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Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 10, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
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	Accelerated Filer
Entity Common Stock, Shares Outstanding		51,650,140
Entity Well-known Seasoned Issuer	No
Entity Public Float			$ 495,132,341
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 893	$ 835
Accounts receivable (less allowance for doubtful accounts of $3,773 and $5,199 at December 31, 2016 and 2015, respectively)	83,954	79,941
Materials and supplies	3,340	3,565
Current derivative asset (Note 12)	0	10,186
Current income tax receivable	99	21,002
Current deferred tax asset (Note 8)	25,211	14,206
Assets held for sale	0	615
Prepaid expenses and other	7,699	9,908
Total current assets	121,196	140,258
Oil and natural gas properties, on the full cost method:
Proved properties	5,446,305	5,401,618
Unproved properties not being amortized	314,867	337,099
Drilling equipment	1,565,268	1,567,560
Gas gathering and processing equipment	705,859	689,063
Saltwater disposal systems	60,638	60,316
Corporate land and building	59,066	49,890
Transportation equipment	32,842	40,072
Other	48,590	45,489
Property, plant and equipment, gross, total	8,233,435	8,191,107
Less accumulated depreciation, depletion, amortization, and impairment	5,952,330	5,609,980
Net property and equipment	2,281,105	2,581,127
Goodwill (Note 2)	62,808	62,808
Non-current derivative asset (Note 12)	377	968
Other assets	13,817	14,681
Total assets	2,479,303	2,799,842
Current liabilities:
Accounts payable	88,793	87,413
Accrued liabilities (Note 5)	39,651	46,918
Current derivative liabilities (Note 12)	21,564	0
Current portion of other long-term liabilities (Note 6)	14,907	16,560
Total current liabilities	164,915	150,891
Long-term debt less unamortized discount and debt issuance costs (Note 6)	800,917	918,995
Non-current derivative liabilities (Note 12)	415	285
Other long-term liabilities (Note 6)	103,064	140,341
Deferred income taxes (Note 8)	215,922	275,750
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, 51,494,318 and 50,413,101 shares issued as of December 31, 2016 and 2015, respectively	10,016	9,831
Capital in excess of par value	502,500	486,571
Retained earnings	681,554	817,178
Total shareholders' equity	1,194,070	1,313,580
Total liabilities and shareholders' equity	$ 2,479,303	$ 2,799,842

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 3,773	$ 5,199
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	51,494,318	50,413,101

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Oil and natural gas	$ 294,221	$ 385,774	$ 740,079
Contract drilling	122,086	265,668	476,517
Gas gathering and processing	185,870	202,789	356,348
Total revenues	602,177	854,231	1,572,944
Operating costs:
Oil and natural gas	120,184	166,046	187,916
Contract drilling	88,154	156,408	274,933
Gas gathering and processing	137,609	161,556	306,831
Total operating costs	345,947	484,010	769,680
Depreciation, depletion, and amortization	208,353	352,742	402,888
Impairments	161,563	1,634,628	158,069
General and administrative	33,337	34,358	41,027
(Gain) loss on disposition of assets	(2,540)	7,229	(8,953)
Total expenses	746,660	2,512,967	1,362,711
Income (loss) from operations	(144,483)	(1,658,736)	210,233
Other income (expense):
Interest, net	(39,829)	(31,963)	(17,371)
Gain (loss) on derivatives	(22,813)	26,345	30,147
Other	307	45	(70)
Total other income (expense)	(62,335)	(5,573)	12,706
Income (loss) before income taxes	(206,818)	(1,664,309)	222,939
Income tax expense (benefit):
Current	15	(20,616)	9,378
Deferred	(71,209)	(606,332)	77,285
Total Income tax expense (benefit)	(71,194)	(626,948)	86,663
Net income (loss)	$ (135,624)	$ (1,037,361)	$ 136,276
Net income (loss) per common share:
Basic	$ (2.71)	$ (21.12)	$ 2.80
Diluted	$ (2.71)	$ (21.12)	$ 2.78

Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Capital In Excess of Par Value	Retained Earnings
Beginning balances at Dec. 31, 2013	$ 2,173,392	$ 9,659	$ 445,470	$ 1,718,263
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	136,276	0	0	136,276
Activity in employee compensation plans	22,726	73	22,653	0
Ending balances at Dec. 31, 2014	2,332,394	9,732	468,123	1,854,539
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,037,361)	0	0	(1,037,361)
Activity in employee compensation plans	18,547	99	18,448	0
Ending balances at Dec. 31, 2015	1,313,580	9,831	486,571	817,178
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(135,624)	0	0	(135,624)
Activity in employee compensation plans	16,114	185	15,929	0
Ending balances at Dec. 31, 2016	$ 1,194,070	$ 10,016	$ 502,500	$ 681,554

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Activity in employee compensation plans (shares)	1,081,217	819,289	486,808

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES:
Net income (loss)	$ (135,624)	$ (1,037,361)	$ 136,276
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	208,353	352,742	402,888
Impairments (Note 2)	161,563	1,634,628	158,069
Amortization of debt issuance costs and debt discount	2,122	2,088	2,055
(Gain) loss on derivatives	22,813	(26,345)	(30,147)
Cash (payments) receipts on derivatives settled	9,658	46,615	(6,038)
(Gain) loss on disposition of assets	(3,127)	7,229	(8,953)
Deferred tax expense (benefit)	(71,209)	(606,332)	77,285
Employee stock compensation plans	13,812	21,468	24,320
Bad debt expense	785	1,191	3,562
ARO liability accretion	2,779	3,453	4,599
Other, net	(6,037)	(1,517)	1,068
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(11,796)	105,426	(60,800)
Materials and supplies	225	1,507	2,602
Prepaid expenses and other	2,585	7,134	6,550
Accounts payable	27,400	(20,306)	4,715
Accrued liabilities	(4,388)	(22,920)	(1,297)
Income taxes	20,903	(21,482)	(6,994)
Contract advances	(687)	(274)	(767)
Net cash provided by operating activities	240,130	446,944	708,993
INVESTING ACTIVITIES:
Capital expeditures	(186,149)	(561,453)	(981,374)
Producing property and other acquisitions	(564)	(179)	(5,723)
Proceeds from disposition of property and equipment	74,823	11,854	66,197
Other	919	0	303
Net cash used in investing activities	(110,971)	(549,778)	(920,597)
FINANCING ACTIVITIES:
Borrowings under line of credit	251,398	618,500	725,800
Payments under line of credit	(371,600)	(503,500)	(559,800)
Payments on capitalized leases	(3,694)	(3,549)	(2,392)
Proceeds from exercise of stock options	0	0	1,083
Tax (expense) benefit from stock compensation	(376)	(3,207)	1,614
Increase (decrease) in book overdrafts (Note 2)	(4,829)	(5,624)	27,755
Net cash provided by (used in) financing activities	(129,101)	102,620	194,060
Net increase (decrease) in cash and cash equivalents	58	(214)	(17,544)
Cash and cash equivalents, beginning of year	835	1,049	18,593
Cash and cash equivalents, end of year	893	835	1,049
Supplemental disclosure of cash flow information:
Interest paid (net of capitalization)	35,690	30,910	13,620
Income taxes	42	3,540	15,898
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	21,190	105,157	(31,968)
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	30,897	5,694	37,689
Non-cash additions to property, plant, and equipment acquired under capital leases	$ 0	$ 0	$ (28,202)

Organization	12 Months Ended
Organization	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	ORGANIZATION Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like terms refer to Unit Corporation and its subsidiaries. We are primarily engaged in the exploration, development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are located principally in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream. Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company, we explore, develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are located mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, 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 as well as for a wide range of other oil and natural gas companies. Our drilling operations are mainly located in Oklahoma, Texas, Wyoming, North Dakota, and to a lesser extent in Louisiana and Kansas. Our contract drilling segment experienced more demand for natural gas drilling as opposed to drilling for oil and NGLs before 2008. Since 2008, operators have been focusing more on drilling for oil and NGLs. Mid-Stream. Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

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, 2016, all of our contracts were daywork contracts of which eight were multi-well and had durations which ranged from six months to two years, seven of which expire in 2017 and one expiring in 2018. 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, 2016 and 2015, book overdrafts were $17.3 million and $22.1 million, respectively.

Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.

Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues:



	2016		2015		2014
Oil and Natural Gas:
Sunoco Logistics Partners L.P.	24	%	19	%	14	%
Valero Energy Corporation	11	%	15	%	24	%
Drilling:
QEP Resources, Inc.	28	%	25	%	19	%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	18	%	7	%	9	%
Mid-Stream:
ONEOK Partners, L.P.	30	%	29	%	44	%
Koch Energy Services, LLC	11	%	9	%	2	%
Range Resources Corporation	10	%	5	%	2	%
Tenaska Resources, LLC	10	%	18	%	22	%
Laclede Group, Inc.	9	%	12	%	16	%

We had a concentration of cash of $8.3 million and $2.3 million at December 31, 2016 and 2015, 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, 2016 and determined there was no material risk at that time. At December 31, 2016, the fair values of the net 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, 2016
	(In millions)
Canadian Imperial Bank of Commerce	$	11.1
Bank of Montreal	8.0
Scotiabank	2.5
Total liabilities	$	21.6

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

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

On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable in the current environment and based on the estimated market value from third-party assessments, we recorded a write-down of approximately $74.3 million, pre-tax. During the first quarter of 2015, we sold one of these drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During the third quarter, we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.

In 2016, our mid-stream segment had no impairments.

In 2015, our mid-stream segment incurred a $27.0 million, pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems.

In 2014, our mid-stream segment incurred a $7.1 million, pre-tax write-down of three of its systems, Weatherford, Billy Rose, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems.

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 2016, 2015, and 2014, interest of approximately $15.3 million, $21.7 million, and $32.2 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2016, 2015, or 2014. There were no additions to goodwill in 2016, 2015, or 2014. Based on our impairment test performed as of December 31, 2016, the fair value of our drilling segment exceeded its carrying value by 16%. Goodwill of $1.3 million is deductible for tax purposes.

Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $15.4 million, $19.2 million, and $23.7 million were capitalized in 2016, 2015, and 2014, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $6.24, $12.30, and $14.82 per Boe in 2016, 2015, and 2014, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our unproved properties and wells in progress totaling $314.9 million are excluded from the DD&A calculation.

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

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

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

We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $73.7 million in 2014, $114.4 million in 2015, and $7.6 million in 2016 of costs being added to the total of our capitalized costs being amortized. We incurred a $76.7 million pre-tax ($47.7 million net of tax) non-cash ceiling test write-down of our oil and natural gas properties in 2014 due to the inclusion of the impaired value of those unproved properties and a reduction of the 12-month average commodity prices during the year. 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. There was not a ceiling test write-down for the fourth quarter of 2016.

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. We did not eliminate any revenue or expenses in our contract drilling segment during 2016. We eliminated revenue of $22.1 million and $89.5 million for 2015 and 2014, respectively from our contract drilling segment and eliminated the associated operating expense of $18.3 million and $62.4 million during 2015 and 2014, respectively, yielding $3.8 million and $27.1 million during 2015 and 2014, respectively, as a reduction to the carrying value of our oil and natural gas properties.

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

Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. 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. 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. Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.

The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We have $0.4 million of unrecognized tax benefits.

Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2016 balancing position to be approximately 3.7 Bcf on under-produced properties and approximately 3.3 Bcf on over-produced properties. We have recorded a receivable of $2.8 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.8 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.

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

New Accounting Standards

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the subsequent measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. This amendment will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe this ASU will 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 amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have 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. This amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe this ASU will have a material impact on our financial statements.

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to 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 amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments primarily impact classification within the statement of cash flows between financial and operating activities. This will not have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. Under the new guidance, lessees will be required 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 amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact these amendments will have on our financial statements.

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require current deferred tax assets to be combined with noncurrent deferred tax assets. The amendments will not have a material impact on our financial statements.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This guidance affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASU rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities— Oil and Gas, effective upon the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We will adopt these amendments effective January 1, 2018. We have begun the identification of revenue within the scope of the guidance. Our evaluation of the impact of the new guidance on our financial statements is on-going. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative effect adjustment to retained earnings at the date of adoption . We currently believe we will adopt the cumulative effect method.

Adopted Standards

Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have maintained debt issuance costs associated with our credit agreement as an asset and amortize these fees over the life of the credit agreement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We have adopted these amendments during the first quarter of 2016. Previously, debt issuance costs associated with the Notes was classified as a long-term asset on the balance sheet, but with ASU 2015-03, it is presented as a direct deduction from the carrying amount of the recognized debt liability. This is also reflected in Note 6 – Long-Term Debt and Other Long-term Liabilities.

Presentation of Financial Statements-Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The FASB has issued ASU 2014-15. This is intended to define management's responsibility to evaluate whether there is substantial doubt about an organization's ability to continue as a going concern and to provide related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company's ability to continue as a going concern within one year from the date financial statements are issued. The amendments are effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. We have adopted these amendments and began performing the management assessment beginning with the fiscal year end of December 31, 2016. There are no considerations or events that raise substantial doubt about our ability to continue as a going concern.

Divestitures	12 Months Ended
Divestitures	Dec. 31, 2016
Acquisitions and divestitures [Abstract]
Divestitures	DIVESTITURES Oil and Natural Gas We had non-core asset sales with proceeds, net of related expenses, of $33.1 million, $1.9 million, and $67.2 million in 2014, 2015, and 2016, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized. Contract Drilling During 2014, we sold four drilling rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $16.3 million net book value of the drilling rigs, both in the aggregate and for each drilling rig, resulting in a gain of $9.6 million. During the first quarter of 2015, we sold one drilling rig to an unaffiliated third party for $0.3 million resulting in a gain of $7,900. During the third quarter, we sold 30 drilling rigs, some old top drive equipment, and drill pipe in an auction. The proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. 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.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-Section 50
-Paragraph 4
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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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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Reference 10: 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=73530397&loc=d3e4922-128472

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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=73530397&loc=SL65897772-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Earnings (Loss) Per Share

12 Months Ended

Dec. 31, 2016

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, 2014:
Basic earnings per common share	$	136,276		48,611	$	2.80
Effect of dilutive stock options, restricted stock, and SARs	—			472	(0.02		)
Diluted earnings per common share	$	136,276		49,083	$	2.78
For the year ended December 31, 2015:
Basic earnings (loss) per common share	$	(1,037,361	)	49,110	$	(21.12	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted earnings (loss) per common share	$	(1,037,361	)	49,110	$	(21.12	)
For the year ended December 31, 2016:
Basic earnings (loss) per common share	$	(135,624	)	50,029	$	(2.71	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted earnings (loss) per common share	$	(135,624	)	50,029	$	(2.71	)

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:



	2016		2015		2014
Options and SARs	199,755		261,270		73,500
Average exercise price	$	48.79	$	50.34	$	64.43

Accrued Liabilities

12 Months Ended

Dec. 31, 2016

Accrued Liabilities [Abstract]

Accrued Liabilities [Text Block]

ACCRUED LIABILITIES

Accrued liabilities consisted of the following as of December 31:



	2016		2015
	(In thousands)
Employee costs	$	15,394	$	12,641
Lease operating expenses	10,075		17,220
Interest payable	6,524		6,321
Third-party credits	2,998		3,326
Taxes	2,219		3,767
Other	2,441		3,643
Total accrued liabilities	$	39,651	$	46,918

Long-Term Debt And Other Long-Term Liabilities

12 Months Ended

Dec. 31, 2016

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:



	2016			2015
	(In thousands)
Credit agreement with average interest rates of 2.8% and 2.6% at December 31, 2016 and 2015, respectively	$	160,800		$	281,000
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	$	810,800		$	931,000
Less: unamortized discount	(2,804		)	(3,338		)
Less: debt issuance costs, net	(7,079		)	(8,667		)
Total long-term debt	$	800,917		$	918,995

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 midstream affiliate, Superior Pipeline Company, L.L.C.

The amount of the borrowing base–which is subject to redetermination by the lenders on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The October 2016 redetermination did not result in 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 in any event cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at anytime, without a premium or penalty. At December 31, 2016, we had $160.8 million outstanding borrowings under our credit agreement.

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

The credit agreement prohibits, among other things:


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


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


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

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


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

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 quarter 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, 2016, we were in compliance with the covenants contained in the credit agreement.

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

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors and the Trustee (as supplemented, the 2011 Indenture), establishing the terms and providing for the issuance of the Notes. The Guarantors are all of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through dividends, loans, advances or otherwise.

On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of December 31, 2016.

Other Long-Term Liabilities

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



	2016		2015
	(In thousands)
ARO liability	$	70,170	$	98,297
Capital lease obligations	18,918		22,466
Workers’ compensation	15,163		16,551
Separation benefit plans	4,943		9,886
Deferred compensation plan	4,578		4,244
Gas balancing liability	3,789		5,047
Other	410		410
	117,971		156,901
Less current portion	14,907		16,560
Total other long-term liabilities	$	103,064	$	140,341

Estimated annual principal payments under the terms of debt and other long-term liabilities from 2017 through 2021 are $14.9 million, $5.5 million, $47.9 million, $170.0 million, and $655.8 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 $3.7 million is included in current portion of other long-term liabilities and the non-current portion of $15.2 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2016. These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $7.7 million and $1.9 million, respectively at December 31, 2016. Annual payments, net of maintenance and interest, average $4.1 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, 2016 are as follows:



	Amount
Ending December 31,	(In thousands)
2017	$	6,168
2018	6,168
2019	6,168
2020	6,168
2021	3,769
Total future payments	28,441
Less payments related to:
Maintenance	7,659
Interest	1,864
Present value of future minimum payments	$	18,918

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

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:



	2016			2015
	(In thousands)
ARO liability, January 1:	$	98,297		$	100,567
Accretion of discount	2,779			3,453
Liability incurred	584			6,754
Liability settled	(1,215		)	(2,893		)
Liability sold	(10,882		)	(421		)
Revision of estimates ⁽¹⁾	(19,393		)	(9,163		)
ARO liability, December 31:	70,170			98,297
Less current portion	2,906			3,965
Total long-term ARO liability	$	67,264		$	94,332

_________________________


(1)	Plugging liability estimates were revised in both 2016 and 2015 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows:



	2016			2015			2014
	(In thousands)
Income tax expense (benefit) computed by applying the statutory rate	$	(72,386	)	$	(582,508	)	$	78,029
State income tax expense (benefit), net of federal benefit	(5,687		)	(45,768		)	6,131
Restricted stock shortfall	5,465			—			—
Statutory depletion and other	1,414			1,328			2,503
Income tax expense (benefit)	$	(71,194	)	$	(626,948	)	$	86,663

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



	2016			2015			2014
	(In thousands)
Current taxes:
Federal	$	—		$	(20,612	)	$	8,594
State	15			(4		)	784
	15			(20,616		)	9,378
Deferred taxes:
Federal	(62,923		)	(535,691		)	68,360
State	(8,286		)	(70,641		)	8,925
	(71,209		)	(606,332		)	77,285
Total provision	$	(71,194	)	$	(626,948	)	$	86,663

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



	2016			2015
	(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals	$	53,967		$	56,479
Net operating loss carryforward	190,603			140,863
Alternative minimum tax and research and development tax credit carryforward	5,409			5,409
	249,979			202,751
Deferred tax liability:
Depreciation, depletion, amortization, and impairment	(440,690		)	(464,295		)
Net deferred tax liability	(190,711		)	(261,544		)
Current deferred tax asset	25,211			14,206
Non-current—deferred tax liability	$	(215,922	)	$	(275,750	)

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, 2016, we have federal net operating loss carryforwards of approximately $485.0 million which expire from 2021 to 2036.

We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal or state income tax examinations by tax authorities for years before 2013. During 2014, we recognized a tax benefit relating to a research and development tax credit carryforward in conjunction with our BOSS drilling rig activities. Due to the nature and subjectivity surrounding the research and development credit and historical challenges by the IRS against companies who claim the credit, it is our belief that the full amount of the credit may not be eventually allowed by the IRS once we are no longer in an AMT tax paying position. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



	2016		2015		2014
	(In thousands)
Balance at January 1:	$	410	$	410	$	—
Additions based on tax positions related to current year	—		—		410
Additions for tax positions of prior years	—		—		—
Reductions for tax positions of prior years	—		—		—
Settlements	—		—		—
Balance at December 31:	$	410	$	410	$	410

At December 31, 2016, 2015, and 2014, there was $0.4 million of unrecognized tax benefits that if recognized would affect the annual effective tax rate.

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2016
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 630,039, 235,104, and 120,333 shares of common stock and recognized expense of $4.0 million, $6.2 million, and $5.2 million in 2016, 2015, and 2014, 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, 2016 and 2015 was $4.6 million and $4.2 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral. Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments, and the circumstances under which employees become eligible to receive benefits. On December 8, 2015, we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $3.1 million, $3.0 million, and $2.7 million in 2016, 2015, and 2014, 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, 2016

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:



	2016		2015		2014
	(In thousands)
Contract drilling	$	—	$	—	$	4
Well supervision and other fees	254		423		435
General and administrative expense reimbursement	6		18		39

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.

Former Chairman of our Board, John Nikkel is a 25.8% owner of Rampart Holdings, Inc. which owns 100% of Toklan Oil and Gas Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son, Robert Nikkel is Toklan's President, and he owns 20.0% of the company. In 2014, there were two wells drilled for Toklan, one of which was completed in 2014 and one of which was completed in 2015 with no activity in 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 and $1.5 million in 2014. During 2014, we received payments of $1.1 million and had an accounts receivable balance of $0.4 million at December 31, 2014. During 2015, we received payments of $0.9 million with no accounts receivable balance at December 31, 2015. There was no material revenues in 2016. The Company also paid royalties in 2014, in the ordinary course of business, of approximately $0.2 million to Toklan. There were no material royalties to disclose for 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 holds an approximate 25.0% ownership interest and in which Mr. Robert Nikkel has an ownership interest of approximately 20.0%. West Thomas entered into a gas purchase agreement with our exploration and production segment in November of 2015. Payments from West Thomas under that contract amounted to $0.4 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 $0.5 million, $0.8 million, and $1.3 million during 2016, 2015, and 2014, 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, 2016

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

Stock-Based Compensation

STOCK-BASED COMPENSATION

For restricted stock awards, we had:



	2016		2015 ⁽¹⁾		2014
	(In millions)
Recognized stock compensation expense	$	9.6	$	15.3	$	17.4
Capitalized stock compensation cost for our oil and natural gas properties	2.1		3.5		3.7
Tax benefit on stock based compensation	3.6		5.8		6.7

_________________________


(1)	In 2015, recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

The remaining unrecognized compensation cost related to unvested awards at December 31, 2016 is approximately $6.5 million of which $1.0 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of a year.

The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors. A total of 4,500,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that can be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following:


•	incentive stock options under Section 422 of the Internal Revenue Code;


•	non-qualified stock options;


•	performance shares;


•	performance units;


•	restricted stock;


•	restricted stock units;


•	stock appreciation rights;


•	cash based awards; and


•	other stock-based awards.

This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in the award agreement.

Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States Treasury Strips rate using the term over which it is anticipated the grant will be exercised.

SARs

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



	Number of Shares		Weighted Average Price
Outstanding at January 1, 2014	145,901		$	46.59
Granted	—		—
Exercised	(14,131	)	46.50
Forfeited	—		—
Outstanding at December 31, 2014	131,770		46.60
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2015	131,770		46.60
Granted	—		—
Exercised	—		—
Forfeited	(40,515	)	51.76
Outstanding at December 31, 2016	91,255		$	44.31

There were no SARs granted or vested during 2016, 2015, or 2014.



	Outstanding and Exercisable SARs at December 31, 2016
Exercise Prices	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$44.31	91,255	1.0 year	$44.31

There were no SARs exercised in 2016. The SARs expire after 10 years from the date of the grant. There was no aggregate intrinsic value on the 91,255 shares outstanding at December 31, 2016. The remaining weighted average contractual term is 1.0 year.

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, 2014	652,835		123,908		776,743		$	48.70
Granted	383,448		71,674		455,122		53.72
Vested	(291,712	)	(13,092	)	(304,804	)	49.68
Forfeited	(19,805	)	(6,970	)	(26,775	)	51.92
Nonvested at December 31, 2014	724,766		175,520		900,286		50.81
Granted	576,361		148,081		724,442		34.06
Vested	(343,657	)	(39,245	)	(382,902	)	49.69
Forfeited	(20,808	)	(7,196	)	(28,004	)	45.33
Nonvested at December 31, 2015	936,662		277,160		1,213,822		41.29
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



Non-Employee Directors	Number of Shares		Weighted Average Price
Nonvested at January 1, 2014	35,704		$	41.07
Granted	13,768		63.91
Vested	(14,336	)	40.93
Forfeited	—		—
Nonvested at December 31, 2014	35,136		$	50.08
Granted	25,848		34.04
Vested	(18,920	)	46.51
Forfeited	—		—
Nonvested at December 31, 2015	42,064		$	41.83
Granted	90,000		12.02
Vested	(20,248	)	43.46
Forfeited	—		—
Nonvested at December 31, 2016	111,816		$	17.21

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, 2016, the participants are estimated to receive 102% of the 2016, 10% of the 2015, and 41% of the 2014 performance based shares. The CFTA performance measurement at December 31, 2016 was assessed to vest at target or 100%.

The fair value of the restricted stock granted in 2016, 2015, and 2014 at the grant date was $4.5 million, $24.5 million, and $24.1 million, respectively. The aggregate intrinsic value of the 445,443 shares of restricted stock that vested in 2016 on their vesting date was $4.1 million. The aggregate intrinsic value of the 1,413,681 shares of restricted stock outstanding subject to vesting at December 31, 2016 was $38.0 million with a weighted average remaining life of 1.0 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, 2014	68,920		$	37.81
Granted	—		—
Exercised	(21,490	)	37.83
Forfeited	(37,930	)	37.83
Outstanding at December 31, 2014	9,500		37.69
Granted	—		—
Exercised	—		—
Forfeited	(9,500	)	37.69
Outstanding at December 31, 2015	—		—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2016	—		$	—

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, 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, 2014	171,500		$	51.70
Granted	—		—
Exercised	(21,000	)	33.94
Forfeited	—		—
Outstanding at December 31, 2014	150,500		54.18
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	54.35
Outstanding at December 31, 2015	129,500		54.15
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	62.40
Outstanding at December 31, 2016	108,500		$	52.56

There were no options exercised in 2016.



	Outstanding and Exercisable Options at December 31, 2016
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$31.30 - $41.21	38,500	2.9 years	$	37.58
$53.81 - $73.26	70,000	2.2 years	$	60.79

There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2016. The remaining weighted average remaining contractual term is 2.5 years.

Derivatives

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract is based, in part, on our view of current and future market conditions. As of December 31, 2016, 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, 2016, the following non-designated hedges were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Jan’17 – Mar’17	Natural gas – swap	70,000 MMBtu/day	$3.044	IF – NYMEX (HH)
Apr'17 – Dec'17	Natural gas – swap	60,000 MMBtu/day	$2.960	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – swap	10,000 MMBtu/day	$3.025	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – basis swap ⁽¹⁾	20,000 MMBtu/day	$(0.215)	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – basis swap ⁽¹⁾	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan'17 – Oct'17	Natural gas – collar	20,000 MMBtu/day	$2.88 - $3.10	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – three-way collar	15,000 MMBtu/day	$2.50 - $2.00 - $3.32	IF – NYMEX (HH)
Jan'18 – Mar'18	Natural gas – three-way collar	10,000 MMBtu/day	$3.25 - $2.50 - $4.43	IF – NYMEX (HH)
Jan’17 – Dec'17	Crude oil – three-way collar	3,750 Bbl/day	$49.79 - $39.58 - $60.98	WTI – NYMEX

_________________________


(1)	After December 31, 2016, the basis swaps for February through October 2017 and April through October 2018 were liquidated for $0.6 million and $0.5 million, respectively.

After December 31, 2016, the following non-designated hedges were entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Apr’17 – Oct'17	Natural gas – swap	10,000 MMBtu/day	$3.505	IF – NYMEX (HH)
Nov’17 – Dec'17	Natural gas – three-way collar	10,000 MMBtu/day	$3.50 - $2.75 - $4.00	IF – NYMEX (HH)
Jan'18 – Mar'18	Natural gas – three-way collar	40,000 MMBtu/day	$3.38 - $2.69 - $4.17	IF – NYMEX (HH)
Apr’18 – Dec'18	Natural gas – three-way collar	10,000 MMBtu/day	$3.00 - $2.50 - $3.66	IF – NYMEX (HH)

The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31:



		Derivative Assets Fair Value
	Balance Sheet Location	2016		2015
		(In thousands)
Commodity derivatives:
Current	Current derivative assets	$	—	$	10,186
Long-term	Non-current derivative assets	377		968
Total derivative assets		$	377	$	11,154



		Derivative Liabilities Fair Value
	Balance Sheet Location	2016		2015
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	21,564	$	—
Long-term	Non-current derivative liabilities	415		285
Total derivative liabilities		$	21,979	$	285

If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Consolidated Balance Sheets.

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		2016			2015
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(22,813	)	$	26,345
Total		$	(22,813	)	$	26,345

_________________________


(1)	Amount settled during the period is a gain of $9,658 and a gain of $46,615, respectively.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

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


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


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


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

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

The following tables set forth our recurring fair value measurements:



	December 31, 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	)



	December 31, 2015
	Level 2			Level 3			Effect of Netting			Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	2,794		$	10,145		$	(1,785	)	$	11,154
Liabilities	(1,019		)	(1,051		)	1,785			(285		)
	$	1,775		$	9,094		$	—		$	10,869

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, 2016.

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, 2016			December 31, 2015
	(In thousands)
Beginning of period	$	9,094		$	3,355
Total gains or losses:
Included in earnings⁽¹⁾	(9,042		)	15,260
Settlements	(7,174		)	(9,521		)
End of period	$	(7,122	)	$	9,094
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	$	(16,216	)	$	5,739

_________________________


(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, 2016:



Commodity ⁽¹⁾	Fair Value		Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil three-way collar	(1,167	)	Discounted cash flow	Forward commodity price curve	$0.00 - $4.29
Natural gas collar	(3,332	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.79
Natural gas three-way collar	(2,623	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.71

_________________________


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

Based on our valuation at December 31, 2016, 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, 2016, 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, 2016 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, 2016 and December 31, 2015 were $640.1 million and $638.0 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2016 and December 31, 2015 were $649.9 million and $455.5 million, respectively. These Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

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

Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2016, 2015, and 2014, we recorded non-cash impairment charges discussed further in Note 2 – Summary of Significant Accounting Policies. The valuation of these assets require the use of significant unobservable inputs classified as Level 3.

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2016
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 Pittsburgh, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $3.0 million, $0.9 million, $0.1 million, and $0.1 million in 2017 through 2020, respectively. Total rent expense incurred was $11.1 million, $12.9 million, and $13.6 million in 2016, 2015, and 2014, 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 $7.7 million and $1.9 million, respectively at December 31, 2016. Annual payments, net of maintenance and interest, average $4.1 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 $5,000, $118,000, $45,000 in 2016, 2015, and 2014, 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 2017 and 2018, we have committed to purchase approximately $2.3 million and $1.9 million, respectively, of new drilling rig components. We have also committed to paying $1.4 million for Enterprise Resource Planning software and maintenance over the next year. We are subject to various legal proceedings arising in the ordinary course of our various businesses none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows.

Industry Segment Information

12 Months Ended

Dec. 31, 2016

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, 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	$	965,159		$	—		$	—		$	—		$	—		$	965,159
Contract drilling	—			941,676			—			—			—			941,676
Gas gathering and processing	—			—			461,600			—			—			461,600
Total identifiable assets ⁽³⁾	965,159			941,676			461,600			—			—			2,368,435
Corporate land and building	—			—			—			58,188			—			58,188
Other corporate assets ⁽⁴⁾	—			—			—			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)	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, 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	$	1,218,036		$	—		$	—		$	—		$	—		$	1,218,036
Contract drilling	—			993,015			—			—			—			993,015
Gas gathering and processing	—			—			478,661			—			—			478,661
Total identifiable assets ⁽³⁾	1,218,036			993,015			478,661			—			—			2,689,712
Corporate land and building	—			—			—			49,890			—			49,890
Other corporate assets ⁽⁴⁾	—			—			—			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 a $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)	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, corporate leasehold improvements, transportation equipment, furniture, and equipment.



	Year Ended December 31, 2014
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	740,079	$	—	$	—	$	—		$	—		$	740,079
Contract drilling	—		566,012		—		—			(89,495		)	476,517
Gas gathering and processing	—		—		445,934		—			(89,586		)	356,348
Total revenues	740,079		566,012		445,934		—			(179,081		)	1,572,944
Expenses:
Operating costs:
Oil and natural gas	192,429		—		—		—			(4,513		)	187,916
Contract drilling	—		337,371		—		—			(62,438		)	274,933
Gas gathering and processing	—		—		391,903		—			(85,072		)	306,831
Total operating costs	192,429		337,371		391,903		—			(152,023		)	769,680
Depreciation, depletion and amortization	276,088		85,370		40,434		996			—			402,888
Impairments ⁽¹⁾	76,683		74,318		7,068		—			—			158,069
Total expenses	545,200		497,059		439,405		996			(152,023		)	1,330,637
Total operating income (loss) ⁽²⁾	194,879		68,953		6,529		(996		)	(27,058		)
General and administrative expense	—		—		—		(41,027		)	—			(41,027		)
Gain on disposition of assets	—		8,819		97		37			—			8,953
Gain on derivatives	—		—		—		30,147			—			30,147
Interest expense, net	—		—		—		(17,371		)	—			(17,371		)
Other	—		—		—		(70		)	—			(70		)
Income (loss) before income taxes	$	194,879	$	77,772	$	6,626	$	(29,280	)	$	(27,058	)	$	222,939

Identifiable assets:
Oil and natural gas	$	2,856,833	$	—	$	—	$	—		$	—		$	2,856,833
Contract drilling	—		1,059,980		—		—			—			1,059,980
Gas gathering and processing	—		—		500,255		—			—			500,255
Total identifiable assets ⁽³⁾	2,856,833		1,059,980		500,255		—			—			4,417,068
Corporate land and building	—		—		—		16,104			—			16,104
Other corporate assets ⁽⁴⁾	—		—		—		30,300			—			30,300
Total assets	$	2,856,833	$	1,059,980	$	500,255	$	46,404		$	—		$	4,463,472

Capital expenditures: ⁽⁵⁾	$	740,262	$	176,683	$	79,268	$	17,067		$	—		$	1,013,280

_______________________

(1)

We incurred non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million, net of tax). Impairment for contract drilling equipment includes a $74.3 million pre-tax write-down for 31 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, 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 on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


(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, corporate leasehold improvements, transportation equipment, furniture, and equipment.


(5)	Our mid-stream segment entered into capital leases for $28.2 million.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8981-108599

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-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9038-108599

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-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Selected Quarterly Financial Information

12 Months Ended

Dec. 31, 2016

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)
2015
Revenues	$	255,099		$	214,447		$	212,393		$	172,292
Gross loss ⁽¹⁾	$	(389,699	)	$	(419,916	)	$	(314,657	)	$	(492,877	)
Net loss	$	(248,354	)	$	(274,389	)	$	(205,281	)	$	(309,337	)
Net loss per common share:
Basic	$	(5.07	)	$	(5.58	)	$	(4.18	)	$	(6.29	)
Diluted	$	(5.07	)	$	(5.58	)	$	(4.18	)	$	(6.29	)
2016
Revenues	$	136,184		$	138,305		$	153,408		$	174,280
Gross income (loss) ⁽¹⁾	$	(49,871	)	$	(74,223	)	$	(27,365	)	$	37,773
Net income (loss)	$	(41,149	)	$	(72,136	)	$	(24,022	)	$	1,683
Net income (loss) per common share:
Basic	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03
Diluted ⁽²⁾	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03

_________________________


(1)	Gross profit (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)	Due to the effect of the income in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual loss per share.

Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2016

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:



	2016			2015			2014
	(In thousands)
Capitalized costs:
Proved properties	$	5,446,305		$	5,401,618		$	4,990,753
Unproved properties	314,867			337,099			485,568
	5,761,172			5,738,717			5,476,321
Accumulated depreciation, depletion, amortization, and impairment	(4,900,304		)	(4,631,404		)	(2,786,678		)
Net capitalized costs	$	860,868		$	1,107,313		$	2,689,643
Cost incurred:
Unproved properties acquired	$	21,675		$	41,777		$	76,041
Proved properties acquired	564			179			5,723
Exploration	17,325			19,222			68,811
Development	80,582			208,845			615,252
Asset retirement obligation	(30,906		)	(5,693		)	(37,687		)
Total costs incurred	$	89,240		$	264,330		$	728,140

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2016, by the year in which such costs were incurred:



	2016		2015		2014		2013 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	23,494	$	41,445	$	55,562	$	194,366	$	314,867

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:



	2016			2015			2014
	(In thousands)
Revenues	$	282,742		$	371,335		$	723,566
Production costs	(108,822		)	(152,560		)	(165,315		)
Depreciation, depletion, amortization, and impairment	(268,901		)	(1,844,726		)	(347,220		)
	(94,981		)	(1,625,951		)	211,031
Income tax (expense) benefit	32,696			612,496			(82,028		)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	(62,285	)	$	(1,013,455	)	$	129,003

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)
2014
Proved developed and undeveloped reserves:
Beginning of year	21,765		41,205		581,784		159,934
Revision of previous estimates ⁽¹⁾	(3,174	)	(2,266	)	(32,790	)	(10,905	)
Extensions and discoveries	5,327		10,850		113,541		35,101
Infill reserves in existing proved fields	2,775		3,577		47,189		14,217
Purchases of minerals in place	236		88		368		385
Production	(3,844	)	(4,629	)	(58,854	)	(18,282	)
Sales	(418	)	(296	)	(4,277	)	(1,427	)
End of year	22,667		48,529		646,961		179,023
Proved developed reserves:
Beginning of year	15,594		30,437		464,234		123,403
End of year	17,448		35,850		500,950		136,790
Proved undeveloped reserves:
Beginning of year	6,171		10,768		117,550		36,531
End of year	5,219		12,679		146,011		42,233
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

_________________________


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

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

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



	2016			2015			2014
	(In thousands)
Future cash flows	$	2,030,925		$	2,475,898		$	6,398,236
Future production costs	(861,625		)	(1,017,777		)	(2,069,636		)
Future development costs	(173,446		)	(228,445		)	(560,102		)
Future income tax expenses	(141,752		)	(230,544		)	(1,228,533		)
Future net cash flows	854,102			999,132			2,539,965
10% annual discount for estimated timing of cash flows	(335,892		)	(409,646		)	(1,104,221		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	518,210		$	589,486		$	1,435,744

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



	2016			2015			2014
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(173,920	)	$	(218,115	)	$	(558,252	)
Net changes in prices and production costs	(94,026		)	(1,356,333		)	(33,259		)
Revisions in quantity estimates and changes in production timing	(51,979		)	(213,945		)	(135,125		)
Extensions, discoveries, and improved recovery, less related costs	84,738			95,671			635,752
Changes in estimated future development costs	70,976			227,857			96,339
Previously estimated cost incurred during the period	16,602			59,117			164,430
Purchases of minerals in place	2,652			—			8,395
Sales of minerals in place	(17,248		)	(3,338		)	(19,135		)
Accretion of discount	69,069			209,979			179,190
Net change in income taxes	44,241			562,838			(98,119		)
Other—net	(22,381		)	(209,989		)	(30,448		)
Net change	(71,276		)	(846,258		)	209,768
Beginning of year	589,486			1,435,744			1,225,976
End of year	$	518,210		$	589,486		$	1,435,744

Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.

The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.

The December 31, 2016, future cash flows were computed by applying the unescalated 12-month average prices of $42.75 per barrel for oil, $19.74 per barrel for NGLs, and $2.48 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, 2016

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, 2016	$	5,199	$	785	$	(2,211	)	$	3,773
Year ended December 31, 2015	$	5,039	$	1,191	$	(1,031	)	$	5,199
Year ended December 31, 2014	$	5,342	$	3,562	$	(3,865	)	$	5,039

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2016

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, 2016, all of our contracts were daywork contracts of which eight were multi-well and had durations which ranged from six months to two years, seven of which expire in 2017 and one expiring in 2018. 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, 2016 and 2015, book overdrafts were $17.3 million and $22.1 million, respectively.

Accounts Receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.

Financial Instruments and Concentrations Of Credit Risk and Non-Performance Risk

Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues:



	2016		2015		2014
Oil and Natural Gas:
Sunoco Logistics Partners L.P.	24	%	19	%	14	%
Valero Energy Corporation	11	%	15	%	24	%
Drilling:
QEP Resources, Inc.	28	%	25	%	19	%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	18	%	7	%	9	%
Mid-Stream:
ONEOK Partners, L.P.	30	%	29	%	44	%
Koch Energy Services, LLC	11	%	9	%	2	%
Range Resources Corporation	10	%	5	%	2	%
Tenaska Resources, LLC	10	%	18	%	22	%
Laclede Group, Inc.	9	%	12	%	16	%

We had a concentration of cash of $8.3 million and $2.3 million at December 31, 2016 and 2015, respectively with one bank.



	December 31, 2016
	(In millions)
Canadian Imperial Bank of Commerce	$	11.1
Bank of Montreal	8.0
Scotiabank	2.5
Total liabilities	$	21.6

Property and Equipment

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

In 2016, our mid-stream segment had no impairments.

Capitalized Interest

During 2016, 2015, and 2014, interest of approximately $15.3 million, $21.7 million, and $32.2 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.

Goodwill

Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2016, 2015, or 2014. There were no additions to goodwill in 2016, 2015, or 2014. Based on our impairment test performed as of December 31, 2016, the fair value of our drilling segment exceeded its carrying value by 16%. Goodwill of $1.3 million is deductible for tax purposes.

Oil and Natural Gas Operations

We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $15.4 million, $19.2 million, and $23.7 million were capitalized in 2016, 2015, and 2014, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $6.24, $12.30, and $14.82 per Boe in 2016, 2015, and 2014, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our unproved properties and wells in progress totaling $314.9 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.

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. 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

Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.

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, 2016 balancing position to be approximately 3.7 Bcf on under-produced properties and approximately 3.3 Bcf on over-produced properties. We have recorded a receivable of $2.8 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.8 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.

Employee And Director Stock Based Compensation

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

Impact of Financial Accounting Pronouncements

Adopted Standards

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

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:



	2016		2015		2014
Oil and Natural Gas:
Sunoco Logistics Partners L.P.	24	%	19	%	14	%
Valero Energy Corporation	11	%	15	%	24	%
Drilling:
QEP Resources, Inc.	28	%	25	%	19	%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	18	%	7	%	9	%
Mid-Stream:
ONEOK Partners, L.P.	30	%	29	%	44	%
Koch Energy Services, LLC	11	%	9	%	2	%
Range Resources Corporation	10	%	5	%	2	%
Tenaska Resources, LLC	10	%	18	%	22	%
Laclede Group, Inc.	9	%	12	%	16	%

Schedule Of Fair Values Of The Net Liabilities [Table Text Block]

At December 31, 2016, the fair values of the net 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, 2016
	(In millions)
Canadian Imperial Bank of Commerce	$	11.1
Bank of Montreal	8.0
Scotiabank	2.5
Total liabilities	$	21.6

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

12 Months Ended

Dec. 31, 2016

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, 2014:
Basic earnings per common share	$	136,276		48,611	$	2.80
Effect of dilutive stock options, restricted stock, and SARs	—			472	(0.02		)
Diluted earnings per common share	$	136,276		49,083	$	2.78
For the year ended December 31, 2015:
Basic earnings (loss) per common share	$	(1,037,361	)	49,110	$	(21.12	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted earnings (loss) per common share	$	(1,037,361	)	49,110	$	(21.12	)
For the year ended December 31, 2016:
Basic earnings (loss) per common share	$	(135,624	)	50,029	$	(2.71	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted earnings (loss) per common share	$	(135,624	)	50,029	$	(2.71	)

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



	2016		2015		2014
Options and SARs	199,755		261,270		73,500
Average exercise price	$	48.79	$	50.34	$	64.43

Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Accrued Liabilities [Abstract]

Accrued Liabilities [Table Text Block]

Accrued liabilities consisted of the following as of December 31:



	2016		2015
	(In thousands)
Employee costs	$	15,394	$	12,641
Lease operating expenses	10,075		17,220
Interest payable	6,524		6,321
Third-party credits	2,998		3,326
Taxes	2,219		3,767
Other	2,441		3,643
Total accrued liabilities	$	39,651	$	46,918

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

12 Months Ended

Dec. 31, 2016

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:



	2016			2015
	(In thousands)
Credit agreement with average interest rates of 2.8% and 2.6% at December 31, 2016 and 2015, respectively	$	160,800		$	281,000
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	$	810,800		$	931,000
Less: unamortized discount	(2,804		)	(3,338		)
Less: debt issuance costs, net	(7,079		)	(8,667		)
Total long-term debt	$	800,917		$	918,995

Other Long Term Liabilities [Table Text Block]

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



	2016		2015
	(In thousands)
ARO liability	$	70,170	$	98,297
Capital lease obligations	18,918		22,466
Workers’ compensation	15,163		16,551
Separation benefit plans	4,943		9,886
Deferred compensation plan	4,578		4,244
Gas balancing liability	3,789		5,047
Other	410		410
	117,971		156,901
Less current portion	14,907		16,560
Total other long-term liabilities	$	103,064	$	140,341

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

Future payments required under the capital leases at December 31, 2016 are as follows:



	Amount
Ending December 31,	(In thousands)
2017	$	6,168
2018	6,168
2019	6,168
2020	6,168
2021	3,769
Total future payments	28,441
Less payments related to:
Maintenance	7,659
Interest	1,864
Present value of future minimum payments	$	18,918

- 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)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

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

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

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

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

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

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

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:



	2016			2015
	(In thousands)
ARO liability, January 1:	$	98,297		$	100,567
Accretion of discount	2,779			3,453
Liability incurred	584			6,754
Liability settled	(1,215		)	(2,893		)
Liability sold	(10,882		)	(421		)
Revision of estimates ⁽¹⁾	(19,393		)	(9,163		)
ARO liability, December 31:	70,170			98,297
Less current portion	2,906			3,965
Total long-term ARO liability	$	67,264		$	94,332

_________________________


(1)	Plugging liability estimates were revised in both 2016 and 2015 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

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:



	2016			2015			2014
	(In thousands)
Income tax expense (benefit) computed by applying the statutory rate	$	(72,386	)	$	(582,508	)	$	78,029
State income tax expense (benefit), net of federal benefit	(5,687		)	(45,768		)	6,131
Restricted stock shortfall	5,465			—			—
Statutory depletion and other	1,414			1,328			2,503
Income tax expense (benefit)	$	(71,194	)	$	(626,948	)	$	86,663

Schedule Of Total Provision For Income Taxes [Table Text Block]

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



	2016			2015			2014
	(In thousands)
Current taxes:
Federal	$	—		$	(20,612	)	$	8,594
State	15			(4		)	784
	15			(20,616		)	9,378
Deferred taxes:
Federal	(62,923		)	(535,691		)	68,360
State	(8,286		)	(70,641		)	8,925
	(71,209		)	(606,332		)	77,285
Total provision	$	(71,194	)	$	(626,948	)	$	86,663

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

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



	2016			2015
	(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals	$	53,967		$	56,479
Net operating loss carryforward	190,603			140,863
Alternative minimum tax and research and development tax credit carryforward	5,409			5,409
	249,979			202,751
Deferred tax liability:
Depreciation, depletion, amortization, and impairment	(440,690		)	(464,295		)
Net deferred tax liability	(190,711		)	(261,544		)
Current deferred tax asset	25,211			14,206
Non-current—deferred tax liability	$	(215,922	)	$	(275,750	)

Schedule of Unrecognized Tax Benefits [Table Text Block]

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



	2016		2015		2014
	(In thousands)
Balance at January 1:	$	410	$	410	$	—
Additions based on tax positions related to current year	—		—		410
Additions for tax positions of prior years	—		—		—
Reductions for tax positions of prior years	—		—		—
Settlements	—		—		—
Balance at December 31:	$	410	$	410	$	410

Transactions With Related Parties (Tables)

12 Months Ended

Dec. 31, 2016

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:



	2016		2015		2014
	(In thousands)
Contract drilling	$	—	$	—	$	4
Well supervision and other fees	254		423		435
General and administrative expense reimbursement	6		18		39

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

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:



	2016		2015 ⁽¹⁾		2014
	(In millions)
Recognized stock compensation expense	$	9.6	$	15.3	$	17.4
Capitalized stock compensation cost for our oil and natural gas properties	2.1		3.5		3.7
Tax benefit on stock based compensation	3.6		5.8		6.7

_________________________


(1)	In 2015, recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

Activity Pertaining to Stock Appreciation Rights [Table Text Block]

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



	Number of Shares		Weighted Average Price
Outstanding at January 1, 2014	145,901		$	46.59
Granted	—		—
Exercised	(14,131	)	46.50
Forfeited	—		—
Outstanding at December 31, 2014	131,770		46.60
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2015	131,770		46.60
Granted	—		—
Exercised	—		—
Forfeited	(40,515	)	51.76
Outstanding at December 31, 2016	91,255		$	44.31

Shares Authorized Under Stock Appreciation Rights By Exercise Price [Table Text Block]



	Outstanding and Exercisable SARs at December 31, 2016
Exercise Prices	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$44.31	91,255	1.0 year	$44.31

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, 2014	652,835		123,908		776,743		$	48.70
Granted	383,448		71,674		455,122		53.72
Vested	(291,712	)	(13,092	)	(304,804	)	49.68
Forfeited	(19,805	)	(6,970	)	(26,775	)	51.92
Nonvested at December 31, 2014	724,766		175,520		900,286		50.81
Granted	576,361		148,081		724,442		34.06
Vested	(343,657	)	(39,245	)	(382,902	)	49.69
Forfeited	(20,808	)	(7,196	)	(28,004	)	45.33
Nonvested at December 31, 2015	936,662		277,160		1,213,822		41.29
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



Non-Employee Directors	Number of Shares		Weighted Average Price
Nonvested at January 1, 2014	35,704		$	41.07
Granted	13,768		63.91
Vested	(14,336	)	40.93
Forfeited	—		—
Nonvested at December 31, 2014	35,136		$	50.08
Granted	25,848		34.04
Vested	(18,920	)	46.51
Forfeited	—		—
Nonvested at December 31, 2015	42,064		$	41.83
Granted	90,000		12.02
Vested	(20,248	)	43.46
Forfeited	—		—
Nonvested at December 31, 2016	111,816		$	17.21

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, 2014	68,920		$	37.81
Granted	—		—
Exercised	(21,490	)	37.83
Forfeited	(37,930	)	37.83
Outstanding at December 31, 2014	9,500		37.69
Granted	—		—
Exercised	—		—
Forfeited	(9,500	)	37.69
Outstanding at December 31, 2015	—		—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2016	—		$	—

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, 2014	171,500		$	51.70
Granted	—		—
Exercised	(21,000	)	33.94
Forfeited	—		—
Outstanding at December 31, 2014	150,500		54.18
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	54.35
Outstanding at December 31, 2015	129,500		54.15
Granted	—		—
Exercised	—		—
Forfeited	(21,000	)	62.40
Outstanding at December 31, 2016	108,500		$	52.56

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



	Outstanding and Exercisable Options at December 31, 2016
Weighted Average Exercise Price	Number of Shares	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price
$31.30 - $41.21	38,500	2.9 years	$	37.58
$53.81 - $73.26	70,000	2.2 years	$	60.79

Derivatives (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

At December 31, 2016, the following non-designated hedges were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Jan’17 – Mar’17	Natural gas – swap	70,000 MMBtu/day	$3.044	IF – NYMEX (HH)
Apr'17 – Dec'17	Natural gas – swap	60,000 MMBtu/day	$2.960	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – swap	10,000 MMBtu/day	$3.025	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – basis swap ⁽¹⁾	20,000 MMBtu/day	$(0.215)	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – basis swap ⁽¹⁾	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan'17 – Oct'17	Natural gas – collar	20,000 MMBtu/day	$2.88 - $3.10	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – three-way collar	15,000 MMBtu/day	$2.50 - $2.00 - $3.32	IF – NYMEX (HH)
Jan'18 – Mar'18	Natural gas – three-way collar	10,000 MMBtu/day	$3.25 - $2.50 - $4.43	IF – NYMEX (HH)
Jan’17 – Dec'17	Crude oil – three-way collar	3,750 Bbl/day	$49.79 - $39.58 - $60.98	WTI – NYMEX

_________________________


(1)	After December 31, 2016, the basis swaps for February through October 2017 and April through October 2018 were liquidated for $0.6 million and $0.5 million, respectively.

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

After December 31, 2016, the following non-designated hedges were entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price for Swaps	Contracted Market
Apr’17 – Oct'17	Natural gas – swap	10,000 MMBtu/day	$3.505	IF – NYMEX (HH)
Nov’17 – Dec'17	Natural gas – three-way collar	10,000 MMBtu/day	$3.50 - $2.75 - $4.00	IF – NYMEX (HH)
Jan'18 – Mar'18	Natural gas – three-way collar	40,000 MMBtu/day	$3.38 - $2.69 - $4.17	IF – NYMEX (HH)
Apr’18 – Dec'18	Natural gas – three-way collar	10,000 MMBtu/day	$3.00 - $2.50 - $3.66	IF – NYMEX (HH)

Fair Value Of Derivative Instruments And Locations In Balance Sheets [Table Text Block]

The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31:



		Derivative Assets Fair Value
	Balance Sheet Location	2016		2015
		(In thousands)
Commodity derivatives:
Current	Current derivative assets	$	—	$	10,186
Long-term	Non-current derivative assets	377		968
Total derivative assets		$	377	$	11,154



		Derivative Liabilities Fair Value
	Balance Sheet Location	2016		2015
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	21,564	$	—
Long-term	Non-current derivative liabilities	415		285
Total derivative liabilities		$	21,979	$	285

Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments [Table Text Block]

Effect of derivative instruments on the Consolidated Statements of Operations 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		2016			2015
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(22,813	)	$	26,345
Total		$	(22,813	)	$	26,345

_________________________


(1)	Amount settled during the period is a gain of $9,658 and a gain of $46,615, respectively.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Recurring Fair Value Measurements [Table Text Block]

The following tables set forth our recurring fair value measurements:



	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	)



	December 31, 2015
	Level 2			Level 3			Effect of Netting			Total
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	2,794		$	10,145		$	(1,785	)	$	11,154
Liabilities	(1,019		)	(1,051		)	1,785			(285		)
	$	1,775		$	9,094		$	—		$	10,869

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, 2016			December 31, 2015
	(In thousands)
Beginning of period	$	9,094		$	3,355
Total gains or losses:
Included in earnings⁽¹⁾	(9,042		)	15,260
Settlements	(7,174		)	(9,521		)
End of period	$	(7,122	)	$	9,094
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	$	(16,216	)	$	5,739

_________________________


(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, 2016:



Commodity ⁽¹⁾	Fair Value		Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil three-way collar	(1,167	)	Discounted cash flow	Forward commodity price curve	$0.00 - $4.29
Natural gas collar	(3,332	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.79
Natural gas three-way collar	(2,623	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.71

_________________________


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

Industry Segment Information (Tables)

12 Months Ended

Dec. 31, 2016

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, 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	$	965,159		$	—		$	—		$	—		$	—		$	965,159
Contract drilling	—			941,676			—			—			—			941,676
Gas gathering and processing	—			—			461,600			—			—			461,600
Total identifiable assets ⁽³⁾	965,159			941,676			461,600			—			—			2,368,435
Corporate land and building	—			—			—			58,188			—			58,188
Other corporate assets ⁽⁴⁾	—			—			—			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)	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, 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	$	1,218,036		$	—		$	—		$	—		$	—		$	1,218,036
Contract drilling	—			993,015			—			—			—			993,015
Gas gathering and processing	—			—			478,661			—			—			478,661
Total identifiable assets ⁽³⁾	1,218,036			993,015			478,661			—			—			2,689,712
Corporate land and building	—			—			—			49,890			—			49,890
Other corporate assets ⁽⁴⁾	—			—			—			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)	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, corporate leasehold improvements, transportation equipment, furniture, and equipment.



	Year Ended December 31, 2014
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	740,079	$	—	$	—	$	—		$	—		$	740,079
Contract drilling	—		566,012		—		—			(89,495		)	476,517
Gas gathering and processing	—		—		445,934		—			(89,586		)	356,348
Total revenues	740,079		566,012		445,934		—			(179,081		)	1,572,944
Expenses:
Operating costs:
Oil and natural gas	192,429		—		—		—			(4,513		)	187,916
Contract drilling	—		337,371		—		—			(62,438		)	274,933
Gas gathering and processing	—		—		391,903		—			(85,072		)	306,831
Total operating costs	192,429		337,371		391,903		—			(152,023		)	769,680
Depreciation, depletion and amortization	276,088		85,370		40,434		996			—			402,888
Impairments ⁽¹⁾	76,683		74,318		7,068		—			—			158,069
Total expenses	545,200		497,059		439,405		996			(152,023		)	1,330,637
Total operating income (loss) ⁽²⁾	194,879		68,953		6,529		(996		)	(27,058		)
General and administrative expense	—		—		—		(41,027		)	—			(41,027		)
Gain on disposition of assets	—		8,819		97		37			—			8,953
Gain on derivatives	—		—		—		30,147			—			30,147
Interest expense, net	—		—		—		(17,371		)	—			(17,371		)
Other	—		—		—		(70		)	—			(70		)
Income (loss) before income taxes	$	194,879	$	77,772	$	6,626	$	(29,280	)	$	(27,058	)	$	222,939

Identifiable assets:
Oil and natural gas	$	2,856,833	$	—	$	—	$	—		$	—		$	2,856,833
Contract drilling	—		1,059,980		—		—			—			1,059,980
Gas gathering and processing	—		—		500,255		—			—			500,255
Total identifiable assets ⁽³⁾	2,856,833		1,059,980		500,255		—			—			4,417,068
Corporate land and building	—		—		—		16,104			—			16,104
Other corporate assets ⁽⁴⁾	—		—		—		30,300			—			30,300
Total assets	$	2,856,833	$	1,059,980	$	500,255	$	46,404		$	—		$	4,463,472

Capital expenditures: ⁽⁵⁾	$	740,262	$	176,683	$	79,268	$	17,067		$	—		$	1,013,280

_______________________

(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 on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.


(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, corporate leasehold improvements, transportation equipment, furniture, and equipment.


(5)	Our mid-stream segment entered into capital leases for $28.2 million.

Selected Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2016

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)
2015
Revenues	$	255,099		$	214,447		$	212,393		$	172,292
Gross loss ⁽¹⁾	$	(389,699	)	$	(419,916	)	$	(314,657	)	$	(492,877	)
Net loss	$	(248,354	)	$	(274,389	)	$	(205,281	)	$	(309,337	)
Net loss per common share:
Basic	$	(5.07	)	$	(5.58	)	$	(4.18	)	$	(6.29	)
Diluted	$	(5.07	)	$	(5.58	)	$	(4.18	)	$	(6.29	)
2016
Revenues	$	136,184		$	138,305		$	153,408		$	174,280
Gross income (loss) ⁽¹⁾	$	(49,871	)	$	(74,223	)	$	(27,365	)	$	37,773
Net income (loss)	$	(41,149	)	$	(72,136	)	$	(24,022	)	$	1,683
Net income (loss) per common share:
Basic	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03
Diluted ⁽²⁾	$	(0.83	)	$	(1.44	)	$	(0.48	)	$	0.03

_________________________


(1)	Gross profit (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)	Due to the effect of the income in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual loss per share.

Supplemental Oil And Gas Disclosures (Tables)

12 Months Ended

Dec. 31, 2016

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:



	2016			2015			2014
	(In thousands)
Capitalized costs:
Proved properties	$	5,446,305		$	5,401,618		$	4,990,753
Unproved properties	314,867			337,099			485,568
	5,761,172			5,738,717			5,476,321
Accumulated depreciation, depletion, amortization, and impairment	(4,900,304		)	(4,631,404		)	(2,786,678		)
Net capitalized costs	$	860,868		$	1,107,313		$	2,689,643
Cost incurred:
Unproved properties acquired	$	21,675		$	41,777		$	76,041
Proved properties acquired	564			179			5,723
Exploration	17,325			19,222			68,811
Development	80,582			208,845			615,252
Asset retirement obligation	(30,906		)	(5,693		)	(37,687		)
Total costs incurred	$	89,240		$	264,330		$	728,140

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, 2016, by the year in which such costs were incurred:



	2016		2015		2014		2013 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	23,494	$	41,445	$	55,562	$	194,366	$	314,867

Results Of Operations For Producing Activities [Table Text Block]

The results of operations for producing activities are as follows:



	2016			2015			2014
	(In thousands)
Revenues	$	282,742		$	371,335		$	723,566
Production costs	(108,822		)	(152,560		)	(165,315		)
Depreciation, depletion, amortization, and impairment	(268,901		)	(1,844,726		)	(347,220		)
	(94,981		)	(1,625,951		)	211,031
Income tax (expense) benefit	32,696			612,496			(82,028		)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	(62,285	)	$	(1,013,455	)	$	129,003

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)
2014
Proved developed and undeveloped reserves:
Beginning of year	21,765		41,205		581,784		159,934
Revision of previous estimates ⁽¹⁾	(3,174	)	(2,266	)	(32,790	)	(10,905	)
Extensions and discoveries	5,327		10,850		113,541		35,101
Infill reserves in existing proved fields	2,775		3,577		47,189		14,217
Purchases of minerals in place	236		88		368		385
Production	(3,844	)	(4,629	)	(58,854	)	(18,282	)
Sales	(418	)	(296	)	(4,277	)	(1,427	)
End of year	22,667		48,529		646,961		179,023
Proved developed reserves:
Beginning of year	15,594		30,437		464,234		123,403
End of year	17,448		35,850		500,950		136,790
Proved undeveloped reserves:
Beginning of year	6,171		10,768		117,550		36,531
End of year	5,219		12,679		146,011		42,233
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

_________________________


(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]



	2016			2015			2014
	(In thousands)
Future cash flows	$	2,030,925		$	2,475,898		$	6,398,236
Future production costs	(861,625		)	(1,017,777		)	(2,069,636		)
Future development costs	(173,446		)	(228,445		)	(560,102		)
Future income tax expenses	(141,752		)	(230,544		)	(1,228,533		)
Future net cash flows	854,102			999,132			2,539,965
10% annual discount for estimated timing of cash flows	(335,892		)	(409,646		)	(1,104,221		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	518,210		$	589,486		$	1,435,744

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:



	2016			2015			2014
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(173,920	)	$	(218,115	)	$	(558,252	)
Net changes in prices and production costs	(94,026		)	(1,356,333		)	(33,259		)
Revisions in quantity estimates and changes in production timing	(51,979		)	(213,945		)	(135,125		)
Extensions, discoveries, and improved recovery, less related costs	84,738			95,671			635,752
Changes in estimated future development costs	70,976			227,857			96,339
Previously estimated cost incurred during the period	16,602			59,117			164,430
Purchases of minerals in place	2,652			—			8,395
Sales of minerals in place	(17,248		)	(3,338		)	(19,135		)
Accretion of discount	69,069			209,979			179,190
Net change in income taxes	44,241			562,838			(98,119		)
Other—net	(22,381		)	(209,989		)	(30,448		)
Net change	(71,276		)	(846,258		)	209,768
Beginning of year	589,486			1,435,744			1,225,976
End of year	$	518,210		$	589,486		$	1,435,744

- 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=50486907&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, 2016

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, 2016	$	5,199	$	785	$	(2,211	)	$	3,773
Year ended December 31, 2015	$	5,039	$	1,191	$	(1,031	)	$	5,199
Year ended December 31, 2014	$	5,342	$	3,562	$	(3,865	)	$	5,039

Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Sunoco Logistics Partners L.P. \| Oil and Natural Gas [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	24.00%	19.00%	14.00%
Valero Energy Corporation \| Oil and Natural Gas [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	11.00%	15.00%	24.00%
QEP Resources, Inc. \| Drilling [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	28.00%	25.00%	19.00%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) \| Drilling [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	18.00%	7.00%	9.00%
ONEOK Partners, L.P. \| Mid-Stream [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	30.00%	29.00%	44.00%
Koch Energy Services, LLC [Member] \| Mid-Stream [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	11.00%	9.00%	2.00%
Range Resources Corporation [Member] \| Mid-Stream [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	5.00%	2.00%
Tenaska Resources, LLC \| Mid-Stream [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	18.00%	22.00%
Laclede Group, Inc. \| Mid-Stream [Member]
Revenue, Major Customer [Line Items]
Segment's revenues	9.00%	12.00%	16.00%

Summary Of Significant Accounting Policies (Schedule Of Fair Values Of The Net Liabilities) (Details) $ in Millions	Dec. 31, 2016 USD ($)
Derivative Counterparty [Line Items]
Total liabilities	$ 21.6
Canadian Imperial Bank of Commerce
Derivative Counterparty [Line Items]
Total liabilities	11.1
Bank of Montreal
Derivative Counterparty [Line Items]
Total liabilities	8.0
Scotiabank
Derivative Counterparty [Line Items]
Total liabilities	$ 2.5

Summary Of Significant Accounting Policies (Narrative) (Details)

3 Months Ended

12 Months Ended

Sep. 30, 2015

USD ($)

rig

Mar. 31, 2015

USD ($)

rig

Dec. 31, 2014

USD ($)

rig

Dec. 31, 2016

USD ($)

contract

Unit

rig

MMcf

Dec. 31, 2015

USD ($)

rig

systems

Dec. 31, 2014

USD ($)

rig

systems

Dec. 31, 2013

USD ($)

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

$ 17,300,000

$ 22,100,000

Concentration of cash

8,300,000

$ 2,300,000

Impairment of gas gathering systems

Number of gas gathering systems impaired | systems

Interest Costs Capitalized

15,300,000

$ 21,700,000

$ 32,200,000

Additions to goodwill

Goodwill impairment

$ 0

Percentage fair value exceeds carrying value for goodwill

16.00%

Goodwill deductible for tax purposes

$ 1,300,000

$ 23,700,000

15,400,000

19,200,000

23,700,000

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

6.24

12.30

14.82

Unproved properties not being amortized

485,568,000

$ 314,867,000

337,099,000

485,568,000

Future discounted net cash flows discounted

10.00%

Unproved properties included in amortization

73,700,000

$ 7,600,000

114,400,000

73,700,000

Non-cash ceiling test write-down net of tax

100,600,000

1,000,000,000

47,700,000

Revenues from transactions with operating segments of same entity

22,100,000

89,500,000

Eliminated associated operating expense

18,300,000

62,400,000

Eliminated yielding

$ 0

3,800,000

27,100,000

Number of oil and gas limited partnerships | Unit

Unrecognized tax benefits

$ 410,000

410,000

$ 0

Minimum

Summary Of Significant Accounting Policies [Line Items]

Number of days for drilling of one well

10 days

Duration length of contracts

6 months

Insurance coverage

$ 0

Maximum

Summary Of Significant Accounting Policies [Line Items]

Number of days for drilling of one well

90 days

Duration length of contracts

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

3,300

Natural Gas Balancing

Summary Of Significant Accounting Policies [Line Items]

Accounts receivable

$ 2,800,000

Liability recognized to under production

$ 3,800,000

Drilling Equipment

Summary Of Significant Accounting Policies [Line Items]

Minimum depreciation percentage for idle drilling rigs

20.00%

Number of drilling rigs removed from service | rig

Drilling Equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life, years

15 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

Drilling [Member]

Summary Of Significant Accounting Policies [Line Items]

Number of drilling rigs removed from service | rig

Impairment of contract drilling equipment

$ 0

^[1]

$ 8,314,000

74,318,000

Number of rigs sold | rig

Net book value of drilling rigs sold

$ 11,000,000.0

$ 300,000.0

Gain (loss) on sale of drilling rigs

$ (7,300,000)

$ 7,900

Mid-Stream [Member]

Summary Of Significant Accounting Policies [Line Items]

Impairment of gas gathering systems

^[1]

26,966,000

7,068,000

Oil and Natural Gas [Member]

Summary Of Significant Accounting Policies [Line Items]

Impairment of oil and natural gas properties

$ 161,563,000

$ 1,599,348,000

$ 76,683,000

Drilling Equipment

Summary Of Significant Accounting Policies [Line Items]

Number of rigs sold | rig

Net book value of drilling rigs sold

$ 16,300,000.0

$ 1,700,000.0

$ 16,300,000.0

Gain (loss) on sale of drilling rigs

$ 1,600,000

$ 9,600,000

[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).

Divestitures - Narrative (Details)	12 Months Ended
Divestitures - Narrative (Details)	Dec. 31, 2016 USD ($) rig	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) rig
Oil and Natural Gas [Member]
Divestiture [Line Items]
Proceeds from divestiture of assets	$ 67,200,000	$ 1,900,000	$ 33,100,000
Drilling Equipment
Divestiture [Line Items]
Number of rigs sold \| rig	1		4
Net book value of drilling rigs sold	$ 1,700,000.0		$ 16,300,000.0
Gain (loss) on sale of drilling rigs	$ 1,600,000		$ 9,600,000

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, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Earnings Per Share [Abstract]

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

$ 1,683

$ (24,022)

$ (72,136)

$ (41,149)

$ (309,337)

$ (205,281)

$ (274,389)

$ (248,354)

$ (135,624)

$ (1,037,361)

$ 136,276

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

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

$ (135,624)

$ (1,037,361)

$ 136,276

Weighted shares of basic earnings (loss) per common share

50,029

49,110

48,611

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

472

Weighted shares of diluted earnings (loss) per common share

50,029

49,110

49,083

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

$ 0.03

$ (0.48)

$ (1.44)

$ (0.83)

$ (6.29)

$ (4.18)

$ (5.58)

$ (5.07)

$ (2.71)

$ (21.12)

$ 2.80

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

0.00

(0.02)

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

$ 0.03

^[1]

$ (0.48)

^[1]

$ (1.44)

^[1]

$ (0.83)

^[1]

$ (6.29)

$ (4.18)

$ (5.58)

$ (5.07)

$ (2.71)

$ (21.12)

$ 2.78

[1]	Due to the effect of the income in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options and SARs	199,755	261,270	73,500
Average Exercise Price	$ 48.79	$ 50.34	$ 64.43

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, 2016	Dec. 31, 2015
Accrued Liabilities [Abstract]
Employee costs	$ 15,394	$ 12,641
Lease operating expenses	10,075	17,220
Interest payable	6,524	6,321
Third-party credits	2,998	3,326
Taxes	2,219	3,767
Other	2,441	3,643
Total accrued liabilities	$ 39,651	$ 46,918

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Long-term debt and other long-term liabilites [Abstract]
Credit agreement with average interest rates of 2.8% and 2.6% at December 31, 2016 and 2015, respectively	$ 160,800	$ 281,000
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	810,800	931,000
Less: unamortized discount	(2,804)	(3,338)
Less: debt issuance costs, net	(7,079)	(8,667)
Total long-term debt	$ 800,917	$ 918,995
Line of Credit Facility, Interest Rate at Period End	2.80%	2.60%

- 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term debt and other long-term liabilites [Abstract]
ARO liability	$ 70,170	$ 98,297	$ 100,567
Capital lease obligations	18,918	22,466
Workers' compensation	15,163	16,551
Separation benefit plans	4,943	9,886
Deferred compensation plan	4,578	4,244
Gas balancing liability	3,789	5,047
Other	410	410
Other liabilities	117,971	156,901
Less current portion	14,907	16,560
Total other long-term liabilities	$ 103,064	$ 140,341

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt and Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Ending December 31, [Abstract]
2017	$ 6,168
2018	6,168
2019	6,168
2020	6,168
2021	3,769
Total future payments	28,441
Less payments related to:
Maintenance	7,659
Interest	1,864
Present value of future minimum payments	$ 18,918	$ 22,466

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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	LIBOR plus 1.00%
Line of credit facility, amount borrowed	$ 160,800	$ 281,000
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%
Year One	$ 14,900
Year Two	5,500
Year Three	47,900
Year Four	170,000
Year Five	$ 655,800
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,700
Capital Lease Obligations, Noncurrent	$ 15,200
Discount rate capital leases	4.00%
Maintenance	$ 7,659
Interest	1,864
Capital leases, future minimum payments, average annual payment	$ 4,100
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 [Member]
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. [Member]
Debt Instrument [Line Items]
Percentage of collateral pledged	100.00%
Apr 8, 2016 to Mar 31, 2019 [Member]
Debt Instrument [Line Items]
Senior indebtedness ratio	2.75 to 1
Apr 1, 2019 to Apr 20, 2020 [Member]
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, 2016

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

ARO liability, January 1:

$ 98,297

$ 100,567

Accretion of discount

2,779

3,453

Liability incurred

584

6,754

Liability settled

(1,215)

(2,893)

Liability sold

(10,882)

(421)

Revision of estimates

^[1]

(19,393)

(9,163)

ARO liability, December 31:

70,170

98,297

Less current portion

2,906

3,965

Total long-term ARO liability

$ 67,264

$ 94,332

[1]	Plugging liability estimates were revised in both 2016 and 2015 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

Income Taxes (Reconciliation Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax expense (benefit) computed by applying the statutory rate	$ (72,386)	$ (582,508)	$ 78,029
State income tax expense (benefit), net of federal benefit	(5,687)	(45,768)	6,131
Restricted stock shortfall	5,465	0	0
Statutory depletion and other	1,414	1,328	2,503
Total Income tax expense (benefit)	$ (71,194)	$ (626,948)	$ 86,663

Income Taxes (Schedule Of Total Provision For Income Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current taxes, Federal	$ 0	$ (20,612)	$ 8,594
Current taxes, State	15	(4)	784
Current taxes	15	(20,616)	9,378
Deferred taxes, Federal	(62,923)	(535,691)	68,360
Deferred taxes, State	(8,286)	(70,641)	8,925
Deferred taxes	(71,209)	(606,332)	77,285
Total provision	$ (71,194)	$ (626,948)	$ 86,663

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Allowance for losses and nondeductible accruals	$ 53,967	$ 56,479
Net operating loss carryforward	190,603	140,863
Alternative minimum tax and research and development tax credit carryforward	5,409	5,409
Deferred tax assets, total	249,979	202,751
Depreciation, depletion, amortization, and impairment	(440,690)	(464,295)
Net deferred tax liability	(190,711)	(261,544)
Current deferred tax asset	25,211	14,206
Non-current-deferred tax liability	$ (215,922)	$ (275,750)

Income Taxes Income Taxes (Schedule of Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Balance at January 1:	$ 410	$ 410	$ 0
Additions based on tax positions related to current year	0	0	410
Additions for tax positions of prior years	0	0	0
Reductions for tax positions of prior years	0	0	0
Settlements	0	0	0
Balance at December 31:	$ 410	$ 410	$ 410

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 485,000
Unrecognized tax benefits	$ 410	$ 410	$ 410	$ 0
Start
Operating Loss Carryforwards [Line Items]
Operating loss expiration period	Jan. 01, 2021
End
Operating Loss Carryforwards [Line Items]
Operating loss expiration period	Dec. 31, 2036

Employee Benefit Plans (Details)
$ in Thousands

12 Months Ended

May 05, 2004

Jan. 01, 1997

week

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Defined Benefit Plan Disclosure [Line Items]

Recognized stock compensation expense

$ 9,600

$ 15,300

^[1]

$ 17,400

Deferred compensation plan

$ 4,578

$ 4,244

Employee Thrift Plan

Defined Benefit Plan Disclosure [Line Items]

Contribution of shares, common stock | shares

630,039

235,104

120,333

Recognized stock compensation expense

$ 4,000

$ 6,200

$ 5,200

Separation Plan

Defined Benefit Plan Disclosure [Line Items]

Service period, years

20 years

Maximum period benefit, weeks | week

104

Separation benefit plans expense

$ 3,100

$ 3,000

$ 2,700

Special Separation Benefit Plan

Defined Benefit Plan Disclosure [Line Items]

Service period, years

20 years

Age limit | yr

Change Of Control Contracts

Defined Benefit Plan Disclosure [Line Items]

Employee contract period, years | yr

Employment contract period extension, years

1 year

Grace period following the first anniversary

30 days

Multiple for determination compensation

2.9

Plan 401k

Defined Benefit Plan Disclosure [Line Items]

Additional period for 401k, years

3 years

[1]	In 2015, recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

Transactions With Related Parties Transactions With Related Parties (Schedule of Amount Received in Public and Private Partnerships) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Contract drilling	$ 0	$ 0	$ 4
Well supervision and other fees	254	423	435
General and administrative expense reimbursement	$ 6	$ 18	$ 39

Transactions With Related Parties (Narrative) (Details)	12 Months Ended
Transactions With Related Parties (Narrative) (Details)	Dec. 31, 2016 USD ($) Partnerships Unit	Dec. 31, 2015 USD ($) Partnerships wells	Dec. 31, 2014 USD ($) Partnerships wells	Nov. 30, 2016 USD ($)	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	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	$ 500,000	$ 800,000	$ 1,300,000
Toklan Oil and Gas Company \| John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage	25.80%
Number of wells drilled	0	0	2
Completed wells \| wells		1	1
Revenue from related parties		$ 500,000	$ 1,500,000
Cash received from related parties	$ 0	900,000	1,100,000
Related party accounts receivable balance		0	400,000
Payments for royalties	$ 0	0	$ 200,000
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, 2016

Dec. 31, 2015

Dec. 31, 2014

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Recognized stock compensation expense

$ 9.6

$ 15.3

^[1]

$ 17.4

Capitalized stock compensation cost for our oil and natural gas properties

2.1

3.5

^[1]

3.7

Tax benefit on stock based compensation

$ 3.6

5.8

^[1]

$ 6.7

Performance Shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Reduction in recognized stock compensation expense related to performance shares

3.2

Reduction in capitalized stock compensation cost for our oil and natural gas properties related to performance shares

0.2

Reduction in tax benefit on stock based compensation related to performance shares

$ 1.2

[1]	In 2015, recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by $0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Appreciation Rights) (Details) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	131,770	131,770	145,901
Weighted average price, beginning balance	$ 46.60	$ 46.60	$ 46.59
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0	$ 0	$ 0
Number of shares, exercised	0	0	(14,131)
Weighted average price, exercised	$ 0.00	$ 0.00	$ 46.50
Number of shares, forfeited	(40,515)	0	0
Weighted average price, forfeited	$ 51.76	$ 0	$ 0
Number of shares, ending balance	91,255	131,770	131,770
Weighted average price, ending balance	$ 44.31	$ 46.60	$ 46.60

Stock-Based Compensation Stock-Based Compensation (Shares Authorized Under Stock Appreciation Rights By Exercise Price) (Details) - $44.31 - Stock Appreciation Rights (SARs)	12 Months Ended
	Dec. 31, 2016 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding and exercisable options, number of shares \| shares	91,255
Outstanding and exercisable options weighted average remaining contractual life, years	1 year
Outstanding and exercisable options, weighted average exercise price \| $ / shares	$ 44.31

Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	1,213,822	900,286	776,743
Weighted average price, beginning balance	$ 41.29	$ 50.81	$ 48.70
Number of shares, granted	646,451	724,442	455,122
Weighted average price, granted	$ 5.62	$ 34.06	$ 53.72
Number of shares, vested	(425,195)	(382,902)	(304,804)
Weighted average price, exercised	$ 43.47	$ 49.69	$ 49.68
Number of shares, forfeited	(133,213)	(28,004)	(26,775)
Weighted average price, forfeited	$ 36.87	$ 45.33	$ 51.92
Number of shares, ending balance	1,301,865	1,213,822	900,286
Weighted average price, ending balance	$ 23.32	$ 41.29	$ 50.81
Non-employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	42,064	35,136	35,704
Weighted average price, beginning balance	$ 41.83	$ 50.08	$ 41.07
Number of shares, granted	90,000	25,848	13,768
Weighted average price, granted	$ 12.02	$ 34.04	$ 63.91
Number of shares, vested	(20,248)	(18,920)	(14,336)
Weighted average price, exercised	$ 43.46	$ 46.51	$ 40.93
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$ 0.00	$ 0.00	$ 0.00
Number of shares, ending balance	111,816	42,064	35,136
Weighted average price, ending balance	$ 17.21	$ 41.83	$ 50.08
Time Vested \| Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	936,662	724,766	652,835
Number of shares, granted	494,078	576,361	383,448
Number of shares, vested	(425,195)	(343,657)	(291,712)
Number of shares, forfeited	(75,808)	(20,808)	(19,805)
Number of shares, ending balance	929,737	936,662	724,766
Performance Shares \| Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	277,160	175,520	123,908
Number of shares, granted	152,373	148,081	71,674
Number of shares, vested	0	(39,245)	(13,092)
Number of shares, forfeited	(57,405)	(7,196)	(6,970)
Number of shares, ending balance	372,128	277,160	175,520

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Options) (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	0	9,500	68,920
Weighted average price, beginning balance	$ 0.00	$ 37.69	$ 37.81
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0.00	$ 0.00	$ 0.00
Number of shares, exercised	0	0	(21,490)
Weighted average price, exercised	$ 0.00	$ 0.00	$ 37.83
Number of shares, forfeited	0	(9,500)	(37,930)
Weighted average price, forfeited	$ 0.00	$ 37.69	$ 37.83
Number of shares, ending balance	0	0	9,500
Weighted average price, ending balance	$ 0.00	$ 0.00	$ 37.69

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) - Directors Plan - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	129,500	150,500	171,500
Weighted average price, beginning balance	$ 54.15	$ 54.18	$ 51.70
Number of shares, granted	0	0	0
Weighted average price, granted	$ 0.00	$ 0.00	$ 0.00
Number of shares, exercised	0	0	(21,000)
Weighted average price, exercised	$ 0.00	$ 0.00	$ 33.94
Number of shares, forfeited	(21,000)	(21,000)	0
Weighted average price, forfeited	$ 62.40	$ 54.35	$ 0.00
Number of shares, ending balance	108,500	129,500	150,500
Weighted average price, ending balance	$ 52.56	$ 54.15	$ 54.18

Stock-Based Compensation (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) - Directors Plan	12 Months Ended
	Dec. 31, 2016 $ / 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	2 years 10 months 12 days
Outstanding and exercisable options, weighted average exercise price	$ 37.58
$53.81 - $73.26
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Minimum Limit	53.81
Maximum limit	$ 73.26
Outstanding and exercisable options, number of shares \| shares	70,000
Outstanding and exercisable options weighted average remaining contractual life, years	2 years 2 months 15 days
Outstanding and exercisable options, weighted average exercise price	$ 60.79

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 6.5
Unrecognized compensation cost, expect to be capitalized	$ 1.0
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	91,255	131,770	131,770
Exercisable options intrinsic value	$ 0.0
Weighted average remaining contractual term, years	1 year
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance				4,500,000
Number of shares, ending balance	1,413,681
Exercisable options intrinsic value	$ 38.0
Vesting Period	3 years
Grant date fair value	$ 4.5	$ 24.5	$ 24.1
Number of shares, vested	(445,443)
Exercised intrinsic value	$ 4.1
Restricted stock weighted average remaining contractual term, years	1 year
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Shares vested	0	0	0
Maximum Number of Shares of Common Stock Previously Allowed for the Issuance	2,700,000
Vesting rate of options	20.00%
Directors Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Exercisable options intrinsic value	$ 0.0
Weighted average remaining contractual term, years	2 years 6 months
Vesting Period	6 months
Director option awards	3,500
2016 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	102.00%
2015 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	10.00%
2014 \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	41.00%
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
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%
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%

Derivatives Derivatives (Schedule of Non-designated Hedges Outstanding) (Details)

12 Months Ended

Dec. 31, 2016

$ / Unit

MMBTU

bbl

Natural gas | Swap | If Nymex | Jan'17 - Mar'17

Derivative Instruments, Gain (Loss) [Line Items]

Swap Price

3.044

Hedged Volume (MMBtu/day) | MMBTU

70,000

Natural gas | Swap | If Nymex | Apr'17 - Dec'17

Derivative Instruments, Gain (Loss) [Line Items]

Swap Price

2.960

Hedged Volume (MMBtu/day) | MMBTU

60,000

Natural gas | Swap | If Nymex | Jan'18 - Dec'18

Derivative Instruments, Gain (Loss) [Line Items]

Swap Price

3.025

Hedged Volume (MMBtu/day) | MMBTU

10,000

Natural gas | Basis Swap | If Nymex | Jan'17 - Dec'17

Derivative Instruments, Gain (Loss) [Line Items]

Swap Price

(0.215)

^[1]

Hedged Volume (MMBtu/day) | MMBTU

20,000

Natural gas | Basis Swap | If Nymex | Jan'18 - Dec'18

Derivative Instruments, Gain (Loss) [Line Items]

Swap Price

(0.208)

^[1]

Hedged Volume (MMBtu/day) | MMBTU

10,000

Natural gas | Collar | If Nymex | Jan'17 - Oct'17

Derivative Instruments, Gain (Loss) [Line Items]

Ceiling Price

3.10

Floor Price

2.88

Hedged Volume (MMBtu/day) | MMBTU

20,000

Natural gas | Three-way collar | If Nymex | Jan'17 - Dec'17

Derivative Instruments, Gain (Loss) [Line Items]

Ceiling Price

3.32

Subfloor Price

2.00

Floor Price

2.50

Hedged Volume (MMBtu/day) | MMBTU

15,000

Natural gas | Three-way collar | If Nymex | Jan'18 - Mar'18

Derivative Instruments, Gain (Loss) [Line Items]

Ceiling Price

4.43

Subfloor Price

2.50

Floor Price

3.25

Hedged Volume (MMBtu/day) | MMBTU

10,000

Crude Oil | Three-way collar | Wti Nymex | Jan'17 - Dec'17

Derivative Instruments, Gain (Loss) [Line Items]

Ceiling Price

60.98

Subfloor Price

39.58

Floor Price

49.79

Hedged Volume (Bbl/day) | bbl

3,750

[1]	After December 31, 2016, the basis swaps for February through October 2017 and April through October 2018 were liquidated for $0.6 million and $0.5 million, respectively.

Derivatives (Schedule Of Subsequent Non-designated Hedges) (Details) - Natural gas - If Nymex $ in Millions	2 Months Ended	12 Months Ended
	Feb. 24, 2017 USD ($) $ / Unit MMBTU	Dec. 31, 2016 MMBTU $ / Unit
Jan'18 - Mar'18 \| Three-way collar
Derivative Instruments, Gain (Loss) [Line Items]
Subfloor Price		2.50
Floor Price		3.25
Ceiling Price		4.43
Hedged Volume (MMBtu/day) \| MMBTU		10,000
Subsequent to December 31, 2016 \| Feb'17 - Oct'17 \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Liquidated derivatives \| $	$ 0.6
Subsequent to December 31, 2016 \| Apr'18 - Oct'18 \| Basis Swap
Derivative Instruments, Gain (Loss) [Line Items]
Liquidated derivatives \| $	$ 0.5
Subsequent to December 31, 2016 \| Apr'17 - Oct'17 \| Swap
Derivative Instruments, Gain (Loss) [Line Items]
Swap Price	3.505
Hedged Volume (MMBtu/day) \| MMBTU	10,000
Subsequent to December 31, 2016 \| Nov'17 - Dec'17 \| Three-way collar
Derivative Instruments, Gain (Loss) [Line Items]
Subfloor Price	2.75
Floor Price	3.50
Ceiling Price	4
Hedged Volume (MMBtu/day) \| MMBTU	10,000
Subsequent to December 31, 2016 \| Jan'18 - Mar'18 \| Three-way collar
Derivative Instruments, Gain (Loss) [Line Items]
Subfloor Price	2.69
Floor Price	3.38
Ceiling Price	4.17
Hedged Volume (MMBtu/day) \| MMBTU	40,000
Subsequent to December 31, 2016 \| Apr'18 - Dec'18 \| Three-way collar
Derivative Instruments, Gain (Loss) [Line Items]
Subfloor Price	2.50
Floor Price	3
Ceiling Price	3.66
Hedged Volume (MMBtu/day) \| MMBTU	10,000

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 0	$ 10,186
Non-current derivative assets	377	968
Total derivatives assets	377	11,154
Current derivative liabilities	21,564	0
Non-current derivative liabilities	415	285
Total derivative liabilities	21,979	285
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Current derivative assets	0	10,186
Non-current derivative assets	377	968
Current derivative liabilities	21,564	0
Non-current derivative liabilities	$ 415	$ 285

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, expected to be settled within one year or normal operating cycle, if longer. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References + Details

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) on Derivatives

$ (22,813)

$ 26,345

Cash receipts (payments) on derivatives settled

9,658

46,615

Commodity Contract

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) on Derivatives

^[1]

$ (22,813)

$ 26,345

[1]	Amount settled during the period is a gain of $9,658 and a gain of $46,615, respectively.

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	$ (21,600)
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	377	$ 11,154
Liabilities	(21,979)	(285)
Financial assets (liabilities)	(21,602)	10,869
Commodity Contract \| Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	878	2,794
Liabilities	(15,358)	(1,019)
Financial assets (liabilities)	(14,480)	1,775
Commodity Contract \| Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	43	10,145
Liabilities	(7,165)	(1,051)
Financial assets (liabilities)	(7,122)	9,094
Commodity Contract \| Effect of Netting
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	(544)	(1,785)
Liabilities	544	1,785
Financial assets (liabilities)	$ 0	$ 0

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

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

Beginning of period

$ 9,094

$ 3,355

Included in earnings

^[1]

(9,042)

15,260

Settlements

(7,174)

(9,521)

End of period

(7,122)

9,094

Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period

$ (16,216)

$ 5,739

[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, 2016

USD ($)

$ / Unit

Crude Oil | Three-way collar

Derivative liabilities, Fair Value | $

$ (1,167)

^[1]

Derivatives assets, Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Crude Oil | Minimum | Three-way collar

Derivative, Forward Price

Crude Oil | Maximum | Three-way collar

Derivative, Forward Price

4.29

Natural gas | Collar

Derivative liabilities, Fair Value | $

$ (3,332)

^[1]

Derivatives assets, Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Natural gas | Three-way collar

Derivative liabilities, Fair Value | $

$ (2,623)

^[1]

Derivatives assets, Valuation Technique(s)

Discounted cash flow

^[1]

Unobservable Input

Forward commodity price curve

^[1]

Natural gas | Minimum | Collar

Derivative, Forward Price

Natural gas | Minimum | Three-way collar

Derivative, Forward Price

Natural gas | Maximum | Collar

Derivative, Forward Price

0.79

Natural gas | Maximum | Three-way collar

Derivative, Forward Price

0.71

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

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
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	640,100	$ 638,000
Estimated fair value of long-term debt	$ 649,900	$ 455,500

Commitments And Contingencies (Details) - USD ($)	12 Months Ended
Commitments And Contingencies (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Commitments [Line Items]
Lease expiration date	Dec. 31, 2021
Future minimum rental payments under leases, year one	$ 3,000,000
Future minimum rental payments under leases, year two	900,000
Future minimum rental payments under leases, year three	100,000
Future minimum rental payments under leases, year four	72,000
Rent expense incurred	$ 11,100,000	$ 12,900,000	$ 13,600,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
2017	$ 6,168,000
2018	6,168,000
2019	6,168,000
2020	6,168,000
2021	3,769,000
Maintenance	7,659,000
Interest	1,864,000
Capital leases, future minimum payments, average annual payment	$ 4,100,000
Capital lease fair market value percentage for purchase	10.00%
Repurchase of limited units outstanding	20.00%
Repurchase of limited units outstanding amount	$ 5,000	$ 118,000	$ 45,000
Drilling Equipment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	2,300,000
Other Commitment, Due in Second Year	1,900,000
Corporate, Non-Segment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 1,400,000

Industry Segment Information (Revenue From Different Segments) (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Mar. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

rig

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

rig

systems

Dec. 31, 2014

USD ($)

systems

Revenues

Oil and natural gas

$ 294,221

$ 385,774

$ 740,079

Contract drilling

122,086

265,668

476,517

Gas gathering and processing

185,870

202,789

356,348

Total revenues

$ 174,280

$ 153,408

$ 138,305

$ 136,184

$ 172,292

$ 212,393

$ 214,447

$ 255,099

602,177

854,231

1,572,944

Operating costs:

Oil and natural gas

120,184

166,046

187,916

Contract drilling

88,154

156,408

274,933

Gas gathering and processing

137,609

161,556

306,831

Total operating costs

345,947

484,010

769,680

Depreciation, depletion, and amortization

208,353

352,742

402,888

Impairment of gas gathering systems

Impairments

161,563

1,634,628

158,069

Total expenses

715,863

2,471,380

1,330,637

General and administrative expense

(33,337)

(34,358)

(41,027)

Gain (loss) on disposition of assets

2,540

(7,229)

8,953

Gain (loss) on derivatives

(22,813)

26,345

30,147

Interest expense, net

(39,829)

(31,963)

(17,371)

Other

307

(70)

Income (loss) before income taxes

(206,818)

(1,664,309)

222,939

Identifiable assets:

Oil and natural gas

965,159

1,218,036

$ 2,856,833

965,159

1,218,036

2,856,833

Contract drilling

941,676

993,015

1,059,980

941,676

993,015

1,059,980

Gas gathering and processing

461,600

478,661

500,255

461,600

478,661

500,255

Total identifiable assets

2,368,435

^[1]

2,689,712

^[2]

4,417,068

^[3]

2,368,435

^[1]

2,689,712

^[2]

4,417,068

^[3]

Corporate land and building

58,188

49,890

16,104

58,188

49,890

16,104

Other corporate assets

52,680

^[4]

60,240

^[5]

30,300

^[6]

52,680

^[4]

60,240

^[5]

30,300

^[6]

Total assets

2,479,303

2,799,842

4,463,472

2,479,303

2,799,842

4,463,472

Capital expenditures:

Total capital expenditures

142,155

454,287

1,013,280

^[7]

Non-cash ceiling test write-down net of tax

100,600

$ 1,000,000

$ 47,700

Number of gas gathering systems impaired | systems

Capital lease obligations incurred

$ 0

$ (28,202)

Oil and Natural Gas [Member]

Revenues

Oil and natural gas

294,221

385,774

740,079

Contract drilling

Gas gathering and processing

Total revenues

294,221

385,774

740,079

Operating costs:

Oil and natural gas

126,739

170,831

192,429

Contract drilling

Gas gathering and processing

Total operating costs

126,739

170,831

192,429

Depreciation, depletion, and amortization

113,811

251,944

276,088

Impairment of Oil and Gas Properties

161,563

1,599,348

76,683

Total expenses

402,113

2,022,123

545,200

Total operating income (loss)

(107,892)

^[8]

(1,636,349)

^[9]

194,879

^[10]

General and administrative expense

Gain (loss) on disposition of assets

(324)

(147)

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

(108,216)

(1,636,496)

194,879

Identifiable assets:

Oil and natural gas

965,159

1,218,036

2,856,833

965,159

1,218,036

2,856,833

Contract drilling

Gas gathering and processing

Total identifiable assets

965,159

^[1]

1,218,036

^[2]

2,856,833

^[3]

965,159

^[1]

1,218,036

^[2]

2,856,833

^[3]

Corporate land and building

Other corporate assets

^[4]

^[5]

^[6]

^[4]

^[5]

^[6]

Total assets

965,159

1,218,036

2,856,833

965,159

1,218,036

2,856,833

Capital expenditures:

Total capital expenditures

89,562

267,944

740,262

^[7]

Drilling [Member]

Revenues

Oil and natural gas

Contract drilling

122,086

287,767

566,012

Gas gathering and processing

Total revenues

122,086

287,767

566,012

Operating costs:

Oil and natural gas

Contract drilling

88,154

174,757

337,371

Gas gathering and processing

Total operating costs

88,154

174,757

337,371

Depreciation, depletion, and amortization

46,992

56,135

85,370

Impairment of contract drilling equipment

^[11]

8,314

74,318

Total expenses

135,146

239,206

497,059

Total operating income (loss)

(13,060)

^[8]

48,561

^[9]

68,953

^[10]

General and administrative expense

Gain (loss) on disposition of assets

3,184

(7,516)

8,819

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

(9,876)

41,045

77,772

Identifiable assets:

Oil and natural gas

Contract drilling

941,676

993,015

1,059,980

941,676

993,015

1,059,980

Gas gathering and processing

Total identifiable assets

941,676

^[1]

993,015

^[2]

1,059,980

^[3]

941,676

^[1]

993,015

^[2]

1,059,980

^[3]

Corporate land and building

Other corporate assets

^[4]

^[5]

^[6]

^[4]

^[5]

^[6]

Total assets

941,676

993,015

$ 1,059,980

941,676

993,015

1,059,980

Capital expenditures:

Total capital expenditures

19,134

84,802

176,683

^[7]

Number of drilling rigs removed from service | rig

Mid-Stream [Member]

Revenues

Oil and natural gas

Contract drilling

Gas gathering and processing

237,785

268,012

445,934

Total revenues

237,785

268,012

445,934

Operating costs:

Oil and natural gas

Contract drilling

Gas gathering and processing

182,969

221,994

391,903

Total operating costs

182,969

221,994

391,903

Depreciation, depletion, and amortization

45,715

43,676

40,434

Impairment of gas gathering systems

^[11]

26,966

7,068

Total expenses

228,684

292,636

439,405

Total operating income (loss)

9,101

^[8]

(24,624)

^[9]

6,529

^[10]

General and administrative expense

Gain (loss) on disposition of assets

(302)

465

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

8,799

(24,159)

6,626

Identifiable assets:

Oil and natural gas

$ 0

Contract drilling

Gas gathering and processing

461,600

478,661

500,255

461,600

478,661

500,255

Total identifiable assets

461,600

^[1]

478,661

^[2]

500,255

^[3]

461,600

^[1]

478,661

^[2]

500,255

^[3]

Corporate land and building

Other corporate assets

^[4]

^[5]

^[6]

^[4]

^[5]

^[6]

Total assets

461,600

478,661

500,255

461,600

478,661

500,255

Capital expenditures:

Total capital expenditures

16,796

63,476

79,268

^[7]

Other Segments [Member]

Revenues

Oil and natural gas

Contract drilling

Gas gathering and processing

Gas gathering and processing

Total operating costs

Depreciation, depletion, and amortization

1,835

987

996

Impairments

^[11]

^[12]

^[13]

Total expenses

1,835

987

996

Total operating income (loss)

(1,835)

^[8]

(987)

^[9]

(996)

^[10]

General and administrative expense

(33,337)

(34,358)

(41,027)

Gain (loss) on disposition of assets

(18)

(31)

Gain (loss) on derivatives

(22,813)

26,345

30,147

Interest expense, net

(39,829)

(31,963)

(17,371)

Other

307

(70)

Income (loss) before income taxes

(97,525)

(40,949)

(29,280)

Identifiable assets:

Oil and natural gas

Contract drilling

Gas gathering and processing

Total identifiable assets

^[1]

^[2]

^[3]

^[1]

^[2]

^[3]

Corporate land and building

58,188

49,890

16,104

58,188

49,890

16,104

Other corporate assets

52,680

^[4]

60,240

^[5]

30,300

^[6]

52,680

^[4]

60,240

^[5]

30,300

^[6]

Total assets

110,868

110,130

46,404

110,868

110,130

46,404

Capital expenditures:

Total capital expenditures

16,663

38,065

17,067

^[7]

Intersubsegment Eliminations [Member]

Revenues

Oil and natural gas

Contract drilling

(22,099)

(89,495)

Gas gathering and processing

(51,915)

(65,223)

(89,586)

Total revenues

(51,915)

(87,322)

(179,081)

Operating costs:

Oil and natural gas

(6,555)

(4,785)

(4,513)

Contract drilling

(18,349)

(62,438)

Gas gathering and processing

(45,360)

(60,438)

(85,072)

Total operating costs

(51,915)

(83,572)

(152,023)

Depreciation, depletion, and amortization

Impairments

^[11]

^[12]

^[13]

Total expenses

(51,915)

(83,572)

(152,023)

Total operating income (loss)

^[8]

(3,750)

^[9]

(27,058)

^[10]

General and administrative expense

Gain (loss) on disposition of assets

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

(3,750)

(27,058)

Identifiable assets:

Oil and natural gas

Contract drilling

Gas gathering and processing

Total identifiable assets

^[1]

^[2]

^[3]

^[1]

^[2]

^[3]

Corporate land and building

Other corporate assets

^[4]

^[5]

^[6]

^[4]

^[5]

^[6]

Total assets

$ 0

Capital expenditures:

Total capital expenditures

$ 0

^[7]

Drilling Equipment

Capital expenditures:

Number of drilling rigs removed from service | rig

[1]	Identifiable assets are those used in Unit’s operations in each industry segment.
[2]	Identifiable assets are those used in Unit’s operations in each industry segment.
[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.
[5]	Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, transportation equipment, furniture, and equipment.
[6]	Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, transportation equipment, furniture, and equipment.
[7]	Our mid-stream segment entered into capital leases for $28.2 million.
[8]	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.
[9]	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.
[10]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.
[11]	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).
[12]	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 a $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.
[13]	We incurred non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million, net of tax). Impairment for contract drilling equipment includes a $74.3 million pre-tax write-down for 31 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek.

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

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Revenues

$ 174,280

$ 153,408

$ 138,305

$ 136,184

$ 172,292

$ 212,393

$ 214,447

$ 255,099

$ 602,177

$ 854,231

$ 1,572,944

Gross profit (loss)

^[1]

37,773

(27,365)

(74,223)

(49,871)

(492,877)

(314,657)

(419,916)

(389,699)

Net income (loss)

$ 1,683

$ (24,022)

$ (72,136)

$ (41,149)

$ (309,337)

$ (205,281)

$ (274,389)

$ (248,354)

$ (135,624)

$ (1,037,361)

$ 136,276

Net income (loss) per common share:

Basic

$ 0.03

$ (0.48)

$ (1.44)

$ (0.83)

$ (6.29)

$ (4.18)

$ (5.58)

$ (5.07)

$ (2.71)

$ (21.12)

$ 2.80

Diluted

$ 0.03

^[2]

$ (0.48)

^[2]

$ (1.44)

^[2]

$ (0.83)

^[2]

$ (6.29)

$ (4.18)

$ (5.58)

$ (5.07)

$ (2.71)

$ (21.12)

$ 2.78

[1]	Gross profit (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]	Due to the effect of the income in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized costs:
Proved properties	$ 5,446,305	$ 5,401,618	$ 4,990,753
Unproved properties not being amortized	314,867	337,099	485,568
Capitalized costs gross	5,761,172	5,738,717	5,476,321
Accumulated depreciation, depletion, amortization, and impairment	(4,900,304)	(4,631,404)	(2,786,678)
Net capitalized costs	860,868	1,107,313	2,689,643
Costs incurred:
Unproved properties acquired	21,675	41,777	76,041
Proved properties acquired	564	179	5,723
Exploration	17,325	19,222	68,811
Development	80,582	208,845	615,252
Asset retirement obligation	(30,906)	(5,693)	(37,687)
Total costs incurred	$ 89,240	$ 264,330	$ 728,140

Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Unproved properties acquired and wells in progress	$ 314,867	$ 337,099	$ 485,568
2016
Unproved properties acquired and wells in progress	23,494
2015
Unproved properties acquired and wells in progress	41,445
2014
Unproved properties acquired and wells in progress	55,562
2013 and prior
Unproved properties acquired and wells in progress	$ 194,366

Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil and Gas Disclosures [Abstract]
Revenues	$ 282,742	$ 371,335	$ 723,566
Production costs	(108,822)	(152,560)	(165,315)
Depreciation, depletion, amortization, and impairment	(268,901)	(1,844,726)	(347,220)
Results of operations, income before income taxes	(94,981)	(1,625,951)	211,031
Income tax (expense) benefit	32,696	612,496	(82,028)
Results of operations for producing activities (excluding corporate overhead and financing costs)	$ (62,285)	$ (1,013,455)	$ 129,003

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, 2016

MBoe

bbl

Mcf

Dec. 31, 2015

MBoe

bbl

Mcf

Dec. 31, 2014

MBoe

bbl

Mcf

Proved developed and undeveloped reserves:

Beginning of year (MBoe) | MBoe

135,233

179,023

159,934

Revision of previous estimate (MBoe) | MBoe

^[1]

(8,300)

(36,573)

(10,905)

Extension and discovery (MBoe) | MBoe

5,690

6,651

35,101

Infill reserves in existing proved fields (MBoe) | MBoe

7,504

6,304

14,217

Purchase of mineral in place (MBoe) | MBoe

262

385

Production (MBoe) | MBoe

(17,277)

(19,981)

(18,282)

Sales (MBoe) | MBoe

(5,338)

(191)

(1,427)

End of year (MBoe) | MBoe

117,774

135,233

179,023

Proved developed reserves:

Beginning of year (MBoe) | MBoe

115,296

136,790

123,403

End of year (MBoe) | MBoe

99,079

115,296

136,790

Proved undeveloped reserves

Beginning of year (MBoe) | MBoe

19,937

42,233

36,531

End of year (MBoe) | MBoe

18,695

19,937

42,233

Oil (bbls)

Proved developed and undeveloped reserves:

Beginning of year

16,735

22,667

21,765

Revision of previous estimates

^[1]

(549)

(3,954)

(3,174)

Extensions and discoveries

1,816

1,208

5,327

Infill reserves in existing proved fields

663

670

2,775

Purchases of minerals in place

114

236

Production

(2,974)

(3,783)

(3,844)

Sales

(109)

(73)

(418)

End of year

15,696

16,735

22,667

Proved developed reserves:

Beginning of year

14,679

17,448

15,594

End of year

12,724

14,679

17,448

Proved undeveloped reserves

Beginning of year

2,056

5,219

6,171

End of year

2,972

2,056

5,219

Natural Gas Liquids (bbls)

Proved developed and undeveloped reserves:

Beginning of year

37,687

48,529

41,205

Revision of previous estimates

^[1]

(2,473)

(9,367)

(2,266)

Extensions and discoveries

1,588

1,948

10,850

Infill reserves in existing proved fields

2,724

1,861

3,577

Purchases of minerals in place

Production

(5,014)

(5,274)

(4,629)

Sales

(73)

(10)

(296)

End of year

34,482

37,687

48,529

Proved developed reserves:

Beginning of year

31,218

35,850

30,437

End of year

28,502

31,218

35,850

Proved undeveloped reserves

Beginning of year

6,469

12,679

10,768

End of year

5,980

6,469

12,679

Natural gas (Mcf)

Proved developed and undeveloped reserves:

Beginning of year | Mcf

484,868

646,961

581,784

Revision of previous estimates | Mcf

^[1]

(31,670)

(139,514)

(32,790)

Extensions and discoveries | Mcf

13,720

20,974

113,541

Infill reserves in existing proved fields | Mcf

24,704

22,641

47,189

Purchases of minerals in place | Mcf

630

368

Production | Mcf

(55,735)

(65,546)

(58,854)

Sales | Mcf

(30,938)

(648)

(4,277)

End of year | Mcf

405,579

484,868

646,961

Proved developed reserves:

Beginning of year | Mcf

416,395

500,950

464,234

End of year | Mcf

347,121

416,395

500,950

Proved undeveloped reserves

Beginning of year | Mcf

68,473

146,011

117,550

End of year | Mcf

58,458

68,473

146,011

[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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash flows	$ 2,030,925	$ 2,475,898	$ 6,398,236
Future production costs	(861,625)	(1,017,777)	(2,069,636)
Future development costs	(173,446)	(228,445)	(560,102)
Future income tax expenses	(141,752)	(230,544)	(1,228,533)
Future net cash flows	854,102	999,132	2,539,965
10% annual discount for estimated timing of cash flows	(335,892)	(409,646)	(1,104,221)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves	$ 518,210	$ 589,486	$ 1,435,744	$ 1,225,976
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Reserve Quantities [Line Items]
Sales and transfers of oil and natural gas produced, net of production costs	$ (173,920)	$ (218,115)	$ (558,252)
Net changes in prices and production costs	(94,026)	(1,356,333)	(33,259)
Revisions in quantity estimates and changes in production timing	(51,979)	(213,945)	(135,125)
Extensions, discoveries, and improved recovery, less related costs	84,738	95,671	635,752
Changes in estimated future development costs	70,976	227,857	96,339
Previously estimated cost incurred during the period	16,602	59,117	164,430
Purchases of minerals in place	2,652	0	8,395
Sales of minerals in place	(17,248)	(3,338)	(19,135)
Accretion of discount	69,069	209,979	179,190
Net change in income taxes	44,241	562,838	(98,119)
Other-net	(22,381)	(209,989)	(30,448)
Net change	(71,276)	(846,258)	209,768
Beginning of year	589,486	1,435,744	1,225,976
End of year	$ 518,210	$ 589,486	$ 1,435,744

Supplemental Oil And Gas Disclosures Supplemental Oil and Gas Disclosures (Narrative) (Details)	12 Months Ended
	Dec. 31, 2016 $ / Unit
Oil (bbls)
Average Sales Prices	42.75
Natural Gas Liquids (bbls)
Average Sales Prices	19.74
Natural gas (Mcf)
Average Sales Prices	2.48

Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	$ 5,199	$ 5,039	$ 5,342
Additions charged to costs and expenses	785	1,191	3,562
Deductions and net write-offs	(2,211)	(1,031)	(3,865)
Balance at end of period	$ 3,773	$ 5,199	$ 5,039