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Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 13, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	0000798949
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,061,832
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 958,140,471
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 701	$ 893
Accounts receivable (less allowance for doubtful accounts of $2,450 and $3,773 at December 31, 2017 and 2016, respectively)	111,512	83,954
Materials and supplies	505	3,340
Current derivative asset (Note 12)	721	0
Current deferred tax asset (Note 8)	0	25,211
Prepaid expenses and other	6,233	7,798
Total current assets	119,672	121,196
Oil and natural gas properties, on the full cost method:
Proved properties	5,712,813	5,446,305
Unproved properties not being amortized	296,764	314,867
Drilling equipment	1,593,611	1,565,268
Gas gathering and processing equipment	726,236	705,859
Saltwater disposal systems	62,618	60,638
Corporate land and building	59,080	59,066
Transportation equipment	29,631	32,842
Other	53,439	48,590
Property, plant and equipment, gross, total	8,534,192	8,233,435
Less accumulated depreciation, depletion, amortization, and impairment	6,151,450	5,952,330
Net property and equipment	2,382,742	2,281,105
Goodwill (Note 2)	62,808	62,808
Non-current derivative asset (Note 12)	0	377
Other assets	16,230	13,817
Total assets	2,581,452	2,479,303
Current liabilities:
Accounts payable	112,648	88,793
Accrued liabilities (Note 5)	48,523	39,651
Current derivative liabilities (Note 12)	7,763	21,564
Current portion of other long-term liabilities (Note 6)	13,002	14,907
Total current liabilities	181,936	164,915
Long-term debt less unamortized discount and debt issuance costs (Note 6)	820,276	800,917
Non-current derivative liabilities (Note 12)	0	415
Other long-term liabilities (Note 6)	100,203	103,064
Deferred income taxes (Note 8)	133,477	215,922
Commitments and contingencies (Note 14)	0	0
Shareholders' equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued	0	0
Common stock, $0.20 par value, 175,000,000 shares authorized, 52,880,134 and 51,494,318 shares issued as of December 31, 2017 and 2016, respectively	10,280	10,016
Capital in excess of par value	535,815	502,500
Accumulated other comprehensive income (net of tax of $39 at December 31, 2017) (Note 15)	63	0
Retained earnings	799,402	681,554
Total shareholders' equity	1,345,560	1,194,070
Total liabilities and shareholders' equity	$ 2,581,452	$ 2,479,303

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 2,450	$ 3,773
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	52,880,134	51,494,318
Other comprehensive income, tax	$ 39	$ 0

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Oil and natural gas	$ 357,744	$ 294,221	$ 385,774
Contract drilling	174,720	122,086	265,668
Gas gathering and processing	207,176	185,870	202,789
Total revenues	739,640	602,177	854,231
Operating costs:
Oil and natural gas	130,789	120,184	166,046
Contract drilling	122,600	88,154	156,408
Gas gathering and processing	155,483	137,609	161,556
Total operating costs	408,872	345,947	484,010
Depreciation, depletion, and amortization	209,257	208,353	352,742
Impairments	0	161,563	1,634,628
General and administrative	38,087	33,337	34,358
(Gain) loss on disposition of assets	(327)	(2,540)	7,229
Total expenses	655,889	746,660	2,512,967
Income (loss) from operations	83,751	(144,483)	(1,658,736)
Other income (expense):
Interest, net	(38,334)	(39,829)	(31,963)
Gain (loss) on derivatives	14,732	(22,813)	26,345
Other	21	307	45
Total other income (expense)	(23,581)	(62,335)	(5,573)
Income (loss) before income taxes	60,170	(206,818)	(1,664,309)
Income tax expense (benefit):
Current	5	15	(20,616)
Deferred	(57,683)	(71,209)	(606,332)
Total income taxes	(57,678)	(71,194)	(626,948)
Net income (loss)	$ 117,848	$ (135,624)	$ (1,037,361)
Net income (loss) per common share:
Basic	$ 2.31	$ (2.71)	$ (21.12)
Diluted	$ 2.28	$ (2.71)	$ (21.12)

Consolidated Statements of Comprehensive Income Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 89,155	$ 3,705	$ 9,059	$ 15,929	$ 1,683	$ (24,022)	$ (72,136)	$ (41,149)	$ 117,848	$ (135,624)	$ (1,037,361)
Other comprehensive income, net of taxes:
Unrealized appreciation on securities, net of tax of $39, $0, and $0									63	0	0
Comprehensive income (loss)									117,911	(135,624)	(1,037,361)
Other comprehensive income, tax									$ 39	$ 0	$ 0

Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Capital In Excess of Par Value	Accumulated Other Comprehensive Income	Retained Earnings
Beginning balances at Dec. 31, 2014	$ 2,332,394	$ 9,732	$ 468,123	$ 0	$ 1,854,539
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,037,361)	0	0	0	(1,037,361)
Other comprehensive income	0
Total comprehensive income	(1,037,361)
Activity in employee compensation plans	18,547	99	18,448	0	0
Ending balances at Dec. 31, 2015	1,313,580	9,831	486,571	0	817,178
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(135,624)	0	0	0	(135,624)
Other comprehensive income	0
Total comprehensive income	(135,624)
Activity in employee compensation plans	16,114	185	15,929	0	0
Ending balances at Dec. 31, 2016	1,194,070	10,016	502,500	0	681,554
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	117,848	0	0	0	117,848
Other comprehensive income	63	0	0	63	0
Total comprehensive income	117,911
Proceeds from sale of stock	18,623	158	18,465	0	0
Activity in employee compensation plans	14,956	106	14,850	0	0
Ending balances at Dec. 31, 2017	$ 1,345,560	$ 10,280	$ 535,815	$ 63	$ 799,402

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock Issued During Period, Shares, New Issues	787,547	0	0
Activity in employee compensation plans (shares)	598,269	1,081,217	819,289
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$ 39	$ 0	$ 0
Other comprehensive income	$ 63	$ 0	$ 0

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES:
Net income (loss)	$ 117,848	$ (135,624)	$ (1,037,361)
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	209,257	208,353	352,742
Impairments (Note 2)	0	161,563	1,634,628
Amortization of debt issuance costs and debt discount	2,159	2,122	2,088
(Gain) loss on derivatives	(14,732)	22,813	(26,345)
Cash receipts on derivatives settled	173	9,658	46,615
(Gain) loss on disposition of assets	(327)	(3,127)	7,229
Deferred tax benefit	(57,683)	(71,209)	(606,332)
Employee stock compensation plans	17,747	13,812	21,468
Bad debt expense	348	785	1,191
ARO liability accretion	2,886	2,779	3,453
Other, net	(865)	(6,037)	(1,517)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(32,073)	(11,796)	105,426
Materials and supplies	2,835	225	1,507
Prepaid expenses and other	1,527	2,585	7,134
Accounts payable	21,824	27,400	(20,306)
Accrued liabilities	6,996	(4,388)	(22,920)
Income taxes	38	20,903	(21,482)
Contract advances	1,630	(687)	(274)
Net cash provided by operating activities	279,588	240,130	446,944
INVESTING ACTIVITIES:
Capital expeditures	(269,185)	(186,149)	(561,453)
Producing property and other acquisitions	(58,026)	(564)	(179)
Proceeds from disposition of property and equipment	21,713	74,823	11,854
Other	(1,500)	919	0
Net cash used in investing activities	(306,998)	(110,971)	(549,778)
FINANCING ACTIVITIES:
Borrowings under line of credit	343,900	251,398	618,500
Payments under line of credit	(326,700)	(371,600)	(503,500)
Payments on capitalized leases	(3,694)	(3,694)	(3,549)
Proceeds from common stock issued, net of issue costs (Note 15)	18,623	0	0
Tax expense from stock compensation	0	(376)	(3,207)
Decrease in book overdrafts (Note 2)	(4,911)	(4,829)	(5,624)
Net cash provided by (used in) financing activities	27,218	(129,101)	102,620
Net increase (decrease) in cash and cash equivalents	(192)	58	(214)
Cash and cash equivalents, beginning of year	893	835	1,049
Cash and cash equivalents, end of year	701	893	835
Supplemental disclosure of cash flow information:
Interest paid (net of capitalization)	33,931	35,690	30,910
Income taxes	0	42	3,540
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(6,942)	21,190	105,157
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	$ 3,613	$ 30,897	$ 5,694

Organization	12 Months Ended
Organization	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	ORGANIZATION Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like terms refer to Unit Corporation and its subsidiaries. We are primarily engaged in the exploration, development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are principally in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream. Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company, we explore, develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, Montana, New Mexico, North Dakota, Utah, and Wyoming. Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, we drill onshore oil and natural gas wells for our own account and for a wide range of other oil and natural gas companies. Our drilling operations are mainly in Oklahoma, Texas, Wyoming, North Dakota, and to a lesser extent in Louisiana and Kansas. Mid-Stream. Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements.

Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity.

Accounting Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Drilling Contracts. We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2017, all of our contracts were daywork contracts of which nine were multi-well and had durations which ranged from six months to two years, eight of which expire in 2018 and one expiring in 2019. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.

Cash Equivalents and Book Overdrafts. We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2017 and 2016, book overdrafts were $12.4 million and $17.3 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:



	2017		2016		2015
Oil and Natural Gas:
Sunoco Logistics Partners L.P.	10	%	24	%	19	%
Valero Energy Corporation	9	%	11	%	15	%
Drilling:
QEP Resources, Inc.	26	%	28	%	25	%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	7	%	18	%	7	%
Mid-Stream:
ONEOK, Inc.	36	%	30	%	29	%
Range Resources Corporation	9	%	10	%	5	%
Koch Energy Services, LLC	8	%	11	%	9	%
Tenaska Resources, LLC	6	%	10	%	18	%
Laclede Group, Inc.	1	%	9	%	12	%

We had a concentration of cash of $11.4 million and $8.3 million at December 31, 2017 and 2016, 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, 2017 and determined there was no material risk at that time. At December 31, 2017, 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, 2017
	(In millions)
Canadian Imperial Bank of Commerce	$	0.7
Bank of America Merrill Lynch	(2.5		)
Bank of Montreal	(5.3		)
Total assets (liabilities)	$	(7.1	)

Property and Equipment. Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.

We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. The use of different estimates and assumptions could cause materially different carrying values of our assets.

On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. Our contract drilling segment had no impairments in either 2016 or 2017. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.

In 2015, our mid-stream segment incurred a $27.0 million, pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. Our mid-stream segment had no impairments in either 2016 or 2017.

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 2017, 2016, and 2015, interest of approximately $15.9 million, $15.3 million, and $21.7 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2017, 2016, or 2015. There were no additions to goodwill in 2017, 2016, or 2015. Based on our impairment test performed as of December 31, 2017, the fair value of our drilling segment exceeded its carrying value by 41%. Goodwill of $0.7 million is deductible for tax purposes.

Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $14.8 million, $15.4 million, and $19.2 million were capitalized in 2017, 2016, and 2015, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $6.00, $6.24, and $12.30 per Boe in 2017, 2016, and 2015, 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 $296.8 million are excluded from the DD&A calculation.

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

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

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

We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $114.4 million, $7.6 million, and $10.5 million in 2015, 2016, and 2017, respectively of costs being added to the total of our capitalized costs being amortized. In 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion net of tax) primarily due to the reduction of the 12-month average commodity prices during the year. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million net of tax) due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We had no non-cash ceiling test write-downs during 2017.

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 $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.

ARO. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.

Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms.

Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.

Derivative Activities. All derivatives are recognized on the balance sheet and measured at fair value with the exception of normal purchase and normal sales which are expected to result in physical delivery. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.

We document our risk management strategy and do not engage in derivative transactions for speculative purposes.

Limited Partnerships. Unit Petroleum Company is a general partner in 13 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.

Income Taxes. During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. The change in tax law required the Company to remeasure existing net deferred tax liabilities using the lower rate in the period of enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.

The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2017 balancing position to be approximately 3.7 Bcf on under-produced properties and approximately 3.8 Bcf on over-produced properties. We have recorded a receivable of $2.4 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.3 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.

Employee and Director Stock Based Compensation. We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants is based on the closing stock price on the date of the grants.

New Accounting Standards

Compensation—Stock Compensation. The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms of a share-based payment award. The amendment is effective for reporting periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendment should help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendment is effective for annual periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. This amendment will not have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are evaluating the impact this amendment will have on our financial statements and currently evaluating a plan for implementation.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This standard affects any entity using U.S. GAAP that either contracts with customers to transfer goods or services or enters into contracts for transferring nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which is codified in the new Topic 606, effective January 1, 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We adopted this standard January 1, 2018 using the modified retrospective approach, which resulted in a cumulative effect adjustment upon adoption for our mid-stream segment. This adjustment related to the timing of revenue on certain demand fees which was not material to the company. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment.

The application of Topic 606 will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but additional footnote disclosures are required with respect to revenue. In our oil and natural gas segment, the classification of certain costs as either a deduction from revenue or an expense will be determined based on when control of the commodity transfers to the customer, which would impact total revenue recognized, but will not affect gross profit.

Part of our review included evaluation of these issues:

•

Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees collectible during a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.

•

Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires these arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue when it is not expected to be subject to a significant reversal.

Our internal control framework did not materially change, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.

Adopted Standards

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations must classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment requires current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendment should improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment primarily affects classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2017

Acquisitions and Divestitures [Abstract]

Acquisitions and Divestitures

ACQUISITIONS AND DIVESTITURES

Acquisitions

On April 3, 2017, we closed on an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million.

As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction.

We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed.



Final Adjusted Purchase Price
Total consideration given	$	54,332

Final Adjusted Allocation of Purchase Price
Oil and natural gas properties included in the full cost pool:
Proved oil and natural gas properties	$	43,745
Undeveloped oil and natural gas properties	8,650
Total oil and natural gas properties included in the full cost pool ⁽¹⁾	52,395
Gas gathering equipment and other	2,340
Asset retirement obligation	(403		)
Fair value of net assets acquired	$	54,332


(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 2017, we had approximately $4.7 million in other acquisitions.

Divestitures

Oil and Natural Gas

We had non-core asset sales with proceeds, net of related expenses, of $18.6 million, $67.2 million, and $1.9 million, in 2017, 2016, and 2015, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.

Contract Drilling

During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax.

During December 2016, we sold one idle 1500 HP SCR drilling rig to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $1.7 million net book value of the drilling rig, resulting in a gain of $1.6 million.

We did not have any divestitures in 2017.

Earnings (Loss) Per Share

12 Months Ended

Dec. 31, 2017

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, 2015:
Basic loss per common share	$	(1,037,361	)	49,110	$	(21.12	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(1,037,361	)	49,110	$	(21.12	)
For the year ended December 31, 2016:
Basic loss per common share	$	(135,624	)	50,029	$	(2.71	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(135,624	)	50,029	$	(2.71	)
For the year ended December 31, 2017:
Basic earnings per common share	$	117,848		51,113	$	2.31
Effect of dilutive restricted stock	—			635	(0.03		)
Diluted earnings per common share	$	117,848		51,748	$	2.28

Due to the net loss for the years ended December 31, 2016 and 2015, approximately 509,000 and 186,000, respectively, weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share calculation above.

The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31:



	2017		2016		2015
Options and SARs	87,500		199,755		261,270
Average exercise price	$	51.34	$	48.79	$	50.34

Accrued Liabilities

12 Months Ended

Dec. 31, 2017

Accrued Liabilities [Abstract]

Accrued Liabilities [Text Block]

ACCRUED LIABILITIES

Accrued liabilities consisted of the following as of December 31:



	2017		2016
	(In thousands)
Employee costs	$	19,521	$	15,394
Lease operating expenses	11,819		10,075
Interest payable	6,745		6,524
Taxes	3,404		2,219
Third-party credits	2,240		2,998
Other	4,794		2,441
Total accrued liabilities	$	48,523	$	39,651

Long-Term Debt And Other Long-Term Liabilities

12 Months Ended

Dec. 31, 2017

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:



	2017			2016
	(In thousands)
Credit agreement with average interest rates of 3.4% and 2.8% at December 31, 2017 and 2016, respectively	$	178,000		$	160,800
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	$	828,000		$	810,800
Less: unamortized discount	(2,234		)	(2,804		)
Less: debt issuance costs, net	(5,490		)	(7,079		)
Total long-term debt	$	820,276		$	800,917

Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. With the new amendment, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.

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 and on our cash flows from our mid-stream segment. The October 2017 redetermination did not cause any changes. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At December 31, 2017, we had $178.0 million outstanding borrowings under our credit agreement.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes.

The credit agreement prohibits, among other things:


•	the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;


•	the incurrence of additional debt with certain limited exceptions; and


•	the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except for our lenders.

The credit agreement also requires that we have at the end of each quarter:


•	a current ratio (as defined in the credit agreement) of not less than 1 to 1.

Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:


•	a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.

Beginning with the quarter ending June 30, 2019, and for each quarter ending thereafter, the credit agreement requires:


•	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, 2017, we were in compliance with the covenants contained in the credit agreement.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees that are being amortized as debt issuance cost over the life of the Notes.

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors and the Trustee (as supplemented, the 2011 Indenture), establishing the terms and providing for 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, 2017.

Other Long-Term Liabilities

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



	2017		2016
	(In thousands)
ARO liability	$	69,444	$	70,170
Capital lease obligations	15,224		18,918
Workers’ compensation	13,340		15,163
Separation benefit plans	6,524		4,943
Deferred compensation plan	5,390		4,578
Gas balancing liability	3,283		3,789
Other	—		410
	113,205		117,971
Less current portion	13,002		14,907
Total other long-term liabilities	$	100,203	$	103,064

Estimated annual principal payments under the terms of debt and other long-term liabilities from 2018 through 2022 are $13.0 million, $45.6 million, $184.7 million, $655.9 million, and $2.1 million, respectively.

Capital Leases

During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $3.8 million is included in current portion of other long-term liabilities and the non-current portion of $11.4 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2017. These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $5.9 million and $1.2 million, respectively at December 31, 2017. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.

Future payments required under the capital leases at December 31, 2017 are as follows:



	Amount
Ending December 31,	(In thousands)
2018	$	6,168
2019	6,168
2020	6,168
2021	3,768
Total future payments	22,272
Less payments related to:
Maintenance	5,874
Interest	1,174
Present value of future minimum payments	$	15,224

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

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:



	2017			2016
	(In thousands)
ARO liability, January 1:	$	70,170		$	98,297
Accretion of discount	2,886			2,779
Liability incurred	1,948			584
Liability settled	(2,694		)	(1,215		)
Liability sold	(1,735		)	(10,882		)
Revision of estimates ⁽¹⁾	(1,131		)	(19,393		)
ARO liability, December 31:	69,444			70,170
Less current portion	1,726			2,906
Total long-term ARO liability	$	67,718		$	67,264

_________________________


(1)	Plugging liability estimates were revised in both 2017 and 2016 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, 2017

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.

Also during the fourth quarter of 2017, the SEC issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. While we were able to make reasonable estimates of the impact of the reduction in corporate rate, bonus depreciation expensing provisions, and impact of Sec 162(m) to our existing restricted stock grants, the final impact of the Tax Act may differ from these estimates, due to, among other things, changes in our interpretations and assumptions, additional guidance that may be issued by the IRS, and actions we may take.

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:



	2017			2016			2015
	(In thousands)
Income tax expense (benefit) computed by applying the statutory rate	$	21,059		$	(72,386	)	$	(582,508	)
State income tax expense (benefit), net of federal benefit	1,655			(5,687		)	(45,768		)
Deferred tax liability revaluation ⁽¹⁾	(81,307		)	—			—
Restricted stock shortfall	1,867			5,465			—
Statutory depletion and other	(952		)	1,414			1,328
Income tax benefit	$	(57,678	)	$	(71,194	)	$	(626,948	)

__________________________


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

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



	2017			2016			2015
	(In thousands)
Current taxes:
Federal	$	—		$	—		$	(20,612	)
State	5			15			(4		)
	5			15			(20,616		)
Deferred taxes:
Federal	(62,788		)	(62,923		)	(535,691		)
State	5,105			(8,286		)	(70,641		)
	(57,683		)	(71,209		)	(606,332		)
Total provision	$	(57,678	)	$	(71,194	)	$	(626,948	)

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



	2017			2016
	(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals	$	32,242		$	53,967
Net operating loss carryforward	153,746			190,603
Alternative minimum tax and research and development tax credit carryforward	5,409			5,409
	191,397			249,979
Deferred tax liability:
Depreciation, depletion, amortization, and impairment	(324,874		)	(440,690		)
Net deferred tax liability	(133,477		)	(190,711		)
Current deferred tax asset	—			25,211
Non-current—deferred tax liability	$	(133,477	)	$	(215,922	)

Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced. At December 31, 2017, we have federal net operating loss carryforwards of approximately $587.9 million which expire from 2021 to 2037.

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 2014. During 2014, we recognized a tax benefit relating to a research and development tax credit carryforward in conjunction with our BOSS drilling rig activities. Due to the nature and subjectivity surrounding the research and development credit and historical challenges by the IRS against companies who claim the credit, it was our belief that the full amount of the credit may not have been eventually allowed by the IRS once we were no longer in an AMT tax paying position. During 2017, our U.S federal tax returns for 2013, 2014, and 2015 were examined by the IRS and no additional tax was found to be due and the research and development tax credit carryforward was allowed in full. Accordingly, we no longer have any unrecognized tax benefits as of December 31, 2017.

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2017
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 155,822, 630,039, and 235,104 shares of common stock and recognized expense of $4.4 million, $4.0 million, and $6.2 million in 2017, 2016, and 2015, respectively. We provide a salary deferral plan (Deferral Plan) which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2017 and 2016 was $5.4 million and $4.6 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral. Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments, and the circumstances under which employees become eligible to receive benefits. 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 $2.7 million, $3.1 million, and $3.0 million in 2017, 2016, and 2015, 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, 2017

Transactions With Related Parties

TRANSACTIONS WITH RELATED PARTIES

Unit Petroleum Company serves as the general partner of 13 oil and gas limited partnerships (the employee partnerships) which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. Previously, there were three non-employee partnerships, one that was formed in 1984 and two formed in 1986 (investments by third parties). Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were also dissolved.

The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed. The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one percent.

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



	2017		2016		2015
	(In thousands)
Well supervision and other fees	$	172	$	254	$	423
General and administrative expense reimbursement	—		6		18

Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by management to be reasonable.

As of December 31, 2016, John Nikkel retired as director and chairman of Unit's board and is no longer considered a related party. As of 2016, Mr. Nikkel was a 25.8% owner of Rampart Holdings, Inc. which owned 100% of Toklan Oil and Gas Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son, Robert Nikkel is Toklan's President, and he owned 20.0% of the company. In 2015, there was one well drilled for Toklan with no activity in 2016. Under its usual standard dayrate contract terms available generally to all similarly-situated customers at that time and in the same general drilling area, the Company recognized revenue from Toklan of approximately $0.5 million in 2015. During 2015, we received payments of $0.9 million with no accounts receivable balance at December 31, 2015. There were no material revenues in 2016. There were no material royalties to disclose for 2015 or 2016. Also in 2015, Toklan paid $0.5 million for the North Custer Gathering System, an inactive (since 2009) gathering system owned by our mid-stream segment. We determined that the capital required to re-activate that system would not provide adequate returns based on future cash flow potential. Toklan operates the North Custer Gathering System under its affiliate, West Thomas Field Services, LLC (West Thomas), a company in which Mr. John Nikkel held an approximate 25.0% ownership interest and in which Mr. Robert Nikkel held ownership interest of approximately 20.0%. West Thomas entered into a gas purchase agreement with our exploration and production segment in November of 2015. Payments from West Thomas under that contract amounted to $0.4 million and $0.1 million for 2016 and 2015 volumes purchased, respectively. Additionally, on March 10, 2016, Mr. Nikkel purchased in the open market $0.4 million in aggregate principal amount of our outstanding 6.625% senior subordinated notes due 2021. The notes pay interest semi-annually in cash in arrears on May 15 and November 15 of each year. For 2016, interest payments for May and November were approximately $4,800 and $13,250, respectively.

One of our directors, G. Bailey Peyton IV, also serves as Manager of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. The Company in the ordinary course of business, paid royalties or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.7 million, $0.5 million, and $0.8 million during 2017, 2016, and 2015, 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, 2017

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

Stock-Based Compensation

STOCK-BASED COMPENSATION

For restricted stock awards, we had:



	2017		2016		2015
	(In millions)
Recognized stock compensation expense	$	13.3	$	9.6	$	15.3
Capitalized stock compensation cost for our oil and natural gas properties	1.8		2.1		3.5
Tax benefit on stock based compensation	5.0		3.6		5.8

The remaining unrecognized compensation cost related to unvested awards at December 31, 2017 is approximately $12.8 million of which $1.3 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

Activity pertaining to SARs granted under the amended plan is as follows:



	Number of Shares		Weighted Average Price
Outstanding at January 1, 2015	131,770		$	46.60
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2015	131,770		46.60
Granted	—		—
Exercised	—		—
Forfeited	(40,515	)	51.76
Outstanding at December 31, 2016	91,255		44.31
Granted	—		—
Exercised	—		—
Forfeited	(91,255	)	44.31
Outstanding at December 31, 2017	—		$	—

There were no SARs granted or vested during 2017, 2016, or 2015. There were no SARs exercised in 2017. The SARs expired after 10 years from the date of the grant, and there were no outstanding shares at December 31, 2017.

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, 2015	724,766		175,520		900,286		$	50.81
Granted	576,361		148,081		724,442		34.06
Vested	(343,657	)	(39,245	)	(382,902	)	49.69
Forfeited	(20,808	)	(7,196	)	(28,004	)	45.33
Nonvested at December 31, 2015	936,662		277,160		1,213,822		41.29
Granted	494,078		152,373		646,451		5.62
Vested	(425,195	)	—		(425,195	)	43.47
Forfeited	(75,808	)	(57,405	)	(133,213	)	36.87
Nonvested at December 31, 2016	929,737		372,128		1,301,865		23.32
Granted	485,799		173,373		659,172		26.07
Vested	(455,570	)	(62,119	)	(517,689	)	29.87
Forfeited	(44,408	)	(34,953	)	(79,361	)	38.87
Nonvested at December 31, 2017	915,558		448,429		1,363,987		$	21.25



Non-Employee Directors	Number of Shares		Weighted Average Price
Nonvested at January 1, 2015	35,136		$	50.08
Granted	25,848		34.04
Vested	(18,920	)	46.51
Forfeited	—		—
Nonvested at December 31, 2015	42,064		$	41.83
Granted	90,000		12.02
Vested	(20,248	)	43.46
Forfeited	—		—
Nonvested at December 31, 2016	111,816		$	17.21
Granted	49,104		17.92
Vested	(43,206	)	21.24
Forfeited	—		—
Nonvested at December 31, 2017	117,714		$	16.03

The time vested restricted stock awards granted are being recognized over a three year vesting period. During 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at December 31, 2017, the participants are estimated to receive 82% of the 2017, 159% of the 2016, and 100% of the 2015 performance based shares. The CFTA performance measurement at December 31, 2017 for the one-third vesting in 2018 was assessed to vest at 131%. The CFTA performance measurement for future years was assessed to vest at target or 100%.

The fair value of the restricted stock granted in 2017, 2016, and 2015 at the grant date was $17.4 million, $4.5 million, and $24.5 million, respectively. The aggregate intrinsic value of the 560,895 shares of restricted stock that vested in 2017 on their vesting date was $12.3 million. The aggregate intrinsic value of the 1,481,701 shares of restricted stock outstanding subject to vesting at December 31, 2017 was $32.6 million with a weighted average remaining life of 0.9 of a year.

Employee Stock Option Plan

The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In 2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further awards were made under this plan. During 2015, the remaining options expired.

Activity pertaining to the Stock Option Plan is as follows:



	Number of Shares		Weighted Average Exercise Price
Outstanding at January 1, 2015	9,500		$	37.69
Granted	—		—
Exercised	—		—
Forfeited	(9,500	)	37.69
Outstanding at December 31, 2015	—		—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2016	—		—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2017	—		$	—

As of December 31, 2015, there were no further options outstanding or exercisable in this plan.

Non-Employee Directors' Stock Option Plan

Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The option price for each stock option was the fair market value of the common stock on the date the stock options were granted. The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six months of its term except in case of death. On May 2, 2012, our stockholders approved the amended plan which succeeds this plan, the remaining available shares were transferred over to the new plan and no further awards were made under the non-employee director option plan.

Activity pertaining to the Directors’ Plan is as follows:



	Number of Shares		Weighted Average Exercise Price
Outstanding at January 1, 2015	150,500		$	54.18
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	54.35
Outstanding at December 31, 2015	129,500		54.15
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	62.40
Outstanding at December 31, 2016	108,500		52.56
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	57.63
Outstanding at December 31, 2017	87,500		$	51.34

There were no options exercised in 2017.



	Outstanding and Exercisable Options at December 31, 2017
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$31.30 - $41.21	38,500	1.9 years	$	37.58
$53.81 - $73.26	49,000	2.1 years	$	62.15

There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2017. The remaining weighted average remaining contractual term is 2.0 years.

Derivatives

12 Months Ended

Dec. 31, 2017

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, 2017, our derivative transactions consisted of the following types of hedges:


•	Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.


•	Basis Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis swaps to hedge the price risk between NYMEX and its physical delivery points.


•	Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

•

Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put) and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price.

We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative purposes. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.

At December 31, 2017, the following non-designated hedges were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Jan’18 – Dec’18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
Apr'18 – Oct'18	Natural gas – swap	10,000 MMBtu/day	$2.990	IF – NYMEX (HH)
Jan’18 – Mar'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan’18 – Mar'18	Natural gas – three-way collar	60,000 MMBtu/day	$3.29 - $2.63 - $4.07	IF – NYMEX (HH)
Apr’18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
Jan’18 – Dec'18	Crude oil – swap	3,000 Bbl/day	$51.36	WTI – NYMEX
Jan’18 – Mar'18	Crude oil – collar	500 Bbl/day	$55.00 - $59.50	WTI – NYMEX
Jan’18 – Dec'18	Crude oil – three-way collar	2,000 Bbl/day	$47.50 - $37.50 - $56.08	WTI – NYMEX
Apr’18 – Sep'18	Liquids (Propane) – swap	1,000 Bbl/day	$31.16	MONT BELVIEU

After December 31, 2017, the following non-designated hedges were entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Apr’18 – Sep'18	Natural gas – swap	10,000 MMBtu/day	$2.925	IF – NYMEX (HH)
Apr’18 – Sep'18	Natural gas – collar	30,000 MMBtu/day	$2.67 - $2.97	IF – NYMEX (HH)
Feb’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Feb’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.568)	NGPL MIDCON
Apr’18 – Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.190)	NGPL TEXOK
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.728)	PEPL
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.625)	NGPL MIDCON
Jan'19 – Dec'19	Natural gas – basis swap	20,000 MMBtu/day	$(0.273)	NGPL TEXOK
Jan'20 – Dec'20	Natural gas – basis swap	20,000 MMBtu/day	$(0.280)	NGPL TEXOK
Apr'18 – Dec'18	Crude oil – swap	1,000 Bbl/day	$60.00	WTI – NYMEX
Apr’18 – Sep'18	Liquids – swap	500 Bbl/day	$34.10	MONT BELVIEU

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	2017		2016
		(In thousands)
Commodity derivatives:
Current	Current derivative assets	$	721	$	—
Long-term	Non-current derivative assets	—		377
Total derivative assets		$	721	$	377



		Derivative Liabilities Fair Value
	Balance Sheet Location	2017		2016
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	7,763	$	21,564
Long-term	Non-current derivative liabilities	—		415
Total derivative liabilities		$	7,763	$	21,979

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
Derivatives Instruments		2017		2016
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	14,732	$	(22,813	)
Total		$	14,732	$	(22,813	)

_________________________


(1)	Amount settled during the period are gains of $173 and $9,658, respectively.

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:



	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	(In thousands)
Equity Securities:
December 31, 2017	$	830	$	102	$	—	$	932
December 31, 2016	$	—	$	—	$	—	$	—

During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. These securities would be classified as Level 2.

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:


•	Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.


•	Level 2—significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.


•	Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal data.

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.

The following tables set forth our recurring fair value measurements:



	December 31, 2017
	Level 2			Level 3			Effect of Netting			Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	2,137		$	3,344		$	(4,760	)	$	721
Liabilities	(8,973		)	(3,550		)	4,760			(7,763		)
	$	(6,836	)	$	(206	)	$	—		$	(7,042	)



	December 31, 2016
	Level 2			Level 3			Effect of Netting			Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	878		$	43		$	(544	)	$	377
Liabilities	(15,358		)	(7,165		)	544			(21,979		)
	$	(14,480	)	$	(7,122	)	$	—		$	(21,602	)

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, 2017.

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, 2017			December 31, 2016
	(In thousands)
Beginning of period	$	(7,122	)	$	9,094
Total gains or losses:
Included in earnings⁽¹⁾	7,791			(9,042		)
Settlements	(875		)	(7,174		)
End of period	$	(206	)	$	(7,122	)
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	$	6,916		$	(16,216	)

_________________________


(1)	Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2017:



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil collars	$	(77	)	Discounted cash flow	Forward commodity price curve	$0.00 - $2.48
Oil three-way collar	(3,473		)	Discounted cash flow	Forward commodity price curve	$0.00 - $5.96
Natural gas three-way collar	3,344			Discounted cash flow	Forward commodity price curve	$0.00 - $0.68

_________________________


(1)	The commodity contracts detailed in this category include non-exchange-traded crude oil collars and crude and 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, 2017, 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, 2017, the carrying values on the consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement at December 31, 2017 approximates 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, 2017 and December 31, 2016 were $642.3 million and $640.1 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2017 and December 31, 2016 were $649.7 million and $649.9 million, respectively. These Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented in Note 7 – Asset Retirement Obligations.

Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2016 and 2015, we recorded non-cash impairment charges discussed further in Note 2 – Summary of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as Level 3.

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $2.7 million, $0.6 million, $0.4 million, and $0.1 million in 2018 through 2021, respectively. Total rent expense incurred was $8.8 million, $11.1 million, and $12.9 million in 2017, 2016, and 2015, respectively. During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. Future capital lease payments under the terms are approximately $6.2 million each year through 2020 and approximately $3.8 million in 2021. Total maintenance and interest remaining related to these leases are $5.9 million and $1.2 million, respectively at December 31, 2017. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time. The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of approximately $2,900, $5,000, $118,000 in 2017, 2016, and 2015, respectively. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well. For 2018, we have committed to purchase approximately $3.9 million of new drilling rig components. We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matter, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our results of operations, financial position, or cash flows.

Equity Equity

12 Months Ended

Dec. 31, 2017

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 intend 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.

Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms and conditions of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).

We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.

As of December 31, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the fourth quarter of 2017.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the years ended December 31:



	2017			2016		2015
	(In thousands)
Unrealized appreciation on securities, before tax	$	102		$	—	$	—
Tax expense	(39		)	—		—
Unrealized appreciation on securities, net of tax	$	63		$	—	$	—

Changes in accumulated other comprehensive income by component, net of tax, for the years ended December 31 are as follows:



	Net Gains on Equity Securities
	2017		2016		2015
	(In thousands)
Balance at January 1:	$	—	$	—	$	—
Unrealized appreciation before reclassifications	63		—		—
Amounts reclassified from accumulated other comprehensive income	—		—		—
Net current-period other comprehensive income	63		—		—
Balance at December 31:	$	63	$	—	$	—

Industry Segment Information

12 Months Ended

Dec. 31, 2017

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, 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
Total operating income (loss) ⁽¹⁾	120,301		(2,630		)	12,937		(7,477		)	(1,620		)
General and administrative expense	—		—			—		(38,087		)	—			(38,087		)
Gain (loss) on disposition of assets	228		(776		)	25		850			—			327
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 ⁽²⁾	$	1,127,900	$	—		$	—	$	—		$	—		$	1,127,900
Contract drilling	—		933,063			—		—			—			933,063
Gas gathering and processing	—		—			438,571		—			—			438,571
Total identifiable assets ⁽³⁾	1,127,900		933,063			438,571		—			—			2,499,534
Corporate land and building	—		—			—		56,854			—			56,854
Other corporate assets ⁽⁴⁾	—		—			—		25,064			—			25,064
Total assets	$	1,127,900	$	933,063		$	438,571	$	81,918		$	—		$	2,581,452

Capital expenditures:	$	270,443	$	36,148		$	22,168	$	3,521		$	—		$	332,280

_______________________


(1)	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income, or income taxes.


(2)	Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.


(3)	Identifiable assets are those used in Unit’s operations in each industry segment.


(4)	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.



	Year Ended December 31, 2016
	Oil and Natural Gas			Contract Drilling			Mid-stream			Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	294,221		$	—		$	—		$	—		$	—		$	294,221
Contract drilling	—			122,086			—			—			—			122,086
Gas gathering and processing	—			—			237,785			—			(51,915		)	185,870
Total revenues	294,221			122,086			237,785			—			(51,915		)	602,177
Expenses:
Operating costs:
Oil and natural gas	126,739			—			—			—			(6,555		)	120,184
Contract drilling	—			88,154			—			—			—			88,154
Gas gathering and processing	—			—			182,969			—			(45,360		)	137,609
Total operating costs	126,739			88,154			182,969			—			(51,915		)	345,947
Depreciation, depletion and amortization	113,811			46,992			45,715			1,835			—			208,353
Impairments ⁽¹⁾	161,563			—			—			—			—			161,563
Total expenses	402,113			135,146			228,684			1,835			(51,915		)	715,863
Total operating income (loss) ⁽²⁾	(107,892		)	(13,060		)	9,101			(1,835		)	—
General and administrative expense	—			—			—			(33,337		)	—			(33,337		)
Gain (loss) on disposition of assets	(324		)	3,184			(302		)	(18		)	—			2,540
Loss on derivatives	—			—			—			(22,813		)	—			(22,813		)
Interest expense, net	—			—			—			(39,829		)	—			(39,829		)
Other	—			—			—			307			—			307
Income (loss) before income taxes	$	(108,216	)	$	(9,876	)	$	8,799		$	(97,525	)	$	—		$	(206,818	)

Identifiable assets:
Oil and natural gas ⁽³⁾	$	965,159		$	—		$	—		$	—		$	—		$	965,159
Contract drilling	—			941,676			—			—			—			941,676
Gas gathering and processing	—			—			461,600			—			—			461,600
Total identifiable assets ⁽⁴⁾	965,159			941,676			461,600			—			—			2,368,435
Corporate land and building	—			—			—			58,188			—			58,188
Other corporate assets ⁽⁵⁾	—			—			—			52,680			—			52,680
Total assets	$	965,159		$	941,676		$	461,600		$	110,868		$	—		$	2,479,303

Capital expenditures:	$	89,562		$	19,134		$	16,796		$	16,663		$	—		$	142,155

_______________________


(1)	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax).


(2)	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


(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)	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.



	Year Ended December 31, 2015
	Oil and Natural Gas			Contract Drilling			Mid-stream			Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	385,774		$	—		$	—		$	—		$	—		$	385,774
Contract drilling	—			287,767			—			—			(22,099		)	265,668
Gas gathering and processing	—			—			268,012			—			(65,223		)	202,789
Total revenues	385,774			287,767			268,012			—			(87,322		)	854,231
Expenses:
Operating costs:
Oil and natural gas	170,831			—			—			—			(4,785		)	166,046
Contract drilling	—			174,757			—			—			(18,349		)	156,408
Gas gathering and processing	—			—			221,994			—			(60,438		)	161,556
Total operating costs	170,831			174,757			221,994			—			(83,572		)	484,010
Depreciation, depletion and amortization	251,944			56,135			43,676			987			—			352,742
Impairments ⁽¹⁾	1,599,348			8,314			26,966			—			—			1,634,628
Total expenses	2,022,123			239,206			292,636			987			(83,572		)	2,471,380
Total operating income (loss) ⁽²⁾	(1,636,349		)	48,561			(24,624		)	(987		)	(3,750		)
General and administrative expense	—			—			—			(34,358		)	—			(34,358		)
Gain (loss) on disposition of assets	(147		)	(7,516		)	465			(31		)	—			(7,229		)
Gain on derivatives	—			—			—			26,345			—			26,345
Interest expense, net	—			—			—			(31,963		)	—			(31,963		)
Other	—			—			—			45			—			45
Income (loss) before income taxes	$	(1,636,496	)	$	41,045		$	(24,159	)	$	(40,949	)	$	(3,750	)	$	(1,664,309	)

Identifiable assets:
Oil and natural gas ⁽³⁾	$	1,218,036		$	—		$	—		$	—		$	—		$	1,218,036
Contract drilling	—			993,015			—			—			—			993,015
Gas gathering and processing	—			—			478,661			—			—			478,661
Total identifiable assets ⁽⁴⁾	1,218,036			993,015			478,661			—			—			2,689,712
Corporate land and building	—			—			—			49,890			—			49,890
Other corporate assets ⁽⁵⁾	—			—			—			60,240						60,240
Total assets	$	1,218,036		$	993,015		$	478,661		$	110,130		$	—		$	2,799,842

Capital expenditures:	$	267,944		$	84,802		$	63,476		$	38,065		$	—		$	454,287

_______________________

(1)

We incurred non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). Impairment for contract drilling equipment includes an $8.3 million pre-tax write-down for 30 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek.


(2)	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


(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)	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, 2017

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)
2016
Revenues	$	136,184		$	138,305		$	153,408		$	174,280
Gross income (loss) ⁽¹⁾	$	(49,745	)	$	(73,830	)	$	(26,893	)	$	36,782
Net income (loss)	$	(41,149	)	$	(72,136	)	$	(24,022	)	$	1,683
Net income (loss) per common share:
Basic ⁽²⁾	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03
Diluted ⁽²⁾	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03
2017
Revenues	$	175,724		$	170,581		$	188,488		$	204,847
Gross income ⁽¹⁾	$	32,657		$	24,462		$	27,181		$	37,211
Net income	$	15,929		$	9,059		$	3,705		$	89,155
Net income per common share:
Basic	$	0.32		$	0.18		$	0.07		$	1.74
Diluted ⁽²⁾	$	0.31		$	0.17		$	0.07		$	1.71

_________________________


(1)	Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss).


(2)	The earnings (loss) per share for the year's four quarters does not equal annual income (loss) per share.

Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2017

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:



	2017			2016			2015
	(In thousands)
Capitalized costs:
Proved properties	$	5,712,813		$	5,446,305		$	5,401,618
Unproved properties	296,764			314,867			337,099
	6,009,577			5,761,172			5,738,717
Accumulated depreciation, depletion, amortization, and impairment	(4,996,696		)	(4,900,304		)	(4,631,404		)
Net capitalized costs	$	1,012,881		$	860,868		$	1,107,313
Cost incurred:
Unproved properties acquired	$	47,029		$	21,675		$	41,777
Proved properties acquired	47,638			564			179
Exploration	14,811			17,325			19,222
Development	160,941			80,582			208,845
Asset retirement obligation	(3,613		)	(30,906		)	(5,693		)
Total costs incurred	$	266,806		$	89,240		$	264,330

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2017, by the year in which such costs were incurred:



	2017		2016		2015		2014 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	50,447	$	22,092	$	40,254	$	183,971	$	296,764

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:



	2017			2016			2015
	(In thousands)
Revenues	$	347,285		$	282,742		$	371,335
Production costs	(107,332		)	(108,822		)	(152,560		)
Depreciation, depletion, amortization, and impairment	(96,392		)	(268,901		)	(1,844,726		)
	143,561			(94,981		)	(1,625,951		)
Income tax (expense) benefit	(56,376		)	32,696			612,496
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	87,185		$	(62,285	)	$	(1,013,455	)

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)
2015
Proved developed and undeveloped reserves:
Beginning of year	22,667		48,529		646,961		179,023
Revision of previous estimates ⁽¹⁾	(3,954	)	(9,367	)	(139,514	)	(36,573	)
Extensions and discoveries	1,208		1,948		20,974		6,651
Infill reserves in existing proved fields	670		1,861		22,641		6,304
Purchases of minerals in place	—		—		—		—
Production	(3,783	)	(5,274	)	(65,546	)	(19,981	)
Sales	(73	)	(10	)	(648	)	(191	)
End of year	16,735		37,687		484,868		135,233
Proved developed reserves:
Beginning of year	17,448		35,850		500,950		136,790
End of year	14,679		31,218		416,395		115,296
Proved undeveloped reserves:
Beginning of year	5,219		12,679		146,011		42,233
End of year	2,056		6,469		68,473		19,937
2016
Proved developed and undeveloped reserves:
Beginning of year	16,735		37,687		484,868		135,233
Revision of previous estimates ⁽¹⁾	(549	)	(2,473	)	(31,670	)	(8,300	)
Extensions and discoveries	1,816		1,588		13,720		5,690
Infill reserves in existing proved fields	663		2,724		24,704		7,504
Purchases of minerals in place	114		43		630		262
Production	(2,974	)	(5,014	)	(55,735	)	(17,277	)
Sales	(109	)	(73	)	(30,938	)	(5,338	)
End of year	15,696		34,482		405,579		117,774
Proved developed reserves:
Beginning of year	14,679		31,218		416,395		115,296
End of year	12,724		28,502		347,121		99,079
Proved undeveloped reserves:
Beginning of year	2,056		6,469		68,473		19,937
End of year	2,972		5,980		58,458		18,695
2017
Proved developed and undeveloped reserves:
Beginning of year	15,696		34,482		405,579		117,774
Revision of previous estimates	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

_________________________


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

Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.

The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:



	2017			2016			2015
	(In thousands)
Future cash flows	$	3,347,396		$	2,030,925		$	2,475,898
Future production costs	(1,308,244		)	(861,625		)	(1,017,777		)
Future development costs	(369,560		)	(173,446		)	(228,445		)
Future income tax expenses	(234,152		)	(141,752		)	(230,544		)
Future net cash flows	1,435,440			854,102			999,132
10% annual discount for estimated timing of cash flows	(628,270		)	(335,892		)	(409,646		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	807,170		$	518,210		$	589,486

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



	2017			2016			2015
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(239,953	)	$	(173,920	)	$	(218,115	)
Net changes in prices and production costs	236,126			(94,026		)	(1,356,333		)
Revisions in quantity estimates and changes in production timing	87,239			(51,979		)	(213,945		)
Extensions, discoveries, and improved recovery, less related costs	102,965			84,738			95,671
Changes in estimated future development costs	(5,194		)	70,976			227,857
Previously estimated cost incurred during the period	36,044			16,602			59,117
Purchases of minerals in place	51,686			2,652			—
Sales of minerals in place	(1,447		)	(17,248		)	(3,338		)
Accretion of discount	57,517			69,069			209,979
Net change in income taxes	(33,389		)	44,241			562,838
Other—net	(2,634		)	(22,381		)	(209,989		)
Net change	288,960			(71,276		)	(846,258		)
Beginning of year	518,210			589,486			1,435,744
End of year	$	807,170		$	518,210		$	589,486

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, 2017, future cash flows were computed by applying the unescalated 12-month average prices of $51.34 per barrel for oil, $31.83 per barrel for NGLs, and $2.98 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, 2017

Valuation and Qualifying Accounts [Abstract]

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, 2017	$	3,773	$	348	$	(1,671	)	$	2,450
Year ended December 31, 2016	$	5,199	$	785	$	(2,211	)	$	3,773
Year ended December 31, 2015	$	5,039	$	1,191	$	(1,031	)	$	5,199

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2017

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.

Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Drilling Contracts

We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2017, all of our contracts were daywork contracts of which nine were multi-well and had durations which ranged from six months to two years, eight of which expire in 2018 and one expiring in 2019. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.

Cash Equivalents and Book Overdrafts

We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2017 and 2016, book overdrafts were $12.4 million and $17.3 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:



	2017		2016		2015
Oil and Natural Gas:
Sunoco Logistics Partners L.P.	10	%	24	%	19	%
Valero Energy Corporation	9	%	11	%	15	%
Drilling:
QEP Resources, Inc.	26	%	28	%	25	%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	7	%	18	%	7	%
Mid-Stream:
ONEOK, Inc.	36	%	30	%	29	%
Range Resources Corporation	9	%	10	%	5	%
Koch Energy Services, LLC	8	%	11	%	9	%
Tenaska Resources, LLC	6	%	10	%	18	%
Laclede Group, Inc.	1	%	9	%	12	%

We had a concentration of cash of $11.4 million and $8.3 million at December 31, 2017 and 2016, respectively with one bank.



	December 31, 2017
	(In millions)
Canadian Imperial Bank of Commerce	$	0.7
Bank of America Merrill Lynch	(2.5		)
Bank of Montreal	(5.3		)
Total assets (liabilities)	$	(7.1	)

Property and Equipment

Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation 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.

Capitalized Interest

During 2017, 2016, and 2015, interest of approximately $15.9 million, $15.3 million, and $21.7 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill

Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2017, 2016, or 2015. There were no additions to goodwill in 2017, 2016, or 2015. Based on our impairment test performed as of December 31, 2017, the fair value of our drilling segment exceeded its carrying value by 41%. Goodwill of $0.7 million is deductible for tax purposes.

Oil and Natural Gas Operations

We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $14.8 million, $15.4 million, and $19.2 million were capitalized in 2017, 2016, and 2015, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $6.00, $6.24, and $12.30 per Boe in 2017, 2016, and 2015, 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 $296.8 million are excluded from the DD&A calculation.

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

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

ARO

We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.

Gas Gathering and Processing Revenue

Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms.

Insurance

We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.

Derivative Activities

All derivatives are recognized on the balance sheet and measured at fair value with the exception of normal purchase and normal sales which are expected to result in physical delivery. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.

We document our risk management strategy and do not engage in derivative transactions for speculative purposes.

Limited Partnerships

Unit Petroleum Company is a general partner in 13 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.

Income Taxes

During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. The change in tax law required the Company to remeasure existing net deferred tax liabilities using the lower rate in the period of enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.

Natural Gas Balancing

We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2017 balancing position to be approximately 3.7 Bcf on under-produced properties and approximately 3.8 Bcf on over-produced properties. We have recorded a receivable of $2.4 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.3 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.

Employee And Director Stock Based Compensation

We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants is based on the closing stock price on the date of the grants.

Impact of Financial Accounting Pronouncements

Part of our review included evaluation of these issues:

•

Adopted Standards

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

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:



	2017		2016		2015
Oil and Natural Gas:
Sunoco Logistics Partners L.P.	10	%	24	%	19	%
Valero Energy Corporation	9	%	11	%	15	%
Drilling:
QEP Resources, Inc.	26	%	28	%	25	%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	7	%	18	%	7	%
Mid-Stream:
ONEOK, Inc.	36	%	30	%	29	%
Range Resources Corporation	9	%	10	%	5	%
Koch Energy Services, LLC	8	%	11	%	9	%
Tenaska Resources, LLC	6	%	10	%	18	%
Laclede Group, Inc.	1	%	9	%	12	%

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

At December 31, 2017, 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, 2017
	(In millions)
Canadian Imperial Bank of Commerce	$	0.7
Bank of America Merrill Lynch	(2.5		)
Bank of Montreal	(5.3		)
Total assets (liabilities)	$	(7.1	)

Acquisitions and Divestitures Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

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


(1)	We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.

Earnings (Loss) Per Share Earnings (Loss) Per Share (Tables)

12 Months Ended

Dec. 31, 2017

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, 2015:
Basic loss per common share	$	(1,037,361	)	49,110	$	(21.12	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(1,037,361	)	49,110	$	(21.12	)
For the year ended December 31, 2016:
Basic loss per common share	$	(135,624	)	50,029	$	(2.71	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(135,624	)	50,029	$	(2.71	)
For the year ended December 31, 2017:
Basic earnings per common share	$	117,848		51,113	$	2.31
Effect of dilutive restricted stock	—			635	(0.03		)
Diluted earnings per common share	$	117,848		51,748	$	2.28

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



	2017		2016		2015
Options and SARs	87,500		199,755		261,270
Average exercise price	$	51.34	$	48.79	$	50.34

Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Accrued Liabilities [Abstract]

Accrued Liabilities [Table Text Block]

Accrued liabilities consisted of the following as of December 31:



	2017		2016
	(In thousands)
Employee costs	$	19,521	$	15,394
Lease operating expenses	11,819		10,075
Interest payable	6,745		6,524
Taxes	3,404		2,219
Third-party credits	2,240		2,998
Other	4,794		2,441
Total accrued liabilities	$	48,523	$	39,651

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

12 Months Ended

Dec. 31, 2017

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:



	2017			2016
	(In thousands)
Credit agreement with average interest rates of 3.4% and 2.8% at December 31, 2017 and 2016, respectively	$	178,000		$	160,800
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	$	828,000		$	810,800
Less: unamortized discount	(2,234		)	(2,804		)
Less: debt issuance costs, net	(5,490		)	(7,079		)
Total long-term debt	$	820,276		$	800,917

Other Long Term Liabilities [Table Text Block]

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



	2017		2016
	(In thousands)
ARO liability	$	69,444	$	70,170
Capital lease obligations	15,224		18,918
Workers’ compensation	13,340		15,163
Separation benefit plans	6,524		4,943
Deferred compensation plan	5,390		4,578
Gas balancing liability	3,283		3,789
Other	—		410
	113,205		117,971
Less current portion	13,002		14,907
Total other long-term liabilities	$	100,203	$	103,064

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

Future payments required under the capital leases at December 31, 2017 are as follows:



	Amount
Ending December 31,	(In thousands)
2018	$	6,168
2019	6,168
2020	6,168
2021	3,768
Total future payments	22,272
Less payments related to:
Maintenance	5,874
Interest	1,174
Present value of future minimum payments	$	15,224

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 505
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

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

+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule Of Asset Retirement Obligations [Table Text Block]

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



	2017			2016
	(In thousands)
ARO liability, January 1:	$	70,170		$	98,297
Accretion of discount	2,886			2,779
Liability incurred	1,948			584
Liability settled	(2,694		)	(1,215		)
Liability sold	(1,735		)	(10,882		)
Revision of estimates ⁽¹⁾	(1,131		)	(19,393		)
ARO liability, December 31:	69,444			70,170
Less current portion	1,726			2,906
Total long-term ARO liability	$	67,718		$	67,264

_________________________


(1)	Plugging liability estimates were revised in both 2017 and 2016 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 (Tables)

12 Months Ended

Dec. 31, 2017

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:



	2017			2016			2015
	(In thousands)
Income tax expense (benefit) computed by applying the statutory rate	$	21,059		$	(72,386	)	$	(582,508	)
State income tax expense (benefit), net of federal benefit	1,655			(5,687		)	(45,768		)
Deferred tax liability revaluation ⁽¹⁾	(81,307		)	—			—
Restricted stock shortfall	1,867			5,465			—
Statutory depletion and other	(952		)	1,414			1,328
Income tax benefit	$	(57,678	)	$	(71,194	)	$	(626,948	)

__________________________


(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:



	2017			2016			2015
	(In thousands)
Current taxes:
Federal	$	—		$	—		$	(20,612	)
State	5			15			(4		)
	5			15			(20,616		)
Deferred taxes:
Federal	(62,788		)	(62,923		)	(535,691		)
State	5,105			(8,286		)	(70,641		)
	(57,683		)	(71,209		)	(606,332		)
Total provision	$	(57,678	)	$	(71,194	)	$	(626,948	)

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

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



	2017			2016
	(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals	$	32,242		$	53,967
Net operating loss carryforward	153,746			190,603
Alternative minimum tax and research and development tax credit carryforward	5,409			5,409
	191,397			249,979
Deferred tax liability:
Depreciation, depletion, amortization, and impairment	(324,874		)	(440,690		)
Net deferred tax liability	(133,477		)	(190,711		)
Current deferred tax asset	—			25,211
Non-current—deferred tax liability	$	(133,477	)	$	(215,922	)

Transactions With Related Parties (Tables)

12 Months Ended

Dec. 31, 2017

Schedule Of Amount Received In Public And Private Partnerships [Table Text Block]

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



	2017		2016		2015
	(In thousands)
Well supervision and other fees	$	172	$	254	$	423
General and administrative expense reimbursement	—		6		18

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

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

Schedule Of Restricted Stock Awards Stock Options And SAR [Table Text Block]

For restricted stock awards, we had:



	2017		2016		2015
	(In millions)
Recognized stock compensation expense	$	13.3	$	9.6	$	15.3
Capitalized stock compensation cost for our oil and natural gas properties	1.8		2.1		3.5
Tax benefit on stock based compensation	5.0		3.6		5.8

Activity Pertaining to Stock Appreciation Rights [Table Text Block]

Activity pertaining to SARs granted under the amended plan is as follows:



	Number of Shares		Weighted Average Price
Outstanding at January 1, 2015	131,770		$	46.60
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2015	131,770		46.60
Granted	—		—
Exercised	—		—
Forfeited	(40,515	)	51.76
Outstanding at December 31, 2016	91,255		44.31
Granted	—		—
Exercised	—		—
Forfeited	(91,255	)	44.31
Outstanding at December 31, 2017	—		$	—

Activity Pertaining To Restricted Stock Awards [Table Text Block]

Activity pertaining to restricted stock awards granted under the amended plan is as follows:



Employees	Number of Time Vested Shares		Number of Performance Vested Shares		Total Number of Shares		Weighted Average Price
Nonvested at January 1, 2015	724,766		175,520		900,286		$	50.81
Granted	576,361		148,081		724,442		34.06
Vested	(343,657	)	(39,245	)	(382,902	)	49.69
Forfeited	(20,808	)	(7,196	)	(28,004	)	45.33
Nonvested at December 31, 2015	936,662		277,160		1,213,822		41.29
Granted	494,078		152,373		646,451		5.62
Vested	(425,195	)	—		(425,195	)	43.47
Forfeited	(75,808	)	(57,405	)	(133,213	)	36.87
Nonvested at December 31, 2016	929,737		372,128		1,301,865		23.32
Granted	485,799		173,373		659,172		26.07
Vested	(455,570	)	(62,119	)	(517,689	)	29.87
Forfeited	(44,408	)	(34,953	)	(79,361	)	38.87
Nonvested at December 31, 2017	915,558		448,429		1,363,987		$	21.25



Non-Employee Directors	Number of Shares		Weighted Average Price
Nonvested at January 1, 2015	35,136		$	50.08
Granted	25,848		34.04
Vested	(18,920	)	46.51
Forfeited	—		—
Nonvested at December 31, 2015	42,064		$	41.83
Granted	90,000		12.02
Vested	(20,248	)	43.46
Forfeited	—		—
Nonvested at December 31, 2016	111,816		$	17.21
Granted	49,104		17.92
Vested	(43,206	)	21.24
Forfeited	—		—
Nonvested at December 31, 2017	117,714		$	16.03

Activity Pertaining to the Stock Option Plan [Table Text Block]

Activity pertaining to the Stock Option Plan is as follows:



	Number of Shares		Weighted Average Exercise Price
Outstanding at January 1, 2015	9,500		$	37.69
Granted	—		—
Exercised	—		—
Forfeited	(9,500	)	37.69
Outstanding at December 31, 2015	—		—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2016	—		—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2017	—		$	—

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, 2015	150,500		$	54.18
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	54.35
Outstanding at December 31, 2015	129,500		54.15
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	62.40
Outstanding at December 31, 2016	108,500		52.56
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	57.63
Outstanding at December 31, 2017	87,500		$	51.34

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



	Outstanding and Exercisable Options at December 31, 2017
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$31.30 - $41.21	38,500	1.9 years	$	37.58
$53.81 - $73.26	49,000	2.1 years	$	62.15

Derivatives (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

At December 31, 2017, the following non-designated hedges were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Jan’18 – Dec’18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
Apr'18 – Oct'18	Natural gas – swap	10,000 MMBtu/day	$2.990	IF – NYMEX (HH)
Jan’18 – Mar'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan’18 – Mar'18	Natural gas – three-way collar	60,000 MMBtu/day	$3.29 - $2.63 - $4.07	IF – NYMEX (HH)
Apr’18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
Jan’18 – Dec'18	Crude oil – swap	3,000 Bbl/day	$51.36	WTI – NYMEX
Jan’18 – Mar'18	Crude oil – collar	500 Bbl/day	$55.00 - $59.50	WTI – NYMEX
Jan’18 – Dec'18	Crude oil – three-way collar	2,000 Bbl/day	$47.50 - $37.50 - $56.08	WTI – NYMEX
Apr’18 – Sep'18	Liquids (Propane) – swap	1,000 Bbl/day	$31.16	MONT BELVIEU

Schedule Of Subsequent Non-designated Hedges [Table Text Block]

After December 31, 2017, the following non-designated hedges were entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Apr’18 – Sep'18	Natural gas – swap	10,000 MMBtu/day	$2.925	IF – NYMEX (HH)
Apr’18 – Sep'18	Natural gas – collar	30,000 MMBtu/day	$2.67 - $2.97	IF – NYMEX (HH)
Feb’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Feb’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.568)	NGPL MIDCON
Apr’18 – Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.190)	NGPL TEXOK
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.728)	PEPL
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.625)	NGPL MIDCON
Jan'19 – Dec'19	Natural gas – basis swap	20,000 MMBtu/day	$(0.273)	NGPL TEXOK
Jan'20 – Dec'20	Natural gas – basis swap	20,000 MMBtu/day	$(0.280)	NGPL TEXOK
Apr'18 – Dec'18	Crude oil – swap	1,000 Bbl/day	$60.00	WTI – NYMEX
Apr’18 – Sep'18	Liquids – swap	500 Bbl/day	$34.10	MONT BELVIEU

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	2017		2016
		(In thousands)
Commodity derivatives:
Current	Current derivative assets	$	721	$	—
Long-term	Non-current derivative assets	—		377
Total derivative assets		$	721	$	377



		Derivative Liabilities Fair Value
	Balance Sheet Location	2017		2016
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	7,763	$	21,564
Long-term	Non-current derivative liabilities	—		415
Total derivative liabilities		$	7,763	$	21,979

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
Derivatives Instruments		2017		2016
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	14,732	$	(22,813	)
Total		$	14,732	$	(22,813	)

_________________________


(1)	Amount settled during the period are gains of $173 and $9,658, respectively.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Available-for-sale Securities [Table Text Block]

The following is a summary of available-for-sale securities:



	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	(In thousands)
Equity Securities:
December 31, 2017	$	830	$	102	$	—	$	932
December 31, 2016	$	—	$	—	$	—	$	—

Recurring Fair Value Measurements [Table Text Block]

The following tables set forth our recurring fair value measurements:



	December 31, 2017
	Level 2			Level 3			Effect of Netting			Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	2,137		$	3,344		$	(4,760	)	$	721
Liabilities	(8,973		)	(3,550		)	4,760			(7,763		)
	$	(6,836	)	$	(206	)	$	—		$	(7,042	)



	December 31, 2016
	Level 2			Level 3			Effect of Netting			Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	878		$	43		$	(544	)	$	377
Liabilities	(15,358		)	(7,165		)	544			(21,979		)
	$	(14,480	)	$	(7,122	)	$	—		$	(21,602	)

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, 2017			December 31, 2016
	(In thousands)
Beginning of period	$	(7,122	)	$	9,094
Total gains or losses:
Included in earnings⁽¹⁾	7,791			(9,042		)
Settlements	(875		)	(7,174		)
End of period	$	(206	)	$	(7,122	)
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	$	6,916		$	(16,216	)

_________________________


(1)	Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives.

Schedule Of Quantitative Information About Unobservable Inputs [Table Text Block]

The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2017:



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil collars	$	(77	)	Discounted cash flow	Forward commodity price curve	$0.00 - $2.48
Oil three-way collar	(3,473		)	Discounted cash flow	Forward commodity price curve	$0.00 - $5.96
Natural gas three-way collar	3,344			Discounted cash flow	Forward commodity price curve	$0.00 - $0.68

_________________________


(1)	The commodity contracts detailed in this category include non-exchange-traded crude oil collars and crude and 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.

- Definition

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

+ References + Details

Equity Equity (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income [Table Text Block]

Components of accumulated other comprehensive income were as follows for the years ended December 31:



	2017			2016		2015
	(In thousands)
Unrealized appreciation on securities, before tax	$	102		$	—	$	—
Tax expense	(39		)	—		—
Unrealized appreciation on securities, net of tax	$	63		$	—	$	—

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

Changes in accumulated other comprehensive income by component, net of tax, for the years ended December 31 are as follows:



	Net Gains on Equity Securities
	2017		2016		2015
	(In thousands)
Balance at January 1:	$	—	$	—	$	—
Unrealized appreciation before reclassifications	63		—		—
Amounts reclassified from accumulated other comprehensive income	—		—		—
Net current-period other comprehensive income	63		—		—
Balance at December 31:	$	63	$	—	$	—

Industry Segment Information (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Revenue From Different Segments [Table Text Block]

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



	Year Ended December 31, 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
Total operating income (loss) ⁽¹⁾	120,301		(2,630		)	12,937		(7,477		)	(1,620		)
General and administrative expense	—		—			—		(38,087		)	—			(38,087		)
Gain (loss) on disposition of assets	228		(776		)	25		850			—			327
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 ⁽²⁾	$	1,127,900	$	—		$	—	$	—		$	—		$	1,127,900
Contract drilling	—		933,063			—		—			—			933,063
Gas gathering and processing	—		—			438,571		—			—			438,571
Total identifiable assets ⁽³⁾	1,127,900		933,063			438,571		—			—			2,499,534
Corporate land and building	—		—			—		56,854			—			56,854
Other corporate assets ⁽⁴⁾	—		—			—		25,064			—			25,064
Total assets	$	1,127,900	$	933,063		$	438,571	$	81,918		$	—		$	2,581,452

Capital expenditures:	$	270,443	$	36,148		$	22,168	$	3,521		$	—		$	332,280

_______________________


(1)	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income, or income taxes.


(2)	Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.


(3)	Identifiable assets are those used in Unit’s operations in each industry segment.


(4)	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.



	Year Ended December 31, 2016
	Oil and Natural Gas			Contract Drilling			Mid-stream			Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	294,221		$	—		$	—		$	—		$	—		$	294,221
Contract drilling	—			122,086			—			—			—			122,086
Gas gathering and processing	—			—			237,785			—			(51,915		)	185,870
Total revenues	294,221			122,086			237,785			—			(51,915		)	602,177
Expenses:
Operating costs:
Oil and natural gas	126,739			—			—			—			(6,555		)	120,184
Contract drilling	—			88,154			—			—			—			88,154
Gas gathering and processing	—			—			182,969			—			(45,360		)	137,609
Total operating costs	126,739			88,154			182,969			—			(51,915		)	345,947
Depreciation, depletion and amortization	113,811			46,992			45,715			1,835			—			208,353
Impairments ⁽¹⁾	161,563			—			—			—			—			161,563
Total expenses	402,113			135,146			228,684			1,835			(51,915		)	715,863
Total operating income (loss) ⁽²⁾	(107,892		)	(13,060		)	9,101			(1,835		)	—
General and administrative expense	—			—			—			(33,337		)	—			(33,337		)
Gain (loss) on disposition of assets	(324		)	3,184			(302		)	(18		)	—			2,540
Loss on derivatives	—			—			—			(22,813		)	—			(22,813		)
Interest expense, net	—			—			—			(39,829		)	—			(39,829		)
Other	—			—			—			307			—			307
Income (loss) before income taxes	$	(108,216	)	$	(9,876	)	$	8,799		$	(97,525	)	$	—		$	(206,818	)

Identifiable assets:
Oil and natural gas ⁽³⁾	$	965,159		$	—		$	—		$	—		$	—		$	965,159
Contract drilling	—			941,676			—			—			—			941,676
Gas gathering and processing	—			—			461,600			—			—			461,600
Total identifiable assets ⁽⁴⁾	965,159			941,676			461,600			—			—			2,368,435
Corporate land and building	—			—			—			58,188			—			58,188
Other corporate assets ⁽⁵⁾	—			—			—			52,680			—			52,680
Total assets	$	965,159		$	941,676		$	461,600		$	110,868		$	—		$	2,479,303

Capital expenditures:	$	89,562		$	19,134		$	16,796		$	16,663		$	—		$	142,155

_______________________


(1)	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax).


(2)	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


(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)	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.



	Year Ended December 31, 2015
	Oil and Natural Gas			Contract Drilling			Mid-stream			Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	385,774		$	—		$	—		$	—		$	—		$	385,774
Contract drilling	—			287,767			—			—			(22,099		)	265,668
Gas gathering and processing	—			—			268,012			—			(65,223		)	202,789
Total revenues	385,774			287,767			268,012			—			(87,322		)	854,231
Expenses:
Operating costs:
Oil and natural gas	170,831			—			—			—			(4,785		)	166,046
Contract drilling	—			174,757			—			—			(18,349		)	156,408
Gas gathering and processing	—			—			221,994			—			(60,438		)	161,556
Total operating costs	170,831			174,757			221,994			—			(83,572		)	484,010
Depreciation, depletion and amortization	251,944			56,135			43,676			987			—			352,742
Impairments ⁽¹⁾	1,599,348			8,314			26,966			—			—			1,634,628
Total expenses	2,022,123			239,206			292,636			987			(83,572		)	2,471,380
Total operating income (loss) ⁽²⁾	(1,636,349		)	48,561			(24,624		)	(987		)	(3,750		)
General and administrative expense	—			—			—			(34,358		)	—			(34,358		)
Gain (loss) on disposition of assets	(147		)	(7,516		)	465			(31		)	—			(7,229		)
Gain on derivatives	—			—			—			26,345			—			26,345
Interest expense, net	—			—			—			(31,963		)	—			(31,963		)
Other	—			—			—			45			—			45
Income (loss) before income taxes	$	(1,636,496	)	$	41,045		$	(24,159	)	$	(40,949	)	$	(3,750	)	$	(1,664,309	)

Identifiable assets:
Oil and natural gas ⁽³⁾	$	1,218,036		$	—		$	—		$	—		$	—		$	1,218,036
Contract drilling	—			993,015			—			—			—			993,015
Gas gathering and processing	—			—			478,661			—			—			478,661
Total identifiable assets ⁽⁴⁾	1,218,036			993,015			478,661			—			—			2,689,712
Corporate land and building	—			—			—			49,890			—			49,890
Other corporate assets ⁽⁵⁾	—			—			—			60,240						60,240
Total assets	$	1,218,036		$	993,015		$	478,661		$	110,130		$	—		$	2,799,842

Capital expenditures:	$	267,944		$	84,802		$	63,476		$	38,065		$	—		$	454,287

_______________________

(1)


(2)	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


(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)	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, 2017

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)
2016
Revenues	$	136,184		$	138,305		$	153,408		$	174,280
Gross income (loss) ⁽¹⁾	$	(49,745	)	$	(73,830	)	$	(26,893	)	$	36,782
Net income (loss)	$	(41,149	)	$	(72,136	)	$	(24,022	)	$	1,683
Net income (loss) per common share:
Basic ⁽²⁾	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03
Diluted ⁽²⁾	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03
2017
Revenues	$	175,724		$	170,581		$	188,488		$	204,847
Gross income ⁽¹⁾	$	32,657		$	24,462		$	27,181		$	37,211
Net income	$	15,929		$	9,059		$	3,705		$	89,155
Net income per common share:
Basic	$	0.32		$	0.18		$	0.07		$	1.74
Diluted ⁽²⁾	$	0.31		$	0.17		$	0.07		$	1.71

_________________________


(1)	Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss).


(2)	The earnings (loss) per share for the year's four quarters does not equal annual income (loss) per share.

Supplemental Oil And Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2017

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:



	2017			2016			2015
	(In thousands)
Capitalized costs:
Proved properties	$	5,712,813		$	5,446,305		$	5,401,618
Unproved properties	296,764			314,867			337,099
	6,009,577			5,761,172			5,738,717
Accumulated depreciation, depletion, amortization, and impairment	(4,996,696		)	(4,900,304		)	(4,631,404		)
Net capitalized costs	$	1,012,881		$	860,868		$	1,107,313
Cost incurred:
Unproved properties acquired	$	47,029		$	21,675		$	41,777
Proved properties acquired	47,638			564			179
Exploration	14,811			17,325			19,222
Development	160,941			80,582			208,845
Asset retirement obligation	(3,613		)	(30,906		)	(5,693		)
Total costs incurred	$	266,806		$	89,240		$	264,330

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, 2017, by the year in which such costs were incurred:



	2017		2016		2015		2014 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	50,447	$	22,092	$	40,254	$	183,971	$	296,764

Results Of Operations For Producing Activities [Table Text Block]

The results of operations for producing activities are as follows:



	2017			2016			2015
	(In thousands)
Revenues	$	347,285		$	282,742		$	371,335
Production costs	(107,332		)	(108,822		)	(152,560		)
Depreciation, depletion, amortization, and impairment	(96,392		)	(268,901		)	(1,844,726		)
	143,561			(94,981		)	(1,625,951		)
Income tax (expense) benefit	(56,376		)	32,696			612,496
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	87,185		$	(62,285	)	$	(1,013,455	)

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)
2015
Proved developed and undeveloped reserves:
Beginning of year	22,667		48,529		646,961		179,023
Revision of previous estimates ⁽¹⁾	(3,954	)	(9,367	)	(139,514	)	(36,573	)
Extensions and discoveries	1,208		1,948		20,974		6,651
Infill reserves in existing proved fields	670		1,861		22,641		6,304
Purchases of minerals in place	—		—		—		—
Production	(3,783	)	(5,274	)	(65,546	)	(19,981	)
Sales	(73	)	(10	)	(648	)	(191	)
End of year	16,735		37,687		484,868		135,233
Proved developed reserves:
Beginning of year	17,448		35,850		500,950		136,790
End of year	14,679		31,218		416,395		115,296
Proved undeveloped reserves:
Beginning of year	5,219		12,679		146,011		42,233
End of year	2,056		6,469		68,473		19,937
2016
Proved developed and undeveloped reserves:
Beginning of year	16,735		37,687		484,868		135,233
Revision of previous estimates ⁽¹⁾	(549	)	(2,473	)	(31,670	)	(8,300	)
Extensions and discoveries	1,816		1,588		13,720		5,690
Infill reserves in existing proved fields	663		2,724		24,704		7,504
Purchases of minerals in place	114		43		630		262
Production	(2,974	)	(5,014	)	(55,735	)	(17,277	)
Sales	(109	)	(73	)	(30,938	)	(5,338	)
End of year	15,696		34,482		405,579		117,774
Proved developed reserves:
Beginning of year	14,679		31,218		416,395		115,296
End of year	12,724		28,502		347,121		99,079
Proved undeveloped reserves:
Beginning of year	2,056		6,469		68,473		19,937
End of year	2,972		5,980		58,458		18,695
2017
Proved developed and undeveloped reserves:
Beginning of year	15,696		34,482		405,579		117,774
Revision of previous estimates	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

_________________________


(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]



	2017			2016			2015
	(In thousands)
Future cash flows	$	3,347,396		$	2,030,925		$	2,475,898
Future production costs	(1,308,244		)	(861,625		)	(1,017,777		)
Future development costs	(369,560		)	(173,446		)	(228,445		)
Future income tax expenses	(234,152		)	(141,752		)	(230,544		)
Future net cash flows	1,435,440			854,102			999,132
10% annual discount for estimated timing of cash flows	(628,270		)	(335,892		)	(409,646		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	807,170		$	518,210		$	589,486

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:



	2017			2016			2015
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(239,953	)	$	(173,920	)	$	(218,115	)
Net changes in prices and production costs	236,126			(94,026		)	(1,356,333		)
Revisions in quantity estimates and changes in production timing	87,239			(51,979		)	(213,945		)
Extensions, discoveries, and improved recovery, less related costs	102,965			84,738			95,671
Changes in estimated future development costs	(5,194		)	70,976			227,857
Previously estimated cost incurred during the period	36,044			16,602			59,117
Purchases of minerals in place	51,686			2,652			—
Sales of minerals in place	(1,447		)	(17,248		)	(3,338		)
Accretion of discount	57,517			69,069			209,979
Net change in income taxes	(33,389		)	44,241			562,838
Other—net	(2,634		)	(22,381		)	(209,989		)
Net change	288,960			(71,276		)	(846,258		)
Beginning of year	518,210			589,486			1,435,744
End of year	$	807,170		$	518,210		$	589,486

- Definition

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

+ References

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

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

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

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

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

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

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

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

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

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

+ Details

- Definition

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

- Definition

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

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

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

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, 2017	$	3,773	$	348	$	(1,671	)	$	2,450
Year ended December 31, 2016	$	5,199	$	785	$	(2,211	)	$	3,773
Year ended December 31, 2015	$	5,039	$	1,191	$	(1,031	)	$	5,199

Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Sunoco Logistics Partners L.P. \| Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	24.00%	19.00%
Valero Energy Corporation \| Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	9.00%	11.00%	15.00%
QEP Resources, Inc. \| Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	26.00%	28.00%	25.00%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) \| Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	7.00%	18.00%	7.00%
ONEOK, Inc. \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	36.00%	30.00%	29.00%
Range Resources Corporation \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	9.00%	10.00%	5.00%
Koch Energy Services, LLC \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	8.00%	11.00%	9.00%
Tenaska Resources, LLC \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	6.00%	10.00%	18.00%
Laclede Group, Inc. \| Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	1.00%	9.00%	12.00%

Summary Of Significant Accounting Policies (Schedule of Fair Values of the Net Asset (Liabilities)) (Details) $ in Millions	Dec. 31, 2017 USD ($)
Derivative Counterparty [Line Items]
Total assets (liabilities)	$ (7.1)
Canadian Imperial Bank of Commerce
Derivative Counterparty [Line Items]
Total assets (liabilities)	0.7
Bank of America Merrill Lynch
Derivative Counterparty [Line Items]
Total assets (liabilities)	(2.5)
Bank of Montreal
Derivative Counterparty [Line Items]
Total assets (liabilities)	$ (5.3)

Summary Of Significant Accounting Policies (Narrative) (Details)

12 Months Ended

Dec. 31, 2017

USD ($)

contract

Unit

rig

MMcf

Dec. 31, 2016

USD ($)

rig

Dec. 31, 2015

USD ($)

rig

systems

Summary Of Significant Accounting Policies [Line Items]

Number of daywork contracts | contract

Number of contracts, daywork expiring in one year | contract

Number of contracts, daywork expiring in two years | contract

Book Overdrafts

$ 12,400,000

$ 17,300,000

Concentration of cash

11,400,000

8,300,000

Interest Costs Capitalized

15,900,000

15,300,000

$ 21,700,000

Goodwill impairment

Additions to goodwill

$ 0

Percentage fair value exceeds carrying value for goodwill

41.00%

Goodwill deductible for tax purposes

$ 700,000

14,800,000

15,400,000

19,200,000

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

6.00

6.24

12.30

Unproved properties not being amortized

$ 296,764,000

314,867,000

337,099,000

Future discounted net cash flows discounted

10.00%

Unproved properties included in amortization

$ 10,500,000

7,600,000

114,400,000

Revenues from transactions with operating segments of same entity

13,400,000

22,100,000

Eliminated associated operating expense

11,800,000

18,300,000

Eliminated yielding

$ 1,600,000

$ 0

3,800,000

Number of oil and gas limited partnerships | Unit

Federal statutory income tax rate, percent

35.00%

Tax benefit from change in enacted tax rate

^[1]

$ (81,307,000)

$ 0

Liability recognized to under production

$ (3,283,000)

$ (3,789,000)

Minimum

Summary Of Significant Accounting Policies [Line Items]

Number of days for drilling of one well

10 days

Duration length of contracts

6 months

Insurance coverage

$ 0

Maximum

Summary Of Significant Accounting Policies [Line Items]

Number of days for drilling of one well

90 days

Duration length of contracts

2 years

Insurance coverage

$ 1,000,000

Under-Produced Properties

Summary Of Significant Accounting Policies [Line Items]

Natural gas balancing (MMcf) | MMcf

3,700

Over-Produced Properties

Summary Of Significant Accounting Policies [Line Items]

Natural gas balancing (MMcf) | MMcf

3,800

Natural Gas Balancing

Summary Of Significant Accounting Policies [Line Items]

Accounts receivable

$ 2,400,000

Drilling Equipment

Summary Of Significant Accounting Policies [Line Items]

Minimum depreciation percentage for idle drilling rigs

20.00%

Number of rigs sold | rig

Impairment of contract drilling equipment

$ 0

$ 8,300,000

Net book value of drilling rigs sold

1,700,000.0

11,300,000

Gain (loss) on sale of drilling rigs

1,600,000

(7,300,000)

Drilling Equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life, years

15 years

Building

Summary Of Significant Accounting Policies [Line Items]

Useful life, years

39 years

Property, Plant and Equipment, Other Types | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life, years

3 years

Property, Plant and Equipment, Other Types | Maximum

Summary Of Significant Accounting Policies [Line Items]

Useful life, years

15 years

Gas Gathering and Processing Equipment

Summary Of Significant Accounting Policies [Line Items]

Impairment of gas gathering systems

$ 0

$ 27,000,000

Number of gas gathering systems impaired | systems

Oil and Natural Gas

Summary Of Significant Accounting Policies [Line Items]

Impairment of oil and natural gas properties

161,563,000

$ 1,599,348,000

Non-cash ceiling test write-down net of tax

$ 0

100,600,000

1,000,000,000

Oil and Natural Gas

Summary Of Significant Accounting Policies [Line Items]

Impairment of oil and natural gas properties

161,563,000

^[2]

$ 1,599,348,000

^[3]

Non-cash ceiling test write-down net of tax

$ 100,600,000

Effective starting 2018 [Member]

Summary Of Significant Accounting Policies [Line Items]

Federal statutory income tax rate, percent

21.00%

[1]	In 2017, the revaluation from the Tax Act.
[2]	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax).
[3]	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). Impairment for contract drilling equipment includes an $8.3 million pre-tax write-down for 30 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek.

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

Apr. 03, 2017

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Business Acquisition [Line Items]

Proved oil and natural gas properties

$ 5,712,813

$ 5,446,305

$ 5,401,618

Unproved properties not being amortized

296,764

314,867

337,099

Asset retirement obligation

$ (69,444)

$ (70,170)

$ (98,297)

EOG Acquisition

Business Acquisition [Line Items]

Total consideration given

$ 54,332

Proved oil and natural gas properties

43,745

Unproved properties not being amortized

8,650

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

^[1]

52,395

Gas gathering equipment and other

2,340

Asset retirement obligation

(403)

Fair value of net assets acquired

$ 54,332

[1]

We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.

Acquisitions and Divestitures - Narrative (Details) MBoe in Thousands		12 Months Ended
	Apr. 03, 2017 USD ($) a MBoe wells	Dec. 31, 2017 USD ($) MBoe rig	Dec. 31, 2016 USD ($) MBoe rig	Dec. 31, 2015 USD ($) MBoe rig	Dec. 31, 2014 MBoe
Acquisitions and Divestitures [Line Items]
Proved Developed Reserves (Volume) \| MBoe		112,961	99,079	115,296	136,790
EOG Acquisition
Acquisitions and Divestitures [Line Items]
Total consideration given	$ 54,332,000
Business Acquisition, Effective Date of Acquisition	Jan. 01, 2017
Proved Developed Reserves (Volume) \| MBoe	3,200
Natural Gas Gathering System	1
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%
Oil and Natural Gas
Acquisitions and Divestitures [Line Items]
Other acquisitions		$ 4,700,000
Proceeds from divestiture of assets		$ 18,600,000	$ 67,200,000	$ 1,900,000
Drilling Equipment
Acquisitions and Divestitures [Line Items]
Number of rigs sold \| rig		0	1	31
Impairment of contract drilling equipment		$ 0	$ 0	$ 8,300,000
Net book value of drilling rigs sold			1,700,000.0	11,300,000
Gain (loss) on sale of drilling rigs			$ 1,600,000	$ (7,300,000)

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, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Earnings Per Share [Abstract]

Income (loss) of basic earnings (loss) per common share

$ 89,155

$ 3,705

$ 9,059

$ 15,929

$ 1,683

$ (24,022)

$ (72,136)

$ (41,149)

$ 117,848

$ (135,624)

$ (1,037,361)

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

Income (loss) of diluted earnings (loss) per common share

$ 117,848

$ (135,624)

$ (1,037,361)

Weighted shares of basic earnings (loss) per common share

51,113

50,029

49,110

Weighted shares of effect of dilutive stock options, restricted stock, and SARs

635

Weighted shares of diluted earnings (loss) per common share

51,748

50,029

49,110

Per share amount of basic earnings (loss) per common share

$ 1.74

$ 0.07

$ 0.18

$ 0.32

$ 0.03

^[1]

$ (0.48)

^[1]

$ (1.44)

^[1]

$ (0.83)

^[1]

$ 2.31

$ (2.71)

$ (21.12)

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

(0.03)

0.00

Per share amount of diluted earnings (loss) per common share

$ 1.71

^[1]

$ 0.07

^[1]

$ 0.17

^[1]

$ 0.31

^[1]

$ 0.03

^[1]

$ (0.48)

^[1]

$ (1.44)

^[1]

$ (0.83)

^[1]

$ 2.28

$ (2.71)

$ (21.12)

[1]	The earnings (loss) per share for the year's four quarters does not equal annual income (loss) per share.

Earnings (Loss) Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) - Stock options and SARs - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options and SARs	87,500	199,755	261,270
Average Exercise Price	$ 51.34	$ 48.79	$ 50.34

Earnings (Loss) Per Share Earnings (Loss) Per Share (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Stock options, restricted stock, and SARs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share due to net loss	509,000	186,000

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accrued Liabilities [Abstract]
Employee costs	$ 19,521	$ 15,394
Lease operating expenses	11,819	10,075
Interest payable	6,745	6,524
Taxes	3,404	2,219
Third-party credits	2,240	2,998
Other	4,794	2,441
Total accrued liabilities	$ 48,523	$ 39,651

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Long-term debt and other long-term liabilites [Abstract]
Credit agreement with average interest rates of 3.4% and 2.8% at December 31, 2017 and 2016, respectively	$ 178,000	$ 160,800
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	828,000	810,800
Less: unamortized discount	(2,234)	(2,804)
Less: debt issuance costs, net	(5,490)	(7,079)
Total long-term debt	$ 820,276	$ 800,917
Line of Credit Facility, Interest Rate at Period End	3.40%	2.80%

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term debt and other long-term liabilites [Abstract]
ARO liability	$ 69,444	$ 70,170	$ 98,297
Capital lease obligations	15,224	18,918
Workers' compensation	13,340	15,163
Separation benefit plans	6,524	4,943
Deferred compensation plan	5,390	4,578
Gas balancing liability	3,283	3,789
Other	0	410
Other liabilities	113,205	117,971
Less current portion	13,002	14,907
Total other long-term liabilities	$ 100,203	$ 103,064

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt and Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Ending December 31, [Abstract]
2018	$ 6,168
2019	6,168
2020	6,168
2021	3,768
Total future payments	22,272
Less payments related to:
Maintenance	5,874
Interest	1,174
Present value of future minimum payments	$ 15,224	$ 18,918

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Credit facility maturity date	4/10/2020
Credit Facility Maximum Credit Amount	$ 875,000
Commitment fee percentage under credit facility	0.50%
Origination, agency and syndication fees	$ 1,000
Oil and Gas Property, Full Cost Method, Discount Percentage	10.00%
Debt instrument, variable interest rate, payable assessment period	90 days
LIBOR interest rate plus one percent plus a margin	LIBOR plus 1.00% plus a margin
Line of credit facility, amount borrowed	$ 178,000	$ 160,800
Current ratio of credit facility	1 to 1
Aggregate principal amount	$ 650,000	$ 650,000
Interest percentage of senior subordinated notes	6.625%
Debt Instrument, Maturity Date	May 15, 2021
Deducting fees for debt issuance	$ 14,700
Senior notes repurchase price in percentage	101.00%
Principal Payments Year One	$ 13,000
Principal Payments Year Two	45,600
Principal Payments Year Three	184,700
Principal Payments Year Four	655,900
Principal Payments Year Five	$ 2,100
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,800
Capital Lease Obligations, Noncurrent	$ 11,400
Discount rate capital leases	4.00%
Maintenance	$ 5,874
Interest	1,174
Capital leases, future minimum payments, average annual payment	$ 4,200
Capital lease fair market value percentage for purchase	10.00%
Minimum
Debt Instrument [Line Items]
LIBOR plus interest rate	2.00%
Maximum
Debt Instrument [Line Items]
LIBOR plus interest rate	3.00%
Payments of dividends exceeding percentage	30.00%
Line Of Credit Facility Commitment Amount]
Debt Instrument [Line Items]
Credit facility current credit amount	$ 475,000
Line Of Credit Facility Lender Determined Amount
Debt Instrument [Line Items]
Credit facility current credit amount	$ 475,000
Proved developed producing total value of our oil and gas properties
Debt Instrument [Line Items]
Percentage of collateral pledged	85.00%
Oil and Gas Property, Full Cost Method, Discount Percentage	8.00%
Ownership interest in Superior Pipeline Company, L.L.C.
Debt Instrument [Line Items]
Percentage of collateral pledged	100.00%
Apr 8, 2016 to Mar 31, 2019
Debt Instrument [Line Items]
Senior indebtedness ratio	2.75 to 1
Apr 1, 2019 to Apr 20, 2020
Debt Instrument [Line Items]
Leverage ratio of long-term debt	4 to 1

Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

ARO liability, January 1:

$ 70,170

$ 98,297

Accretion of discount

2,886

2,779

Liability incurred

1,948

584

Liability settled

(2,694)

(1,215)

Liability sold

(1,735)

(10,882)

Revision of estimates

^[1]

(1,131)

(19,393)

ARO liability, December 31:

69,444

70,170

Less current portion

1,726

2,906

Total long-term ARO liability

$ 67,718

$ 67,264

[1]	Plugging liability estimates were revised in both 2017 and 2016 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, 2017

Dec. 31, 2016

Dec. 31, 2015

Income Tax Disclosure [Abstract]

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

$ 21,059

$ (72,386)

$ (582,508)

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

1,655

(5,687)

(45,768)

Deferred tax liability revaluation

^[1]

(81,307)

Restricted stock shortfall

1,867

5,465

Statutory depletion and other

(952)

1,414

1,328

Income tax benefit

$ (57,678)

$ (71,194)

$ (626,948)

[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, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current taxes, Federal	$ 0	$ 0	$ (20,612)
Current taxes, State	5	15	(4)
Current taxes	5	15	(20,616)
Deferred taxes, Federal	(62,788)	(62,923)	(535,691)
Deferred taxes, State	5,105	(8,286)	(70,641)
Deferred taxes	(57,683)	(71,209)	(606,332)
Total provision	$ (57,678)	$ (71,194)	$ (626,948)

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Allowance for losses and nondeductible accruals	$ 32,242	$ 53,967
Net operating loss carryforward	153,746	190,603
Alternative minimum tax and research and development tax credit carryforward	5,409	5,409
Deferred tax assets, total	191,397	249,979
Depreciation, depletion, amortization, and impairment	(324,874)	(440,690)
Net deferred tax liability	(133,477)	(190,711)
Current deferred tax asset	0	25,211
Non-current-deferred tax liability	$ (133,477)	$ (215,922)

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Operating Loss Carryforwards [Line Items]

Federal statutory income tax rate, percent

35.00%

Tax benefit from change in enacted tax rate

^[1]

$ (81,307)

$ 0

Income tax benefit

(57,678)

$ (71,194)

$ (626,948)

Operating loss carryforwards

587,900

Unrecognized tax benefits

$ 0

Start

Operating Loss Carryforwards [Line Items]

Operating loss expiration period

Jan. 01, 2021

End

Operating Loss Carryforwards [Line Items]

Operating loss expiration period

Jan. 01, 2037

Effective starting 2018 [Member]

Operating Loss Carryforwards [Line Items]

Federal statutory income tax rate, percent

21.00%

[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, 2017 USD ($) yr shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares
Defined Benefit Plan Disclosure [Line Items]
Recognized stock compensation expense			$ 13,300	$ 9,600	$ 15,300
Deferred compensation plan			$ 5,390	$ 4,578
Employee Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution of shares, common stock \| shares			155,822	630,039	235,104
Recognized stock compensation expense			$ 4,400	$ 4,000	$ 6,200
Separation Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service period, years		20 years
Maximum period benefit, weeks \| week		104
Separation benefit plans expense			$ 2,700	$ 3,100	$ 3,000
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
Plan401k [Member]
Defined Benefit Plan Disclosure [Line Items]
Additional period for 401k, years			3 years

Transactions With Related Parties Transactions With Related Parties (Schedule of Amount Received in Public and Private Partnerships) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Well supervision and other fees	$ 172	$ 254	$ 423
General and administrative expense reimbursement	$ 0	$ 6	$ 18

Transactions With Related Parties (Narrative) (Details)	12 Months Ended
Transactions With Related Parties (Narrative) (Details)	Dec. 31, 2017 USD ($) Unit Partnerships	Dec. 31, 2016 USD ($) Partnerships	Dec. 31, 2015 USD ($) wells Partnerships	Dec. 31, 2014 Partnerships	Nov. 30, 2016 USD ($)	May 31, 2016 USD ($)	Mar. 10, 2016 USD ($)
Related Party Transaction [Line Items]
Number of oil and gas limited partnerships for employee investment \| Unit	13
Partnerships dissolved \| Partnerships	0	2	0	1
Minimum
Related Party Transaction [Line Items]
Interest rate of employee partnerships in oil and gas properties	1.00%
Maximum
Related Party Transaction [Line Items]
Interest rate of employee partnerships in oil and gas properties	15.00%
John Nikkel
Related Party Transaction [Line Items]
John Nikkel senior subordinated note purchase							$ 400,000
Interest John Nikkel received on senior notes					$ 13,250	$ 4,800
G. Bailey Peyton IV
Related Party Transaction [Line Items]
Payments for royalties	$ 700,000	$ 500,000	$ 800,000
Toklan Oil and Gas Company \| John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage		25.80%
Number of wells drilled		0
Completed wells \| wells			1
Revenue from related parties		$ 0	$ 500,000
Cash received from related parties			900,000
Related party accounts receivable balance			0
Payments for royalties		$ 0	0
Toklan Oil and Gas Company \| Robert Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage		20.00%
West Thomas Field Services, LLC \| John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage		25.00%
Revenue from related parties		$ 400,000	100,000
West Thomas Field Services, LLC \| Robert Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage		20.00%
Gas Gathering and Processing Equipment \| Toklan Oil and Gas Company \| John Nikkel
Related Party Transaction [Line Items]
Amount received from Toklan for gathering system			$ 500,000

Stock-Based Compensation (Schedule Of Restricted Stock Awards Stock Options And SAR) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognized stock compensation expense	$ 13.3	$ 9.6	$ 15.3
Capitalized stock compensation cost for our oil and natural gas properties	1.8	2.1	3.5
Tax benefit on stock based compensation	$ 5.0	$ 3.6	$ 5.8

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Appreciation Rights) (Details) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	91,255	131,770	131,770
Weighted average price, beginning balance	$ 44.31	$ 46.60	$ 46.60
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	$ 0.00	$ 0.00	$ 0.00
Number of shares, forfeited	(91,255)	(40,515)	0
Weighted average price, forfeited	$ 44.31	$ 51.76	$ 0
Number of shares, ending balance	0	91,255	131,770
Weighted average price, ending balance	$ 0.00	$ 44.31	$ 46.60

Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	1,301,865	1,213,822	900,286
Weighted average price, beginning balance	$ 23.32	$ 41.29	$ 50.81
Number of shares, granted	659,172	646,451	724,442
Weighted average price, granted	$ 26.07	$ 5.62	$ 34.06
Number of shares, vested	(517,689)	(425,195)	(382,902)
Weighted average price, vested	$ 29.87	$ 43.47	$ 49.69
Number of shares, forfeited	(79,361)	(133,213)	(28,004)
Weighted average price, forfeited	$ 38.87	$ 36.87	$ 45.33
Number of shares, ending balance	1,363,987	1,301,865	1,213,822
Weighted average price, ending balance	$ 21.25	$ 23.32	$ 41.29
Restricted Stock - Non-employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	111,816	42,064	35,136
Weighted average price, beginning balance	$ 17.21	$ 41.83	$ 50.08
Number of shares, granted	49,104	90,000	25,848
Weighted average price, granted	$ 17.92	$ 12.02	$ 34.04
Number of shares, vested	(43,206)	(20,248)	(18,920)
Weighted average price, vested	$ 21.24	$ 43.46	$ 46.51
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$ 0.00	$ 0.00	$ 0.00
Number of shares, ending balance	117,714	111,816	42,064
Weighted average price, ending balance	$ 16.03	$ 17.21	$ 41.83
Time Vested \| Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	929,737	936,662	724,766
Number of shares, granted	485,799	494,078	576,361
Number of shares, vested	(455,570)	(425,195)	(343,657)
Number of shares, forfeited	(44,408)	(75,808)	(20,808)
Number of shares, ending balance	915,558	929,737	936,662
Performance Shares \| Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	372,128	277,160	175,520
Number of shares, granted	173,373	152,373	148,081
Number of shares, vested	(62,119)	0	(39,245)
Number of shares, forfeited	(34,953)	(57,405)	(7,196)
Number of shares, ending balance	448,429	372,128	277,160

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Options) (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	0	0	9,500
Weighted average price, beginning balance	$ 0.00	$ 0.00	$ 37.69
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0.00	$ 0.00	$ 0.00
Number of shares, exercised	0	0	0
Weighted average price, exercised	$ 0.00	$ 0.00	$ 0.00
Number of shares, forfeited	0	0	(9,500)
Weighted average price, forfeited	$ 0.00	$ 0.00	$ 37.69
Number of shares, ending balance	0	0	0
Weighted average price, ending balance	$ 0.00	$ 0.00	$ 0.00

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) - Directors Plan - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	108,500	129,500	150,500
Weighted average price, beginning balance	$ 52.56	$ 54.15	$ 54.18
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0.00	$ 0.00	$ 0.00
Number of shares, exercised	0	0	0
Weighted average price, exercised	$ 0.00	$ 0.00	$ 0.00
Number of shares, forfeited	(21,000)	(21,000)	(21,000)
Weighted average price, forfeited	$ 57.63	$ 62.40	$ 54.35
Number of shares, ending balance	87,500	108,500	129,500
Weighted average price, ending balance	$ 51.34	$ 52.56	$ 54.15

Stock-Based Compensation (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) - Directors Plan	12 Months Ended
	Dec. 31, 2017 $ / shares shares
$31.30 - $41.21
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Minimum Limit	$ 31.30
Maximum limit	$ 41.21
Outstanding and exercisable options, number of shares \| shares	38,500
Outstanding and exercisable options weighted average remaining contractual life, years	1 year 10 months 12 days
Outstanding and exercisable options, weighted average exercise price	$ 37.58
$53.81 - $73.26
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Minimum Limit	53.81
Maximum limit	$ 73.26
Outstanding and exercisable options, number of shares \| shares	49,000
Outstanding and exercisable options weighted average remaining contractual life, years	2 years 1 month 15 days
Outstanding and exercisable options, weighted average exercise price	$ 62.15

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 12.8
Unrecognized compensation cost, expect to be capitalized	$ 1.3
Weighted average years over which this cost will be recognized	8 months 12 days
Incentive Stock Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance				2,000,000
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, granted	0	0	0
Expire years	10 years
Shares vested	0	0	0
Number of shares, ending balance	0	91,255	131,770
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance				7,230,000
Number of shares, ending balance	1,481,701
Vesting Period	3 years
Grant date fair value	$ 17.4	$ 4.5	$ 24.5
Number of shares, vested	(560,895)
Exercised intrinsic value	$ 12.3
Exercisable options intrinsic value	$ 32.6
Restricted stock weighted average remaining contractual term, years	10 months 24 days
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Shares vested	0	0	0
Maximum Number of Shares of Common Stock Previously Allowed for the Issuance	2,700,000
Vesting rate of options	20.00%
Directors Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Vesting Period	6 months
Exercisable options intrinsic value	$ 0.0
Director option awards	3,500
Weighted average remaining contractual term, years	2 years
2017 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	82.00%
2016 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	159.00%
2015 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%
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%
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	131.00%
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 Derivatives (Schedule of Non-designated Hedges Outstanding) (Details)	12 Months Ended
	Dec. 31, 2017 MMBTU $ / Unit bbl
Natural gas \| Swap \| If Nymex \| Jan'18 - Dec'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	20,000
Swap Price	3.013
Natural gas \| Swap \| If Nymex \| Apr'18 - Oct'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	10,000
Swap Price	2.990
Natural gas \| Basis Swap \| If Nymex \| Jan'18 - Mar'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	10,000
Swap Price	(0.208)
Natural gas \| Basis Swap \| If Nymex \| Nov'18 - Dec'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	10,000
Swap Price	(0.208)
Natural gas \| Three-way collar \| If Nymex \| Jan'18 - Mar'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	60,000
Floor Price	3.29
Ceiling Price	4.07
Subfloor Price	2.63
Natural gas \| Three-way collar \| If Nymex \| Apr'18 - Dec'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Mmbtu) \| MMBTU	20,000
Floor Price	3.00
Ceiling Price	3.51
Subfloor Price	2.50
Crude Oil \| Swap \| Wti Nymex \| Jan'18 - Dec'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Bbl) \| bbl	3,000
Swap Price	51.36
Crude Oil \| Collar \| Wti Nymex \| Jan'18 - Mar'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Bbl) \| bbl	500
Floor Price	55.00
Ceiling Price	59.50
Crude Oil \| Three-way collar \| Wti Nymex \| Jan'18 - Dec'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Bbl) \| bbl	2,000
Floor Price	47.50
Ceiling Price	56.08
Subfloor Price	37.50
Liquids \| Swap \| OPIS - Mont Belvieu \| Apr'18 - Sep'18
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (Bbl) \| bbl	1,000
Swap Price	31.16

Derivatives (Schedule Of Subsequent Non-designated Hedges) (Details)	2 Months Ended	12 Months Ended
	Feb. 23, 2018 MMBTU $ / Unit bbl	Dec. 31, 2017 MMBTU $ / Unit bbl
Apr'18 - Sep'18 \| Liquids \| OPIS - Mont Belvieu \| Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price		31.16
Hedged Volume (Bbl) \| bbl		1,000
Apr'18 - Oct'18 \| Natural gas \| If Nymex \| Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price		2.990
Hedged Volume (Mmbtu) \| MMBTU		10,000
Subsequent to December 31, 2017 \| Apr'18 - Sep'18 \| Natural gas \| If Nymex \| Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	2.925
Hedged Volume (Mmbtu) \| MMBTU	10,000
Subsequent to December 31, 2017 \| Apr'18 - Sep'18 \| Natural gas \| If Nymex \| Collar
Derivative Instruments, Gain (Loss) [Line Items]
Ceiling Price	2.67
Floor Price	2.97
Hedged Volume (Mmbtu) \| MMBTU	30,000
Subsequent to December 31, 2017 \| Apr'18 - Sep'18 \| Liquids \| OPIS - Mont Belvieu \| Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	34.10
Hedged Volume (Bbl) \| bbl	500
Subsequent to December 31, 2017 \| Feb'18 - Dec'18 \| Natural gas \| PEPL \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.678)
Hedged Volume (Mmbtu) \| MMBTU	10,000
Subsequent to December 31, 2017 \| Feb'18 - Dec'18 \| Natural gas \| NGPL Midcon \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.568)
Hedged Volume (Mmbtu) \| MMBTU	10,000
Subsequent to December 31, 2017 \| Apr'18 - Oct'18 \| Natural gas \| NGPL Texok \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.190)
Hedged Volume (Mmbtu) \| MMBTU	10,000
Subsequent to December 31, 2017 \| Jan'19 - Dec'19 \| Natural gas \| PEPL \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.728)
Hedged Volume (Mmbtu) \| MMBTU	10,000
Subsequent to December 31, 2017 \| Jan'19 - Dec'19 \| Natural gas \| NGPL Midcon \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.625)
Hedged Volume (Mmbtu) \| MMBTU	10,000
Subsequent to December 31, 2017 \| Jan'19 - Dec'19 \| Natural gas \| NGPL Texok \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.273)
Hedged Volume (Mmbtu) \| MMBTU	20,000
Subsequent to December 31, 2017 \| Jan'20 - Dec'20 \| Natural gas \| NGPL Texok \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	(0.280)
Hedged Volume (Mmbtu) \| MMBTU	20,000
Subsequent to December 31, 2017 \| Apr'18 - Dec'18 \| Oil \| Wti Nymex \| Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	60.00
Hedged Volume (Bbl) \| bbl	1,000

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 721	$ 0
Non-current derivative assets	0	377
Total derivatives assets	721	377
Current derivative liabilities	7,763	21,564
Non-current derivative liabilities	0	415
Total derivative liabilities	7,763	21,979
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Current derivative assets	721	0
Non-current derivative assets	0	377
Current derivative liabilities	7,763	21,564
Non-current derivative liabilities	$ 0	$ 415

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

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) on Derivatives

$ 14,732

$ (22,813)

Cash receipts on derivatives settled

173

9,658

Commodity Contract

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) on Derivatives

^[1]

$ 14,732

$ (22,813)

[1]	Amount settled during the period are gains of $173 and $9,658, respectively.

Fair Value Measurements Fair Value Measurements (Available-for-sale Securities) (Details) - Level 2 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 830	$ 0
Gross Unrealized Gains	102	0
Gross Unrealized Losses	0	0
Estimated Fair Value	$ 932	$ 0

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	$ (7,100)
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	721	$ 377
Liabilities	(7,763)	(21,979)
Financial assets (liabilities)	(7,042)	(21,602)
Commodity Contract \| Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	2,137	878
Liabilities	(8,973)	(15,358)
Financial assets (liabilities)	(6,836)	(14,480)
Commodity Contract \| Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	3,344	43
Liabilities	(3,550)	(7,165)
Financial assets (liabilities)	(206)	(7,122)
Commodity Contract \| Effect of Netting
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	(4,760)	(544)
Liabilities	4,760	544
Financial assets (liabilities)	$ 0	$ 0

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Beginning of period

$ (7,122)

$ 9,094

Included in earnings

^[1]

7,791

(9,042)

Settlements

(875)

(7,174)

End of period

(206)

(7,122)

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

$ 6,916

$ (16,216)

[1]	Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives.

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

12 Months Ended

Dec. 31, 2017

USD ($)

$ / Unit

Crude Oil | Collar

Derivative assets (liabilities), Fair Value | $

$ (77)

^[1]

Derivatives assets (liabilities), Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Crude Oil | Three-way collar

Derivative assets (liabilities), Fair Value | $

$ (3,473)

^[1]

Derivatives assets (liabilities), Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Crude Oil | Minimum | Collar

Derivative, Average Forward Price

0.00

Crude Oil | Minimum | Three-way collar

Derivative, Average Forward Price

0.00

Crude Oil | Maximum | Collar

Derivative, Average Forward Price

2.48

Crude Oil | Maximum | Three-way collar

Derivative, Average Forward Price

5.96

Natural gas | Three-way collar

Derivative assets (liabilities), Fair Value | $

$ 3,344

^[1]

Derivatives assets (liabilities), Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Natural gas | Minimum | Three-way collar

Derivative, Average Forward Price

0.00

Natural gas | Maximum | Three-way collar

Derivative, Average Forward Price

0.68

[1]	The commodity contracts detailed in this category include non-exchange-traded crude oil collars and crude and 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, 2017	Dec. 31, 2016
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	642,300	$ 640,100
Estimated fair value of long-term debt	$ 649,700	$ 649,900

Commitments And Contingencies (Details) - USD ($)	12 Months Ended
Commitments And Contingencies (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Commitments [Line Items]
Lease expiration date	Dec. 31, 2021
Future minimum rental payments under leases, year one	$ 2,700,000
Future minimum rental payments under leases, year two	600,000
Future minimum rental payments under leases, year three	400,000
Future minimum rental payments under leases, year four	100,000
Rent expense incurred	$ 8,800,000	$ 11,100,000	$ 12,900,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
2018	$ 6,168,000
2019	6,168,000
2020	6,168,000
2021	3,768,000
Maintenance	5,874,000
Interest	1,174,000
Capital leases, future minimum payments, average annual payment	$ 4,200,000
Capital lease fair market value percentage for purchase	10.00%
Repurchase of limited units outstanding	20.00%
Repurchase of limited units outstanding amount	$ 2,900	$ 5,000	$ 118,000
Drilling Equipment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 3,900,000

Equity Equity (Schedule of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Accumulated Other Comprehensive Income (Loss) [Abstract]
Unrealized appreciation on securities, before tax	$ 102	$ 0	$ 0
Tax expense	(39)	0	0
Unrealized appreciation on securities, net of tax	$ 63	$ 0	$ 0

Equity Equity (Reclassification out of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Abstract]
Balance at January 1:	$ 0	$ 0	$ 0
Unrealized appreciation before reclassifications	63	0	0
Amounts reclassified from accumulated other comprehensive income	0	0	0
Net current-period other comprehensive income	63	0	0
Balance at December 31:	$ 63	$ 0	$ 0

Equity Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Apr. 04, 2017
Class of Stock [Line Items]
Common stock, par value	$ 0.2	$ 0.2
Common stock, shares issued	52,880,134	51,494,318
Proceeds from Issuance of Common Stock	$ 18,623	$ 0	$ 0
At-the-Market Common Stock Program [Member]
Class of Stock [Line Items]
Common stock, par value					$ 0.20
Aggregate Offering Price					$ 100,000
Commission of the gross sales price by share paid percentage					2.00%
Common stock, shares issued	787,547			787,547

Industry Segment Information (Revenue From Different Segments) (Details)

3 Months Ended

12 Months Ended

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

rig

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

systems

Revenues

Oil and natural gas

$ 357,744,000

$ 294,221,000

$ 385,774,000

Contract drilling

174,720,000

122,086,000

265,668,000

Gas gathering and processing

207,176,000

185,870,000

202,789,000

Total revenues

$ 204,847,000

$ 188,488,000

$ 170,581,000

$ 175,724,000

$ 174,280,000

$ 153,408,000

$ 138,305,000

$ 136,184,000

739,640,000

602,177,000

854,231,000

Operating costs:

Oil and natural gas

130,789,000

120,184,000

166,046,000

Contract drilling

122,600,000

88,154,000

156,408,000

Gas gathering and processing

155,483,000

137,609,000

161,556,000

Total operating costs

408,872,000

345,947,000

484,010,000

Depreciation, depletion, and amortization

209,257,000

208,353,000

352,742,000

Impairments

161,563,000

1,634,628,000

Total expenses

618,129,000

715,863,000

2,471,380,000

General and administrative expense

(38,087,000)

(33,337,000)

(34,358,000)

Gain (loss) on disposition of assets

327,000

2,540,000

(7,229,000)

Gain (loss) on derivatives

14,732,000

(22,813,000)

26,345,000

Interest expense, net

(38,334,000)

(39,829,000)

(31,963,000)

Other

21,000

307,000

45,000

Income (loss) before income taxes

60,170,000

(206,818,000)

(1,664,309,000)

Identifiable assets:

Oil and natural gas

1,127,900,000

^[1]

965,159,000

^[2]

$ 1,218,036,000

^[3]

1,127,900,000

^[1]

965,159,000

^[2]

1,218,036,000

^[3]

Contract drilling

933,063,000

941,676,000

993,015,000

933,063,000

941,676,000

993,015,000

Gas gathering and processing

438,571,000

461,600,000

478,661,000

438,571,000

461,600,000

478,661,000

Total identifiable assets

2,499,534,000

^[4]

2,368,435,000

^[5]

2,689,712,000

^[6]

2,499,534,000

^[4]

2,368,435,000

^[5]

2,689,712,000

^[6]

Corporate land and building

56,854,000

58,188,000

49,890,000

56,854,000

58,188,000

49,890,000

Other corporate assets

25,064,000

^[7]

52,680,000

^[8]

60,240,000

^[9]

25,064,000

^[7]

52,680,000

^[8]

60,240,000

^[9]

Total assets

2,581,452,000

2,479,303,000

2,799,842,000

2,581,452,000

2,479,303,000

2,799,842,000

Capital expenditures:

Total capital expenditures

332,280,000

142,155,000

454,287,000

Oil and Natural Gas

Revenues

Oil and natural gas

357,744,000

294,221,000

385,774,000

Contract drilling

Gas gathering and processing

Total revenues

357,744,000

294,221,000

385,774,000

Operating costs:

Oil and natural gas

135,532,000

126,739,000

170,831,000

Contract drilling

Gas gathering and processing

Total operating costs

135,532,000

126,739,000

170,831,000

Depreciation, depletion, and amortization

101,911,000

113,811,000

251,944,000

Impairment of oil and natural gas properties

161,563,000

^[10]

1,599,348,000

^[11]

Total expenses

237,443,000

402,113,000

2,022,123,000

Total operating income (loss)

120,301,000

^[12]

(107,892,000)

^[13]

(1,636,349,000)

^[14]

General and administrative expense

Gain (loss) on disposition of assets

228,000

(324,000)

(147,000)

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

120,529,000

(108,216,000)

(1,636,496,000)

Identifiable assets:

Oil and natural gas

1,127,900,000

^[1]

965,159,000

^[2]

1,218,036,000

^[3]

1,127,900,000

^[1]

965,159,000

^[2]

1,218,036,000

^[3]

Contract drilling

Gas gathering and processing

Total identifiable assets

1,127,900,000

^[4]

965,159,000

^[5]

1,218,036,000

^[6]

1,127,900,000

^[4]

965,159,000

^[5]

1,218,036,000

^[6]

Corporate land and building

Other corporate assets

^[7]

^[8]

^[9]

^[7]

^[8]

^[9]

Total assets

1,127,900,000

965,159,000

1,218,036,000

1,127,900,000

965,159,000

1,218,036,000

Capital expenditures:

Total capital expenditures

270,443,000

89,562,000

267,944,000

Non-cash ceiling test write-down net of tax

100,600,000

Drilling

Revenues

Oil and natural gas

Contract drilling

188,172,000

122,086,000

287,767,000

Gas gathering and processing

Total revenues

188,172,000

122,086,000

287,767,000

Operating costs:

Oil and natural gas

Contract drilling

134,432,000

88,154,000

174,757,000

Gas gathering and processing

Total operating costs

134,432,000

88,154,000

174,757,000

Depreciation, depletion, and amortization

56,370,000

46,992,000

56,135,000

Impairment of contract drilling equipment

^[10]

8,314,000

^[11]

Total expenses

190,802,000

135,146,000

239,206,000

Total operating income (loss)

(2,630,000)

^[12]

(13,060,000)

^[13]

48,561,000

^[14]

General and administrative expense

Gain (loss) on disposition of assets

(776,000)

3,184,000

(7,516,000)

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

(3,406,000)

(9,876,000)

41,045,000

Identifiable assets:

Oil and natural gas

^[1]

^[2]

^[3]

^[1]

^[2]

^[3]

Contract drilling

933,063,000

941,676,000

993,015,000

933,063,000

941,676,000

993,015,000

Gas gathering and processing

Total identifiable assets

933,063,000

^[4]

941,676,000

^[5]

993,015,000

^[6]

933,063,000

^[4]

941,676,000

^[5]

993,015,000

^[6]

Corporate land and building

Other corporate assets

^[7]

^[8]

^[9]

^[7]

^[8]

^[9]

Total assets

933,063,000

941,676,000

$ 993,015,000

933,063,000

941,676,000

993,015,000

Capital expenditures:

Total capital expenditures

36,148,000

19,134,000

84,802,000

Number of drilling rigs removed from service | rig

Mid-Stream

Revenues

Oil and natural gas

Contract drilling

Gas gathering and processing

277,049,000

237,785,000

268,012,000

Total revenues

277,049,000

237,785,000

268,012,000

Operating costs:

Oil and natural gas

Contract drilling

Gas gathering and processing

220,613,000

182,969,000

221,994,000

Total operating costs

220,613,000

182,969,000

221,994,000

Depreciation, depletion, and amortization

43,499,000

45,715,000

43,676,000

Impairment of gas gathering systems

^[10]

26,966,000

^[11]

Total expenses

264,112,000

228,684,000

292,636,000

Total operating income (loss)

12,937,000

^[12]

9,101,000

^[13]

(24,624,000)

^[14]

General and administrative expense

Gain (loss) on disposition of assets

25,000

(302,000)

465,000

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

12,962,000

8,799,000

(24,159,000)

Identifiable assets:

Oil and natural gas

^[1]

^[2]

$ 0

^[3]

^[1]

^[2]

^[3]

Contract drilling

Gas gathering and processing

438,571,000

461,600,000

478,661,000

438,571,000

461,600,000

478,661,000

Total identifiable assets

438,571,000

^[4]

461,600,000

^[5]

478,661,000

^[6]

438,571,000

^[4]

461,600,000

^[5]

478,661,000

^[6]

Corporate land and building

Other corporate assets

^[7]

^[8]

^[9]

^[7]

^[8]

^[9]

Total assets

438,571,000

461,600,000

478,661,000

438,571,000

461,600,000

478,661,000

Capital expenditures:

Total capital expenditures

22,168,000

16,796,000

63,476,000

Other Segments

Revenues

Oil and natural gas

Contract drilling

Gas gathering and processing

Gas gathering and processing

Total operating costs

Depreciation, depletion, and amortization

7,477,000

1,835,000

987,000

Impairments

^[10]

^[11]

Total expenses

7,477,000

1,835,000

987,000

Total operating income (loss)

(7,477,000)

^[12]

(1,835,000)

^[13]

(987,000)

^[14]

General and administrative expense

(38,087,000)

(33,337,000)

(34,358,000)

Gain (loss) on disposition of assets

850,000

(18,000)

(31,000)

Gain (loss) on derivatives

14,732,000

(22,813,000)

26,345,000

Interest expense, net

(38,334,000)

(39,829,000)

(31,963,000)

Other

21,000

307,000

45,000

Income (loss) before income taxes

(68,295,000)

(97,525,000)

(40,949,000)

Identifiable assets:

Oil and natural gas

^[1]

^[2]

^[3]

^[1]

^[2]

^[3]

Contract drilling

Gas gathering and processing

Total identifiable assets

^[4]

^[5]

^[6]

^[4]

^[5]

^[6]

Corporate land and building

56,854,000

58,188,000

49,890,000

56,854,000

58,188,000

49,890,000

Other corporate assets

25,064,000

^[7]

52,680,000

^[8]

60,240,000

^[9]

25,064,000

^[7]

52,680,000

^[8]

60,240,000

^[9]

Total assets

81,918,000

110,868,000

110,130,000

81,918,000

110,868,000

110,130,000

Capital expenditures:

Total capital expenditures

3,521,000

16,663,000

38,065,000

Intersubsegment Eliminations

Revenues

Oil and natural gas

Contract drilling

(13,452,000)

(22,099,000)

Gas gathering and processing

(69,873,000)

(51,915,000)

(65,223,000)

Total revenues

(83,325,000)

(51,915,000)

(87,322,000)

Operating costs:

Oil and natural gas

(4,743,000)

(6,555,000)

(4,785,000)

Contract drilling

(11,832,000)

(18,349,000)

Gas gathering and processing

(65,130,000)

(45,360,000)

(60,438,000)

Total operating costs

(81,705,000)

(51,915,000)

(83,572,000)

Depreciation, depletion, and amortization

Impairments

^[10]

^[11]

Total expenses

(81,705,000)

(51,915,000)

(83,572,000)

Total operating income (loss)

(1,620,000)

^[12]

^[13]

(3,750,000)

^[14]

General and administrative expense

Gain (loss) on disposition of assets

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

(1,620,000)

(3,750,000)

Identifiable assets:

Oil and natural gas

^[1]

^[2]

^[3]

^[1]

^[2]

^[3]

Contract drilling

Gas gathering and processing

Total identifiable assets

^[4]

^[5]

^[6]

^[4]

^[5]

^[6]

Corporate land and building

Other corporate assets

^[7]

^[8]

^[9]

^[7]

^[8]

^[9]

Total assets

$ 0

Capital expenditures:

Total capital expenditures

Oil and Natural Gas

Operating costs:

Impairment of oil and natural gas properties

161,563,000

1,599,348,000

Capital expenditures:

Non-cash ceiling test write-down net of tax

100,600,000

1,000,000,000

Gas Gathering and Processing Equipment

Operating costs:

Impairment of gas gathering systems

$ 0

$ 27,000,000

Capital expenditures:

Number of gas gathering systems impaired | systems

[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]	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
[8]	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
[9]	Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
[10]	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax).
[11]	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). Impairment for contract drilling equipment includes an $8.3 million pre-tax write-down for 30 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek.
[12]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income, or income taxes.
[13]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.
[14]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.

Selected Quarterly Financial Information (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Revenues

$ 204,847

$ 188,488

$ 170,581

$ 175,724

$ 174,280

$ 153,408

$ 138,305

$ 136,184

$ 739,640

$ 602,177

$ 854,231

Gross profit (loss)

^[1]

37,211

27,181

24,462

32,657

36,782

(26,893)

(73,830)

(49,745)

Net income (loss)

$ 89,155

$ 3,705

$ 9,059

$ 15,929

$ 1,683

$ (24,022)

$ (72,136)

$ (41,149)

$ 117,848

$ (135,624)

$ (1,037,361)

Net income (loss) per common share:

Basic

$ 1.74

$ 0.07

$ 0.18

$ 0.32

$ 0.03

^[2]

$ (0.48)

^[2]

$ (1.44)

^[2]

$ (0.83)

^[2]

$ 2.31

$ (2.71)

$ (21.12)

Diluted

$ 1.71

^[2]

$ 0.07

^[2]

$ 0.17

^[2]

$ 0.31

^[2]

$ 0.03

^[2]

$ (0.48)

^[2]

$ (1.44)

^[2]

$ (0.83)

^[2]

$ 2.28

$ (2.71)

$ (21.12)

[1]	Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss).
[2]	The earnings (loss) per share for the year's four quarters does not equal annual income (loss) per share.

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized costs:
Proved properties	$ 5,712,813	$ 5,446,305	$ 5,401,618
Unproved properties not being amortized	296,764	314,867	337,099
Capitalized costs gross	6,009,577	5,761,172	5,738,717
Accumulated depreciation, depletion, amortization, and impairment	(4,996,696)	(4,900,304)	(4,631,404)
Net capitalized costs	1,012,881	860,868	1,107,313
Costs incurred:
Unproved properties acquired	47,029	21,675	41,777
Proved properties acquired	47,638	564	179
Exploration	14,811	17,325	19,222
Development	160,941	80,582	208,845
Asset retirement obligation	(3,613)	(30,906)	(5,693)
Total costs incurred	$ 266,806	$ 89,240	$ 264,330

Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unproved properties acquired and wells in progress	$ 296,764	$ 314,867	$ 337,099
2017
Unproved properties acquired and wells in progress	50,447
2016
Unproved properties acquired and wells in progress	22,092
2015
Unproved properties acquired and wells in progress	40,254
2014 and prior
Unproved properties acquired and wells in progress	$ 183,971

Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil and Gas Disclosures [Abstract]
Revenues	$ 347,285	$ 282,742	$ 371,335
Production costs	(107,332)	(108,822)	(152,560)
Depreciation, depletion, amortization, and impairment	(96,392)	(268,901)	(1,844,726)
Results of operations, income before income taxes	143,561	(94,981)	(1,625,951)
Income tax (expense) benefit	(56,376)	32,696	612,496
Results of operations for producing activities (excluding corporate overhead and financing costs)	$ 87,185	$ (62,285)	$ (1,013,455)

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, 2017

MBoe

bbl

Mcf

Dec. 31, 2016

MBoe

bbl

Mcf

Dec. 31, 2015

MBoe

bbl

Mcf

Proved developed and undeveloped reserves:

Beginning of year (MBoe) | MBoe

117,774

135,233

179,023

Revision of previous estimate (MBoe) | MBoe

11,444

(8,300)

^[1]

(36,573)

^[1]

Extension and discovery (MBoe) | MBoe

14,975

5,690

6,651

Infill reserves in existing proved fields (MBoe) | MBoe

16,123

7,504

6,304

Purchase of mineral in place (MBoe) | MBoe

5,768

262

Production (MBoe) | MBoe

(15,996)

(17,277)

(19,981)

Sales (MBoe) | MBoe

(314)

(5,338)

(191)

End of year (MBoe) | MBoe

149,774

117,774

135,233

Proved developed reserves:

Beginning of year (MBoe) | MBoe

99,079

115,296

136,790

End of year (MBoe) | MBoe

112,961

99,079

115,296

Proved undeveloped reserves

Beginning of year (MBoe) | MBoe

18,695

19,937

42,233

End of year (MBoe) | MBoe

36,813

18,695

19,937

Oil (bbls)

Proved developed and undeveloped reserves:

Beginning of year

15,696

16,735

22,667

Revision of previous estimates

730

(549)

^[1]

(3,954)

^[1]

Extensions and discoveries

2,235

1,816

1,208

Infill reserves in existing proved fields

1,632

663

670

Purchases of minerals in place

2,019

114

Production

(2,715)

(2,974)

(3,783)

Sales

(84)

(109)

(73)

End of year

19,513

15,696

16,735

Proved developed reserves:

Beginning of year

12,724

14,679

17,448

End of year

14,862

12,724

14,679

Proved undeveloped reserves

Beginning of year

2,972

2,056

5,219

End of year

4,651

2,972

2,056

Natural Gas Liquids (bbls)

Proved developed and undeveloped reserves:

Beginning of year

34,482

37,687

48,529

Revision of previous estimates

4,325

(2,473)

^[1]

(9,367)

^[1]

Extensions and discoveries

4,520

1,588

1,948

Infill reserves in existing proved fields

5,779

2,724

1,861

Purchases of minerals in place

1,197

Production

(4,737)

(5,014)

(5,274)

Sales

(80)

(73)

(10)

End of year

45,486

34,482

37,687

Proved developed reserves:

Beginning of year

28,502

31,218

35,850

End of year

33,358

28,502

31,218

Proved undeveloped reserves

Beginning of year

5,980

6,469

12,679

End of year

12,128

5,980

6,469

Natural gas (Mcf)

Proved developed and undeveloped reserves:

Beginning of year | Mcf

405,579

484,868

646,961

Revision of previous estimates | Mcf

38,330

(31,670)

^[1]

(139,514)

^[1]

Extensions and discoveries | Mcf

49,321

13,720

20,974

Infill reserves in existing proved fields | Mcf

52,270

24,704

22,641

Purchases of minerals in place | Mcf

15,313

630

Production | Mcf

(51,260)

(55,735)

(65,546)

Sales | Mcf

(903)

(30,938)

(648)

End of year | Mcf

508,650

405,579

484,868

Proved developed reserves:

Beginning of year | Mcf

347,121

416,395

500,950

End of year | Mcf

388,446

347,121

416,395

Proved undeveloped reserves

Beginning of year | Mcf

58,458

68,473

146,011

End of year | Mcf

120,204

58,458

68,473

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

Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash flows	$ 3,347,396	$ 2,030,925	$ 2,475,898
Future production costs	(1,308,244)	(861,625)	(1,017,777)
Future development costs	(369,560)	(173,446)	(228,445)
Future income tax expenses	(234,152)	(141,752)	(230,544)
Future net cash flows	1,435,440	854,102	999,132
10% annual discount for estimated timing of cash flows	(628,270)	(335,892)	(409,646)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves	$ 807,170	$ 518,210	$ 589,486	$ 1,435,744
Percentage of annual discount for estimated timing of cash flows	10.00%	10.00%	10.00%

Supplemental Oil And Gas Disclosures (Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reserve Quantities [Line Items]
Sales and transfers of oil and natural gas produced, net of production costs	$ (239,953)	$ (173,920)	$ (218,115)
Net changes in prices and production costs	236,126	(94,026)	(1,356,333)
Revisions in quantity estimates and changes in production timing	87,239	(51,979)	(213,945)
Extensions, discoveries, and improved recovery, less related costs	102,965	84,738	95,671
Changes in estimated future development costs	(5,194)	70,976	227,857
Previously estimated cost incurred during the period	36,044	16,602	59,117
Purchases of minerals in place	51,686	2,652	0
Sales of minerals in place	(1,447)	(17,248)	(3,338)
Accretion of discount	57,517	69,069	209,979
Net change in income taxes	(33,389)	44,241	562,838
Other-net	(2,634)	(22,381)	(209,989)
Net change	288,960	(71,276)	(846,258)
Beginning of year	518,210	589,486	1,435,744
End of year	$ 807,170	$ 518,210	$ 589,486

Supplemental Oil And Gas Disclosures Supplemental Oil and Gas Disclosures (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 $ / Unit
Oil (bbls)
Average Sales Prices	51.34
Natural Gas Liquids (bbls)
Average Sales Prices	31.83
Natural gas (Mcf)
Average Sales Prices	2.98

Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	$ 3,773	$ 5,199	$ 5,039
Additions charged to costs and expenses	348	785	1,191
Deductions and net write-offs	(1,671)	(2,211)	(1,031)
Balance at end of period	$ 2,450	$ 3,773	$ 5,199