,790,481

1,526,896

2,016,230

62,808

1,733

9,094

6,793

1,612,326

2,209,131

61,002

122,608

14,024

16,539

1,009

7,313

6,563

83,348

145,710

1,047,599

948,790

690

74,662

73,713

(54,437)

83,765

460,464

957,153

Combined Non-Guarantor Subsidiaries

1,612,326

2,209,131

5,841

$ 0

24,653

36,676

7,686

1,049

32,339

43,566

824,699

767,388

3,390

3,086

Less accumulated depreciation, depletion, amortization, and impairment

828,089

770,474

407,144

364,741

420,945

405,733

3,948

9,441

17,552

466,673

466,851

18,511

32,215

6,691

5,620

2,407

7,060

6,875

34,669

44,710

1,186

2,081

16,500

1,404

8,126

14,687

404,788

405,373

Condensed Financial Statements, Captions [Line Items]

$ 466,673

$ 466,851

[1]

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Balance Sheets Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Condensed Financial Statements, Captions [Line Items]
Accounts receivable, allowance for doubtful accounts	$ 2,332	$ 2,531
Common stock, shares issued	55,443,393	54,055,600
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	$ 1,216	$ 1,205
Common stock, shares issued	55,443,393	54,055,600
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	$ 1,116	$ 1,326
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	$ 0
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, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

$ 164,358

^[1]

$ 155,439

^[1]

$ 165,146

^[1]

$ 189,691

^[1]

$ 214,788

$ 220,058

$ 203,303

$ 205,132

$ 674,634

$ 843,281

$ 739,640

Expenses

384,728

430,896

408,872

275,573

243,605

209,257

625,716

147,884

38,246

38,707

38,087

3,502

(704)

(327)

1,327,765

860,388

655,889

(653,131)

(17,107)

83,751

(37,012)

(33,494)

(38,334)

4,225

(3,184)

14,732

(236)

(686,154)

(53,763)

60,170

Equity in net earnings from investment in subsidiaries, net of taxes

(132,326)

(13,996)

(57,678)

Less: net income attributable to non-controlling interest

(553,828)

(39,767)

117,848

5,521

Consolidating Adjustments

$ (334,980)

^[2]

$ (206,886)

^[3]

$ (8,509)

$ (3,504)

$ (77,840)

^[4]

$ 18,899

$ 5,788

$ 7,865

(553,879)

(45,288)

117,848

Condensed Financial Statements, Captions [Line Items]

(47,485)

(88,687)

(71,493)

Expenses

(47,485)

(88,687)

(69,873)

(47,485)

(88,687)

(69,873)

(1,620)

(1,620)

Equity in net earnings from investment in subsidiaries, net of taxes

508,439

(8,638)

(134,768)

Less: net income attributable to non-controlling interest

508,439

(8,638)

(136,388)

(51)

(5,521)

Condensed Financial Statements, Captions [Line Items]

508,490

(3,117)

(136,388)

Parent

Expenses

7,707

7,679

7,477

(11)

(30)

(850)

7,696

7,649

6,627

(7,696)

(7,649)

(6,627)

(35,466)

(32,280)

(37,645)

4,225

(3,184)

14,732

786

(38,151)

(43,091)

(29,519)

Equity in net earnings from investment in subsidiaries, net of taxes

7,238

(11,962)

(12,599)

(508,439)

(8,638)

134,768

Less: net income attributable to non-controlling interest

(553,828)

(39,767)

117,848

5,521

Combined Guarantor Subsidiaries

(553,879)

(45,288)

117,848

Condensed Financial Statements, Captions [Line Items]

494,180

619,551

534,084

Expenses

256,024

268,255

258,132

220,203

191,092

158,281

622,676

147,884

38,246

36,083

29,440

3,673

(564)

548

1,140,822

642,750

446,401

(646,642)

(23,199)

87,683

(1,086)

(647,728)

(23,199)

87,683

Equity in net earnings from investment in subsidiaries, net of taxes

(139,564)

(4,064)

(20,881)

Less: net income attributable to non-controlling interest

(508,164)

(19,135)

108,564

Combined Non-Guarantor Subsidiaries

(508,164)

(19,135)

108,564

Condensed Financial Statements, Captions [Line Items]

227,939

312,417

277,049

Expenses

176,189

251,328

220,613

47,663

44,834

43,499

3,040

2,624

8,647

(160)

(110)

(25)

226,732

298,676

272,734

1,207

13,741

4,315

(1,546)

(1,214)

(689)

(275)

12,527

3,626

Equity in net earnings from investment in subsidiaries, net of taxes

2,030

(24,198)

Less: net income attributable to non-controlling interest

(275)

10,497

27,824

5,521

$ (326)

$ 4,976

$ 27,824

[1]	In 2019, revenues dropped significantly each quarter due to lower commodity prices, production, and drilling rig utilization.
[2]	During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax).
[3]	During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax).
[4]	In the fourth quarter of 2018, we recorded an impairment for contract drilling equipment that included a $147.9 million pre-tax write-down for 41 drilling rigs and other drilling equipment.

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (553,828)	$ (39,767)	$ 117,848
Reclassification adjustment for write-down of securities, net of tax of ($47), $0, and $0	481	0	0
Unrealized gain (loss) on securities, net of tax of $0, ($181), and $39	0	(557)	63
Unrealized loss on securities, tax	0	(181)	39
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	(47)	0	0
Comprehensive income (loss)	(553,347)	(40,324)	117,911
Less: Comprehensive income attributable to non-controlling interest	51	5,521	0
Comprehensive income (loss) attributable to Unit Corporation	(553,398)	(45,845)	117,911
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	508,439	(8,638)	(136,388)
Reclassification adjustment for write-down of securities, net of tax of ($47), $0, and $0	0
Unrealized gain (loss) on securities, net of tax of $0, ($181), and $39		0	0
Unrealized loss on securities, tax		0	0
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	0
Comprehensive income (loss)	508,439	(8,638)	(136,388)
Less: Comprehensive income attributable to non-controlling interest	(51)	(5,521)	0
Comprehensive income (loss) attributable to Unit Corporation	508,490	(3,117)	(136,388)
Parent
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(553,828)	(39,767)	117,848
Reclassification adjustment for write-down of securities, net of tax of ($47), $0, and $0	0
Unrealized gain (loss) on securities, net of tax of $0, ($181), and $39		0	0
Unrealized loss on securities, tax		0	0
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	0
Comprehensive income (loss)	(553,828)	(39,767)	117,848
Less: Comprehensive income attributable to non-controlling interest	51	5,521	0
Comprehensive income (loss) attributable to Unit Corporation	(553,879)	(45,288)	117,848
Combined Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(508,164)	(19,135)	108,564
Reclassification adjustment for write-down of securities, net of tax of ($47), $0, and $0	481
Unrealized gain (loss) on securities, net of tax of $0, ($181), and $39		(557)	63
Unrealized loss on securities, tax		(181)	39
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	(47)
Comprehensive income (loss)	(507,683)	(19,692)	108,627
Less: Comprehensive income attributable to non-controlling interest	0	0	0
Comprehensive income (loss) attributable to Unit Corporation	(507,683)	(19,692)	108,627
Combined Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(275)	10,497	27,824
Reclassification adjustment for write-down of securities, net of tax of ($47), $0, and $0	0
Unrealized gain (loss) on securities, net of tax of $0, ($181), and $39		0	0
Unrealized loss on securities, tax		0	0
Reclassification Adjustment from AOCI for Write-down of Securities, Tax	0
Comprehensive income (loss)	(275)	10,497	27,824
Less: Comprehensive income attributable to non-controlling interest	51	5,521	0
Comprehensive income (loss) attributable to Unit Corporation	$ (326)	$ 4,976	$ 27,824

Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Cash Flow) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$ 269,396	$ 352,747	$ 270,088
INVESTING ACTIVITIES:
Capital expeditures	(406,665)	(446,282)	(255,553)
Producing property and other oil and natural gas acquisitions	(3,653)	(29,970)	(58,026)
Payments to Acquire Other Property, Plant, and Equipment	(16,109)	0	0
Proceeds from disposition of property and equipment	31,864	25,910	21,713
Other	0	0	(1,500)
Net cash provided by (used in) investing activities	(394,563)	(450,342)	(293,366)
FINANCING ACTIVITIES:
Borrowings under line of credit	493,500	99,100	343,900
Payments under line of credit	(368,800)	(277,100)	(326,700)
Intercompany borrowings (advances), net	0	0	0
Payments on finance leases	(4,001)	(3,843)	(3,694)
Payments Related to Tax Withholding for Share-based Compensation	(4,158)	(4,988)	(4,132)
Payments to Noncontrolling Interests	(918)	0	0
Proceeds from common stock issued, net of issue costs	0	0	18,623
Proceeds from investments of non-contolling interests	0	300,000	0
Transaction costs associated with sale of non-controlling interest	0	(2,503)	0
Bank overdrafts	3,663	(7,320)	(4,911)
Net cash provided by (used in) financing activities	119,286	103,346	23,086
Net increase (decrease) in cash and cash equivalents	(5,881)	5,751	(192)
Cash and cash equivalents, beginning of year	6,452	701	893
Cash and cash equivalents, end of year	571	6,452	701
Consolidating Adjustments
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	12,338	325,914	0
INVESTING ACTIVITIES:
Capital expeditures	0	0	0
Producing property and other oil and natural gas acquisitions	0	0	0
Payments to Acquire Other Property, Plant, and Equipment	0
Proceeds from disposition of property and equipment	0	0	0
Other			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	(12,338)	(128,080)	0
Payments on finance leases	0	0	0
Payments Related to Tax Withholding for Share-based Compensation	0	0	0
Payments to Noncontrolling Interests	0
Proceeds from common stock issued, net of issue costs			0
Proceeds from investments of non-contolling interests		(197,042)
Transaction costs associated with sale of non-controlling interest		0
Bank overdrafts	0	0	0
Net cash provided by (used in) financing activities	(12,338)	(325,914)	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	(9,681)	(310,120)	3,458
INVESTING ACTIVITIES:
Capital expeditures	65	236	(3,594)
Producing property and other oil and natural gas acquisitions	0	0	0
Payments to Acquire Other Property, Plant, and Equipment	0
Proceeds from disposition of property and equipment	11	30	964
Other			0
Net cash provided by (used in) investing activities	76	266	(2,630)
FINANCING ACTIVITIES:
Borrowings under line of credit	400,600	97,100	343,900
Payments under line of credit	(292,400)	(275,100)	(326,700)
Intercompany borrowings (advances), net	(97,455)	202,558	(27,615)
Payments on finance leases	0	0	0
Payments Related to Tax Withholding for Share-based Compensation	(4,158)	(4,988)	(4,132)
Payments to Noncontrolling Interests	919
Proceeds from common stock issued, net of issue costs			18,623
Proceeds from investments of non-contolling interests		300,000
Transaction costs associated with sale of non-controlling interest		(2,503)
Bank overdrafts	2,199	(7,320)	(4,911)
Net cash provided by (used in) financing activities	9,705	309,747	(835)
Net increase (decrease) in cash and cash equivalents	100	(107)	(7)
Cash and cash equivalents, beginning of year	403	510	517
Cash and cash equivalents, end of year	503	403	510
Combined Guarantor Subsidiaries
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	217,883	324,696	223,437
INVESTING ACTIVITIES:
Capital expeditures	(355,258)	(400,990)	(233,254)
Producing property and other oil and natural gas acquisitions	(3,653)	(29,970)	(58,026)
Payments to Acquire Other Property, Plant, and Equipment	0
Proceeds from disposition of property and equipment	31,153	25,777	20,674
Other			(1,500)
Net cash provided by (used in) investing activities	(327,758)	(405,183)	(272,106)
FINANCING ACTIVITIES:
Borrowings under line of credit	0	0	0
Payments under line of credit	0	0	0
Intercompany borrowings (advances), net	109,735	80,504	48,484
Payments on finance leases	0	0	0
Payments Related to Tax Withholding for Share-based Compensation	0	0	0
Payments to Noncontrolling Interests	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
Bank overdrafts	0	0	0
Net cash provided by (used in) financing activities	109,735	80,504	48,484
Net increase (decrease) in cash and cash equivalents	(140)	17	(185)
Cash and cash equivalents, beginning of year	208	191	376
Cash and cash equivalents, end of year	68	208	191
Combined Non-Guarantor Subsidiaries
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	48,856	12,257	43,193
INVESTING ACTIVITIES:
Capital expeditures	(51,472)	(45,528)	(18,705)
Producing property and other oil and natural gas acquisitions	0	0	0
Payments to Acquire Other Property, Plant, and Equipment	(16,109)
Proceeds from disposition of property and equipment	700	103	75
Other			0
Net cash provided by (used in) investing activities	(66,881)	(45,425)	(18,630)
FINANCING ACTIVITIES:
Borrowings under line of credit	92,900	2,000	0
Payments under line of credit	(76,400)	(2,000)	0
Intercompany borrowings (advances), net	58	(154,982)	(20,869)
Payments on finance leases	(4,001)	(3,843)	(3,694)
Payments Related to Tax Withholding for Share-based Compensation	0	0	0
Payments to Noncontrolling Interests	(1,837)
Proceeds from common stock issued, net of issue costs			0
Proceeds from investments of non-contolling interests		197,042
Transaction costs associated with sale of non-controlling interest		0
Bank overdrafts	1,464	0	0
Net cash provided by (used in) financing activities	12,184	39,009	(24,563)
Net increase (decrease) in cash and cash equivalents	(5,841)	5,841	0
Cash and cash equivalents, beginning of year	5,841	0	0
Cash and cash equivalents, end of year	$ 0	$ 5,841	$ 0

Subsequent Events (Details) - Subsequent Event	Mar. 11, 2020
Subsequent Event [Line Items]
Subsequent Event, Description	On March 11, 2020, we entered into a Standstill and Amendment Agreement (Standstill Agreement) with the lenders and administrative agent party to the Unit credit agreement. The Standstill Agreement, among other things, provides that during the standstill period (as defined below), the administrative agent and lenders under the Unit credit agreement agree to temporarily standstill from making any final determination in connection with the pending scheduled redetermination of the borrowing base that was, under the Unit credit agreement, otherwise scheduled to be made on or about April 1, 2020, and from otherwise exercising certain of their respective rights and remedies under the Unit credit agreement. The standstill period will begin after the effective date of the Standstill Agreement and will continue until the earlier of: (i) the receipt by any credit party from the administrative agent of notice of the occurrence of any termination event and (ii) 3:00 p.m. central time on April 15, 2020. “Termination event” is defined under the Standstill Agreement to include the occurrence of any one or more of the following: (i) any representation or warranty made or deemed to have been made by any credit party under the Standstill Agreement being false, misleading or erroneous in any material respect when made or deemed to have been made, (ii) any credit party failing to perform, observe or comply with any covenant, agreement or term contained in the Standstill Agreement in any material respect or (iii) any default which is not cured within five (5) business days or event of default occurring under the Unit credit agreement. Under the Standstill Agreement, we are prevented from withdrawing more than an additional $15.0 million, in the aggregate, net of repayments, and we have agreed to make repayments using any excess cash, among certain other conditions.
Subsequent Event, Date	Mar. 11, 2020

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Capitalized costs:
Proved properties	$ 6,341,582	$ 6,018,568	$ 5,712,813
Unproved properties not being amortized	252,874	330,216	296,764
Capitalized costs gross	6,594,456	6,348,784	6,009,577
Accumulated depreciation, depletion, amortization, and impairment	(5,846,177)	(5,124,257)	(4,996,696)
Net capitalized costs	748,279	1,224,527	1,012,881
Costs incurred:
Unproved properties acquired	34,668	57,430	47,029
Proved properties acquired	3,653	15,158	47,638
Exploration	16,480	15,907	14,811
Development	211,443	280,692	160,941
Asset retirement obligation	76	(7,629)	(3,613)
Total costs incurred	$ 266,320	$ 361,558	$ 266,806

Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Unproved properties acquired and wells in progress	$ 252,874	$ 330,216	$ 296,764
2019
Unproved properties acquired and wells in progress	22,621
2018
Unproved properties acquired and wells in progress	54,780
2017
Unproved properties acquired and wells in progress	47,646
2016 and prior
Unproved properties acquired and wells in progress	$ 127,827

Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Oil and Gas Disclosures [Abstract]
Revenues	$ 314,925	$ 411,601	$ 347,285
Production costs	(116,051)	(113,810)	(107,332)
Depreciation, depletion, amortization, and impairment	(727,529)	(132,923)	(96,392)
Results of operations, income before income taxes	(528,655)	164,868	143,561
Income tax (expense) benefit	101,952	(42,915)	(56,376)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$ (426,703)	$ 121,953	$ 87,185

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, 2019

MBoe

bbl

Mcf

Dec. 31, 2018

MBoe

bbl

Mcf

Dec. 31, 2017

MBoe

bbl

Mcf

Beginning of year (MBoe) | MBoe

159,681

149,774

117,774

Revision of previous estimate (MBoe) | MBoe

(68,366)

^[1]

(4,165)

^[2]

11,444

Extension and discovery (MBoe) | MBoe

3,015

^[1]

21,033

14,975

Infill reserves in existing proved fields (MBoe) | MBoe

1,506

8,656

16,123

Purchase of mineral in place (MBoe) | MBoe

503

2,707

5,768

Production (MBoe) | MBoe

(16,825)

(17,070)

(15,996)

Sales (MBoe) | MBoe

(7,590)

(1,254)

(314)

End of year (MBoe) | MBoe

71,924

159,681

149,774

Beginning of year (MBoe) | MBoe

111,576

112,961

99,079

End of year (MBoe) | MBoe

71,924

111,576

112,961

Beginning of year (MBoe) | MBoe

48,105

36,813

18,695

End of year (MBoe) | MBoe

48,105

36,813

Oil (bbls)

Revision of previous estimates

22,558

19,513

15,696

(8,263)

^[1]

180

^[2]

730

Extensions and discoveries

703

^[1]

3,250

2,235

Infill reserves in existing proved fields

271

1,898

1,632

Purchases of minerals in place

183

701

2,019

Production

(3,208)

(2,874)

(2,715)

Sales

(48)

(110)

(84)

12,196

22,558

19,513

15,192

14,862

12,724

12,196

15,192

14,862

7,366

4,651

2,972

Natural Gas Liquids (bbls)

7,366

4,651

Revision of previous estimates

47,796

45,486

34,482

(20,961)

^[1]

(1,368)

^[2]

4,325

Extensions and discoveries

845

^[1]

5,149

4,520

Infill reserves in existing proved fields

434

2,795

5,779

Purchases of minerals in place

101

856

1,197

Production

(4,773)

(4,925)

(4,737)

Sales

(412)

(197)

(80)

23,030

47,796

45,486

33,515

33,358

28,502

23,030

33,515

33,358

14,281

12,128

5,980

14,281

12,128

Natural gas (Mcf)

Revision of previous estimates | Mcf

Beginning of year | Mcf

535,963

508,650

405,579

(234,852)

^[1]

(17,859)

^[2]

38,330

Extensions and discoveries | Mcf

8,798

^[1]

75,806

49,321

Infill reserves in existing proved fields | Mcf

4,806

23,778

52,270

Purchases of minerals in place | Mcf

1,316

6,897

15,313

Production | Mcf

(53,064)

(55,627)

(51,260)

Sales | Mcf

(42,780)

(5,682)

(903)

End of year | Mcf

220,187

535,963

508,650

Beginning of year | Mcf

377,216

388,446

347,121

End of year | Mcf

220,187

377,216

388,446