Unit (UNTC) 10-Q 9 Aug 16 2016 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 22, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	798,949
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		51,503,672

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 974	$ 835
Accounts receivable, net of allowance for doubtful accounts of $5,174 and $5,199 at June 30, 2016 and December 31, 2015, respectively	67,506	79,941
Materials and supplies	3,324	3,565
Current derivative asset (Note 10)	0	10,186
Current income tax receivable	2,033	21,002
Current deferred tax asset	8,598	14,206
Assets held for sale	0	615
Prepaid expenses and other	6,859	9,908
Total current assets	89,294	140,258
Oil and natural gas properties on the full cost method:
Proved properties	5,420,972	5,401,618
Unproved properties not being amortized	321,191	337,099
Drilling equipment	1,567,765	1,567,560
Gas gathering and processing equipment	697,573	689,063
Saltwater disposal systems	60,527	60,316
Corporate land and building	56,149	49,890
Transportation equipment	34,055	40,072
Other	45,777	45,489
Property, plant, and equipment, gross	8,204,009	8,191,107
Less accumulated depreciation, depletion, amortization, and impairment	5,818,163	5,609,980
Net property and equipment	2,385,846	2,581,127
Goodwill	62,808	62,808
Non-current derivative asset (Note 10)	0	968
Other assets	14,148	14,681
Total assets	2,552,096	2,799,842
Current liabilities:
Accounts payable	72,744	87,413
Accrued liabilities (Note 5)	46,368	46,918
Current derivative liability (Note 10)	9,646	0
Current portion of other long-term liabilities (Note 6)	17,999	16,560
Total current liabilities	146,757	150,891
Long-term debt less debt issuance costs (Note 6)	875,051	918,995
Non-current derivative liability (Note 10)	3,420	285
Other long-term liabilities (Note 6)	103,926	140,341
Deferred income taxes	211,721	275,750
Shareholders' equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued	0	0
Common stock, $.20 par value, 175,000,000 shares authorized, 51,504,959 and 50,413,101 shares issued as of June 30, 2016 and December 31, 2015, respectively	10,016	9,831
Capital in excess of par value	497,312	486,571
Retained earnings	703,893	817,178
Total shareholders' equity	1,211,221	1,313,580
Total liabilities and shareholders' equity	$ 2,552,096	$ 2,799,842

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 5,174	$ 5,199
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 0.20	$ 0.20
Common stock, shares authorized	175,000,000	175,000,000
Common stock, shares issued	51,504,959	50,413,101

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Oil and natural gas	$ 69,190	$ 107,256	$ 127,464	$ 213,325
Contract drilling	24,257	55,015	62,967	150,092
Gas gathering and processing	44,858	52,176	84,058	106,129
Total revenues	138,305	214,447	274,489	469,546
Oil and natural gas:
Operating costs	33,331	45,972	66,677	91,183
Depreciation, depletion, and amortization	30,411	68,101	62,243	145,219
Impairment of oil and natural gas properties (Note 2)	74,291	410,536	112,120	811,129
Contract drilling:
Operating costs	19,254	36,485	47,352	88,231
Depreciation	10,918	13,265	23,113	28,278
Impairment of contract drilling equipment (Note 3)	0	8,314	0	8,314
Gas gathering and processing:
Operating costs	32,381	40,592	63,447	84,767
Depreciation and amortization	11,515	10,848	22,974	21,542
General and administrative	8,382	9,624	17,097	18,994
Gain on disposition of assets	(477)	(415)	(669)	(960)
Total operating expenses	220,006	643,322	414,354	1,296,697
Loss from operations	(81,701)	(428,875)	(139,865)	(827,151)
Other income (expense):
Interest, net	(10,606)	(7,956)	(20,223)	(15,196)
Gain (loss) on derivatives	(22,672)	(1,919)	(11,743)	4,667
Other	1	24	(14)	22
Total other income (expense)	(33,277)	(9,851)	(31,980)	(10,507)
Loss before income taxes	(114,978)	(438,726)	(171,845)	(837,658)
Income tax expense (benefit):
Current	0	803	0	868
Deferred	(42,842)	(165,140)	(58,560)	(315,783)
Total income taxes	(42,842)	(164,337)	(58,560)	(314,915)
Net loss	$ (72,136)	$ (274,389)	$ (113,285)	$ (522,743)
Net loss per common share:
Basic	$ (1.44)	$ (5.58)	$ (2.27)	$ (10.66)
Diluted	$ (1.44)	$ (5.58)	$ (2.27)	$ (10.66)

Condensed Consolidated Stateme5

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
OPERATING ACTIVITIES:
Net loss	$ (113,285)	$ (522,743)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	109,522	196,576
Impairments (Notes 2 and 3)	112,120	819,443
(Gain) loss on derivatives	11,743	(4,667)
Cash receipts on derivatives settled	12,192	21,082
Deferred tax benefit	(58,560)	(315,783)
Gain on disposition of assets	(946)	(960)
Employee stock compensation plans	7,703	12,329
Other, net	(2,755)	1,944
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	5,443	77,894
Accounts payable	24,077	(16,327)
Material and supplies	241	(2,366)
Accrued liabilities	3,411	(11,811)
Income taxes	18,969	(1,845)
Other, net	2,841	4,840
Net cash provided by operating activities	132,716	257,606
INVESTING ACTIVITIES:
Capital expenditures	(124,182)	(371,572)
Proceeds from disposition of assets	46,627	5,130
Other	169	0
Net cash used in investing activities	(77,386)	(366,442)
FINANCING ACTIVITIES:
Borrowings under credit agreement	150,300	396,000
Payments under credit agreement	(195,300)	(281,500)
Payments on capitalized leases	(1,828)	(1,757)
Tax (benefit) expense from stock compensation	(376)	4
Book overdrafts	(7,987)	(4,121)
Net cash (used in) provided by financing activities	(55,191)	108,626
Net increase (decrease) in cash and cash equivalents	139	(210)
Cash and cash equivalents, beginning of period	835	1,049
Cash and cash equivalents, end of period	974	839
Cash paid during the year for:
Interest paid (net of capitalized)	19,830	15,886
Income taxes	0	3,142
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	30,758	92,743
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	$ 28,884	$ 5,956

Basis Of Preparation And Presen

Basis Of Preparation And Presentation	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis Of Preparation And Presentation	BASIS OF PREPARATION AND PRESENTATION The accompanying unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 25, 2016, for the year ended December 31, 2015 . In the opinion of our management, the accompanying unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state the following: • Balance Sheets at June 30, 2016 and December 31, 2015 ; • Statements of Operations for the three and six months ended June 30, 2016 and 2015 ; and • Statements of Cash Flows for the six months ended June 30, 2016 and 2015 . Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the six months ended June 30, 2016 and 2015 are not necessarily indicative of the results to be realized for the full year of 2016 , or that we realized for the full year of 2015 . Certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. There was no impact to consolidated net income (loss) or shareholders' equity.

Oil and Natural Gas Properties

Oil and Natural Gas Properties	6 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment [Abstract]
Oil and Natural Gas Properties	OIL AND NATURAL GAS PROPERTIES Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible. During the first quarter of 2015, the 12-month average commodity prices decreased significantly, resulting in a non-cash ceiling test write-down of $400.6 million pre-tax ( $249.4 million , net of tax). During the second quarter of 2015, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $410.5 million pre-tax ( $255.6 million , net of tax). During the first quarter of 2016, the 12-month average commodity prices continued to decrease, resulting in a non-cash ceiling test write-down of $37.8 million pre-tax ( $23.5 million , net of tax). For the second quarter of 2016, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $74.3 million pre-tax ( $46.3 million , net of tax).

Divestitures

Divestitures	6 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment Impairment or Disposal [Abstract]
Divestitures	DIVESTITURES Oil and Natural Gas We sold non-core oil and natural gas assets, net of related expenses, for $43.6 million during the first six months of 2016, compared to less than $0.1 million during the first six months of 2015. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized. Contract Drilling During the second quarter of 2015, we recorded a write-down of approximately $8.3 million pre-tax on drilling equipment that was being held for sale.

Loss Per Share

Loss Per Share	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Loss Per Share	LOSS PER SHARE Information related to the calculation of loss per share follows: Loss (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the three months ended June 30, 2016 Basic loss per common share $ (72,136 ) 50,074 $ (1.44 ) Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) — — — Diluted loss per common share $ (72,136 ) 50,074 $ (1.44 ) For the three months ended June 30, 2015 Basic loss per common share $ (274,389 ) 49,148 $ (5.58 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (274,389 ) 49,148 $ (5.58 ) Due to the net loss for the three months ended June 30, 2016, approximately 417,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above earnings per share calculation. For the three months ended June 30, 2015, approximately 307,000 weighted average shares were excluded. The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock: Three Months Ended June 30, 2016 2015 Stock options and SARs 240,270 259,085 Average exercise price $ 49.29 $ 50.50 Loss (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the six months ended June 30, 2016 Basic loss per common share $ (113,285 ) 49,977 $ (2.27 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (113,285 ) 49,977 $ (2.27 ) For the six months ended June 30, 2015 Basic loss per common share $ (522,743 ) 49,063 $ (10.66 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (522,743 ) 49,063 $ (10.66 ) Because of the net loss for the six months ended June 30, 2016, approximately 332,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above earnings per share calculation. For the six months ended June 30, 2015, approximately 206,000 weighted average shares were excluded. The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock: Six Months Ended June 30, 2016 2015 Stock options and SARs 240,270 261,270 Average exercise price $ 49.29 $ 50.34

Accrued Liabilities

Accrued Liabilities	6 Months Ended
	Jun. 30, 2016
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES Accrued liabilities consisted of the following: June 30, December 31, (In thousands) Lease operating expenses $ 19,157 $ 17,220 Taxes 8,722 3,767 Employee costs 7,007 12,641 Interest payable 6,213 6,321 Third-party credits 2,954 3,326 Derivative settlements 278 — Other 2,037 3,643 Total accrued liabilities $ 46,368 $ 46,918

Long-Term Debt And Other Long-T

Long-Term Debt And Other Long-Term Liabilities	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt And Other Long-Term Liabilities	LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES Long-Term Debt Our long-term debt consisted of the following as of the dates indicated: June 30, December 31, (In thousands) Credit agreement with an average interest rate of 3.9% and 2.6% at June 30, 2016 and December 31, 2015, respectively $ 236,000 $ 281,000 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount 886,000 931,000 Less: unamortized discount (3,076 ) (3,338 ) Less: debt issuance costs, net (7,873 ) (8,667 ) Total long-term debt $ 875,051 $ 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 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 borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a 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 in the credit agreement. At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00% . Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, 2016 , we had $236.0 million outstanding borrowings under our credit agreement. We can use borrowings for financing general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, and (e) general corporate purposes. The credit agreement prohibits, among other things: • the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year; • the incurrence of additional debt with certain limited exceptions; and • the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, 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 quarters of no greater than 2.75 to 1 . Beginning with the quarter ending June 30, 2019, and for each quarter ending thereafter, the credit agreement requires: • a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1 . As of June 30, 2016 , we were in compliance with the covenants 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) outstanding. 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 issuing the Notes, we incurred fees of $14.7 million 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 of and providing for the issuance of the Notes. The Guarantors are most 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 2011 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of 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 June 30, 2016 . Other Long-Term Liabilities Other long-term liabilities consisted of the following: June 30, December 31, (In thousands) Asset retirement obligation (ARO) liability $ 70,926 $ 98,297 Capital lease obligations 20,710 22,466 Workers’ compensation 15,258 16,551 Separation benefit plans 6,386 9,886 Deferred compensation plan 4,430 4,244 Gas balancing liability 3,805 5,047 Other 410 410 121,925 156,901 Less current portion 17,999 16,560 Total other long-term liabilities $ 103,926 $ 140,341 Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning July 1, 2016 (and through 2021) are $18.0 million , $44.3 million , $10.2 million , $244.1 million , and $658.7 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 $3.6 million is included in current portion of other long-term liabilities and the non-current portion of $17.1 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2016 . These capital leases are discounted using annual rates of 4.00% . Total maintenance and interest remaining related to these leases are $8.6 million and $2.3 million , respectively at June 30, 2016 . Annual payments, net of maintenance and interest, average $4.0 million annually through 2021 . At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their fair market value at that time. Future payments required under the capital leases at June 30, 2016: Amount Ending June 30, (In thousands) 2017 $ 6,168 2018 6,168 2019 6,168 2020 6,168 2021 and thereafter 6,853 Total future payments 31,525 Less payments related to: Maintenance 8,552 Interest 2,263 Present value of future minimum payments $ 20,710

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 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. 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 the plugging costs associated with our oil and gas wells. The following table shows certain information about our AROs for the periods indicated: Six Months Ended June 30, 2016 2015 (In thousands) ARO liability, January 1: $ 98,297 $ 100,567 Accretion of discount 1,513 1,757 Liability incurred 212 5,986 Liability settled (605 ) (1,566 ) Liability sold (1) (10,308 ) (246 ) Revision of estimates (2) (18,183 ) (10,130 ) ARO liability, June 30: 70,926 96,368 Less current portion 3,523 3,277 Total long-term ARO $ 67,403 $ 93,091 _______________________ (1) We sold approximately 1,150 wells to unaffiliated third-parties during the first six months of 2016. (2) 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.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS 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. We do not believe the amendments will 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 it 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. We do not believe the amendments will have a material impact on our financial statements. 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. Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This 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 are in the process of evaluating the impact it will have on our financial statements.

Stock-Based Compensation

Stock-Based Compensation	6 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	STOCK-BASED COMPENSATION For restricted stock awards and stock options, we had: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In millions) Recognized stock compensation expense $ 2.0 $ 4.8 $ 5.3 $ 9.1 Capitalized stock compensation cost for our oil and natural gas properties 0.4 1.0 1.2 1.9 Tax benefit on stock based compensation 0.7 1.7 2.0 3.4 The remaining unrecognized compensation cost related to unvested awards at June 30, 2016 is approximately $10.9 million , of which $1.7 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 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options." We did not grant any SARs or stock options during either of the three or six month periods ending June 30, 2016 and 2015 . The following tables show the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated. Three Months Ended Three Months Ended June 30, 2016 June 30, 2015 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees — — — — Non-employee directors 90,000 — 25,848 — 90,000 — 25,848 — Estimated fair value (in millions): (1) Employees $ — $ — $ — $ — Non-employee directors 0.9 — 0.9 — $ 0.9 $ — $ 0.9 $ — Percentage of shares granted expected to be distributed: Employees N/A N/A N/A N/A Non-employee directors 100 % N/A 100 % N/A _______________________ (1) Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.) Six Months Ended Six Months Ended June 30, 2016 June 30, 2015 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees 486,578 152,373 576,361 148,081 Non-employee directors 90,000 — 25,848 — 576,578 152,373 602,209 148,081 Estimated fair value (in millions): (1) Employees $ 2.6 $ 0.8 $ 18.5 $ 5.1 Non-employee directors 0.9 — 0.9 — $ 3.5 $ 0.8 $ 19.4 $ 5.1 Percentage of shares granted expected to be distributed: Employees 94 % 70 % 94 % 3 % Non-employee directors 100 % N/A 100 % N/A _______________________ (1) Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.) The time vested restricted stock awards granted during the first six months of 2016 and 2015 are being recognized over a three year vesting period. During the first quarter of 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 performance measurement each year and will range from 0% to 200% . The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2016 awards for the first six months of 2016 was $0.7 million .

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 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 and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of June 30, 2016 , our derivative transactions comprised the following 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 transactions. We do not engage in derivative transactions for speculative purposes. For our economic hedges any changes in fair value occurring before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. At June 30, 2016 , we had the following derivatives outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Jul’16 – Dec’16 Natural gas – swap 45,000 MMBtu/day $2.596 IF – NYMEX (HH) Jan’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 20,000 MMBtu/day $(0.215) IF – NYMEX (HH) Jan’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH) Jul’16 – Dec'16 Natural gas – collar 42,000 MMBtu/day $2.40 - $2.88 IF – NYMEX (HH) Jan’17 – Oct'17 Natural gas – collar 10,000 MMBtu/day $2.75 - $2.95 IF – NYMEX (HH) Jul’16 – Dec'16 Natural gas – three-way collar 13,500 MMBtu/day $2.70 - $2.20 - $3.26 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) Jul’16 – Sep'16 Crude oil – swap 1,000 Bbl/day $48.45 WTI – NYMEX Jul’16 – Sep'16 Crude oil – collar 2,450 Bbl/day $44.44 - $52.46 WTI – NYMEX Oct’16 – Dec'16 Crude oil – collar 1,450 Bbl/day $47.50 - $56.40 WTI – NYMEX Jul’16 – Dec'16 Crude oil – three-way collar 700 Bbl/day $46.50 - $35.00 - $57.00 WTI – NYMEX Jul’16 – Dec'16 Crude oil – three-way collar (1) 700 Bbl/day $47.50 - $35.00 - $63.50 WTI – NYMEX Jan’17 – Dec'17 Crude oil – three-way collar 750 Bbl/day $50.00 - $37.50 - $63.90 WTI – NYMEX _______________________ (1) We pay our counterparty a premium, which can be and is being deferred until settlement. After June 30, 2016, we entered into the following derivatives: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Jan’17 – Oct'17 Natural gas – collar 10,000 MMBtu/day $3.00 - $3.24 IF – NYMEX (HH) The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets: Derivative Assets Fair Value Balance Sheet Location June 30, December 31, (In thousands) Commodity derivatives: Current Current derivative asset $ — $ 10,186 Long-term Non-current derivative asset — 968 Total derivative assets $ — $ 11,154 Derivative Liabilities Fair Value Balance Sheet Location June 30, December 31, (In thousands) Commodity derivatives: Current Current derivative liability $ 9,646 $ — Long-term Non-current derivative liability 3,420 285 Total derivative liabilities $ 13,066 $ 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 Unaudited Condensed Consolidated Balance Sheets. Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30 : Derivatives Instruments Location of Loss Recognized in Income on Derivative Amount of Loss Recognized in Income on Derivative 2016 2015 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (22,672 ) $ (1,919 ) Total $ (22,672 ) $ (1,919 ) _______________________ (1) Amounts settled during the 2016 and 2015 periods include gains of $5.1 million and $10.1 million , respectively. Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30 : Derivatives Instruments Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative 2016 2015 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (11,743 ) $ 4,667 Total $ (11,743 ) $ 4,667 _______________________ (1) Amounts settled during the 2016 and 2015 periods include gains of $12.2 million and $21.1 million , respectively.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 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 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: June 30, 2016 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 435 $ 515 $ (950 ) $ — Liabilities (8,740 ) (5,276 ) 950 (13,066 ) $ (8,305 ) $ (4,761 ) $ — $ (13,066 ) December 31, 2015 Level 2 Level 3 Effect of Netting Net Amounts Presented (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 June 30, 2016 . The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. 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 and three-way 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 Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning of period $ 9,983 $ 857 $ 9,094 $ 3,355 Total gains or losses (realized and unrealized): Included in earnings (1) (12,322 ) 111 (6,334 ) 888 Settlements (2,422 ) (761 ) (7,521 ) (4,036 ) End of period $ (4,761 ) $ 207 $ (4,761 ) $ 207 Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period $ (14,744 ) $ (650 ) $ (13,855 ) $ (3,148 ) _______________________ (1) Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives. The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2016 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil collars $ (151 ) Discounted cash flow Forward commodity price curve $0.07 - $5.31 Oil three-way collars $ 301 Discounted cash flow Forward commodity price curve $0.00 - $6.35 Natural gas collar $ (3,253 ) Discounted cash flow Forward commodity price curve $0.00 - $0.90 Natural gas three-way collars $ (1,658 ) Discounted cash flow Forward commodity price curve $0.00 - $0.51 _______________________ (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 paid or received within the settlement period. Based on our valuation at June 30, 2016 , we determined that risk of non-performance by 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 June 30, 2016 , the carrying values on the Unaudited Condensed 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 approximates its fair value and at June 30, 2016 and December 31, 2015 was $236.0 million and $281.0 million , respectively. 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 Unaudited Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015 were $639.1 million and $638.0 million , respectively. We estimate the fair value of these Notes using quoted marked prices at June 30, 2016 and December 31, 2015 were $505.4 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.

Industry Segment Information

Industry Segment Information	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Industry Segment Information	INDUSTRY SEGMENT INFORMATION We have three main business segments offering different products and services within the energy industry: • Oil and natural gas, • Contract drilling, and • Mid-stream Our 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. We have no oil and natural gas production outside the United States. The following table provides certain information about the operations of each of our segments: Three Months Ended June 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 69,190 $ — $ — $ — $ — $ 69,190 Contract drilling — 24,257 — — — 24,257 Gas gathering and processing — — 56,533 — (11,675 ) 44,858 Total revenues 69,190 24,257 56,533 — (11,675 ) 138,305 Expenses: Oil and natural gas: Operating costs 35,555 — — — (2,224 ) 33,331 Depreciation, depletion, and amortization 30,411 — — — — 30,411 Impairment of oil and natural gas properties 74,291 — — — — 74,291 Contract drilling: Operating costs — 19,254 — — — 19,254 Depreciation — 10,918 — — — 10,918 Gas gathering and processing: Operating costs — — 41,832 — (9,451 ) 32,381 Depreciation and amortization — — 11,515 — — 11,515 Total expenses 140,257 30,172 53,347 — (11,675 ) 212,101 Total operating income (loss) (1) (71,067 ) (5,915 ) 3,186 — — (73,796 ) General and administrative expense — — — (8,382 ) — (8,382 ) Gain (loss) on disposition of assets (324 ) 815 — (14 ) — 477 Loss on derivatives — — — (22,672 ) — (22,672 ) Interest expense, net — — — (10,606 ) — (10,606 ) Other — — — 1 — 1 Income (loss) before income taxes $ (71,391 ) $ (5,100 ) $ 3,186 $ (41,673 ) $ — $ (114,978 ) _______________________ (1) 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. Three Months Ended June 30, 2015 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 107,256 $ — $ — $ — $ — $ 107,256 Contract drilling — 60,813 — — (5,798 ) 55,015 Gas gathering and processing — — 69,163 — (16,987 ) 52,176 Total revenues 107,256 60,813 69,163 — (22,785 ) 214,447 Expenses: Oil and natural gas: Operating costs 47,179 — — — (1,207 ) 45,972 Depreciation, depletion, and amortization 68,101 — — — — 68,101 Impairment of oil and natural gas properties 410,536 — — — — 410,536 Contract drilling: Operating costs — 41,746 — — (5,261 ) 36,485 Depreciation — 13,265 — — — 13,265 Impairment of contract drilling properties — 8,314 — — — 8,314 Gas gathering and processing: Operating costs — — 56,372 — (15,780 ) 40,592 Depreciation and amortization — — 10,848 — — 10,848 Total expenses 525,816 63,325 67,220 — (22,248 ) 634,113 Total operating income (loss) (1) (418,560 ) (2,512 ) 1,943 — (537 ) (419,666 ) General and administrative expense — — — (9,624 ) — (9,624 ) Gain (loss) on disposition of assets — (50 ) 465 — — 415 Loss on derivatives — — — (1,919 ) — (1,919 ) Interest expense, net — — — (7,956 ) — (7,956 ) Other — — — 24 — 24 Income (loss) before income taxes $ (418,560 ) $ (2,562 ) $ 2,408 $ (19,475 ) $ (537 ) $ (438,726 ) _______________________ (1) 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. Six Months Ended June 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 127,464 $ — $ — $ — $ — $ 127,464 Contract drilling — 62,967 — — — 62,967 Gas gathering and processing — — 105,578 — (21,520 ) 84,058 Total revenues 127,464 62,967 105,578 — (21,520 ) 274,489 Expenses: Oil and natural gas: Operating costs 70,361 — — — (3,684 ) 66,677 Depreciation, depletion, and amortization 62,243 — — — — 62,243 Impairment of oil and natural gas properties 112,120 — — — — 112,120 Contract drilling: Operating costs — 47,352 — — — 47,352 Depreciation — 23,113 — — — 23,113 Gas gathering and processing: Operating costs — — 81,283 — (17,836 ) 63,447 Depreciation and amortization — — 22,974 — — 22,974 Total expenses 244,724 70,465 104,257 — (21,520 ) 397,926 Total operating income (loss) (1) (117,260 ) (7,498 ) 1,321 — — (123,437 ) General and administrative expense — — — (17,097 ) — (17,097 ) Gain (loss) on disposition of assets (324 ) 1,316 (302 ) (21 ) — 669 Loss on derivatives — — — (11,743 ) — (11,743 ) Interest expense, net — — — (20,223 ) — (20,223 ) Other — — — (14 ) — (14 ) Income (loss) before income taxes $ (117,584 ) $ (6,182 ) $ 1,019 $ (49,098 ) $ — $ (171,845 ) _______________________ (1) 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. Six Months Ended June 30, 2015 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 213,325 $ — $ — $ — $ — $ 213,325 Contract drilling — 165,751 — — (15,659 ) 150,092 Gas gathering and processing — — 142,967 — (36,838 ) 106,129 Total revenues 213,325 165,751 142,967 — (52,497 ) 469,546 Expenses: Oil and natural gas: Operating costs 93,560 — — — (2,377 ) 91,183 Depreciation, depletion, and amortization 145,219 — — — — 145,219 Impairment of oil and natural gas properties 811,129 — — — — 811,129 Contract drilling: Operating costs — 100,443 — — (12,212 ) 88,231 Depreciation — 28,278 — — — 28,278 Impairment of contract drilling properties — 8,314 — — — 8,314 Gas gathering and processing: Operating costs — — 119,228 — (34,461 ) 84,767 Depreciation and amortization — — 21,542 — — 21,542 Total expenses 1,049,908 137,035 140,770 — (49,050 ) 1,278,663 Total operating income (loss) (1) (836,583 ) 28,716 2,197 — (3,447 ) (809,117 ) General and administrative expense — — — (18,994 ) — (18,994 ) Gain on disposition of assets — 495 465 — — 960 Gain on derivatives — — — 4,667 — 4,667 Interest expense, net — — — (15,196 ) — (15,196 ) Other — — — 22 — 22 Income (loss) before income taxes $ (836,583 ) $ 29,211 $ 2,662 $ (29,501 ) $ (3,447 ) $ (837,658 ) _______________________ (1) 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.

Loss Per Share (Tables)

Loss Per Share (Tables)	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Schedule Of Loss Per Share	Information related to the calculation of loss per share follows: Loss (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the three months ended June 30, 2016 Basic loss per common share $ (72,136 ) 50,074 $ (1.44 ) Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) — — — Diluted loss per common share $ (72,136 ) 50,074 $ (1.44 ) For the three months ended June 30, 2015 Basic loss per common share $ (274,389 ) 49,148 $ (5.58 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (274,389 ) 49,148 $ (5.58 ) Loss (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the six months ended June 30, 2016 Basic loss per common share $ (113,285 ) 49,977 $ (2.27 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (113,285 ) 49,977 $ (2.27 ) For the six months ended June 30, 2015 Basic loss per common share $ (522,743 ) 49,063 $ (10.66 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (522,743 ) 49,063 $ (10.66 )
Schedule Of Antidilutive Securities Excluded From Computation Of Loss Per Share	The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock: Three Months Ended June 30, 2016 2015 Stock options and SARs 240,270 259,085 Average exercise price $ 49.29 $ 50.50 The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock: Six Months Ended June 30, 2016 2015 Stock options and SARs 240,270 261,270 Average exercise price $ 49.29 $ 50.34

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	Accrued liabilities consisted of the following: June 30, December 31, (In thousands) Lease operating expenses $ 19,157 $ 17,220 Taxes 8,722 3,767 Employee costs 7,007 12,641 Interest payable 6,213 6,321 Third-party credits 2,954 3,326 Derivative settlements 278 — Other 2,037 3,643 Total accrued liabilities $ 46,368 $ 46,918

Long-Term Debt And Other Long20

Long-Term Debt And Other Long-Term Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Our long-term debt consisted of the following as of the dates indicated: June 30, December 31, (In thousands) Credit agreement with an average interest rate of 3.9% and 2.6% at June 30, 2016 and December 31, 2015, respectively $ 236,000 $ 281,000 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount 886,000 931,000 Less: unamortized discount (3,076 ) (3,338 ) Less: debt issuance costs, net (7,873 ) (8,667 ) Total long-term debt $ 875,051 $ 918,995
Other Long-Term Liabilities	Other long-term liabilities consisted of the following: June 30, December 31, (In thousands) Asset retirement obligation (ARO) liability $ 70,926 $ 98,297 Capital lease obligations 20,710 22,466 Workers’ compensation 15,258 16,551 Separation benefit plans 6,386 9,886 Deferred compensation plan 4,430 4,244 Gas balancing liability 3,805 5,047 Other 410 410 121,925 156,901 Less current portion 17,999 16,560 Total other long-term liabilities $ 103,926 $ 140,341
Capital leases	Future payments required under the capital leases at June 30, 2016: Amount Ending June 30, (In thousands) 2017 $ 6,168 2018 6,168 2019 6,168 2020 6,168 2021 and thereafter 6,853 Total future payments 31,525 Less payments related to: Maintenance 8,552 Interest 2,263 Present value of future minimum payments $ 20,710

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Asset Retirement Obligations	The following table shows certain information about our AROs for the periods indicated: Six Months Ended June 30, 2016 2015 (In thousands) ARO liability, January 1: $ 98,297 $ 100,567 Accretion of discount 1,513 1,757 Liability incurred 212 5,986 Liability settled (605 ) (1,566 ) Liability sold (1) (10,308 ) (246 ) Revision of estimates (2) (18,183 ) (10,130 ) ARO liability, June 30: 70,926 96,368 Less current portion 3,523 3,277 Total long-term ARO $ 67,403 $ 93,091 _______________________ (1) We sold approximately 1,150 wells to unaffiliated third-parties during the first six months of 2016. (2) 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.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Restricted Stock Awards and Stock Options	For restricted stock awards and stock options, we had: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In millions) Recognized stock compensation expense $ 2.0 $ 4.8 $ 5.3 $ 9.1 Capitalized stock compensation cost for our oil and natural gas properties 0.4 1.0 1.2 1.9 Tax benefit on stock based compensation 0.7 1.7 2.0 3.4
Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods	The following tables show the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated. Three Months Ended Three Months Ended June 30, 2016 June 30, 2015 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees — — — — Non-employee directors 90,000 — 25,848 — 90,000 — 25,848 — Estimated fair value (in millions): (1) Employees $ — $ — $ — $ — Non-employee directors 0.9 — 0.9 — $ 0.9 $ — $ 0.9 $ — Percentage of shares granted expected to be distributed: Employees N/A N/A N/A N/A Non-employee directors 100 % N/A 100 % N/A _______________________ (1) Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.) Six Months Ended Six Months Ended June 30, 2016 June 30, 2015 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees 486,578 152,373 576,361 148,081 Non-employee directors 90,000 — 25,848 — 576,578 152,373 602,209 148,081 Estimated fair value (in millions): (1) Employees $ 2.6 $ 0.8 $ 18.5 $ 5.1 Non-employee directors 0.9 — 0.9 — $ 3.5 $ 0.8 $ 19.4 $ 5.1 Percentage of shares granted expected to be distributed: Employees 94 % 70 % 94 % 3 % Non-employee directors 100 % N/A 100 % N/A _______________________ (1) Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives outstanding	At June 30, 2016 , we had the following derivatives outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Jul’16 – Dec’16 Natural gas – swap 45,000 MMBtu/day $2.596 IF – NYMEX (HH) Jan’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 20,000 MMBtu/day $(0.215) IF – NYMEX (HH) Jan’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH) Jul’16 – Dec'16 Natural gas – collar 42,000 MMBtu/day $2.40 - $2.88 IF – NYMEX (HH) Jan’17 – Oct'17 Natural gas – collar 10,000 MMBtu/day $2.75 - $2.95 IF – NYMEX (HH) Jul’16 – Dec'16 Natural gas – three-way collar 13,500 MMBtu/day $2.70 - $2.20 - $3.26 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) Jul’16 – Sep'16 Crude oil – swap 1,000 Bbl/day $48.45 WTI – NYMEX Jul’16 – Sep'16 Crude oil – collar 2,450 Bbl/day $44.44 - $52.46 WTI – NYMEX Oct’16 – Dec'16 Crude oil – collar 1,450 Bbl/day $47.50 - $56.40 WTI – NYMEX Jul’16 – Dec'16 Crude oil – three-way collar 700 Bbl/day $46.50 - $35.00 - $57.00 WTI – NYMEX Jul’16 – Dec'16 Crude oil – three-way collar (1) 700 Bbl/day $47.50 - $35.00 - $63.50 WTI – NYMEX Jan’17 – Dec'17 Crude oil – three-way collar 750 Bbl/day $50.00 - $37.50 - $63.90 WTI – NYMEX _______________________ (1) We pay our counterparty a premium, which can be and is being deferred until settlement.
Subsequent derivatives outstanding	After June 30, 2016, we entered into the following derivatives: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Jan’17 – Oct'17 Natural gas – collar 10,000 MMBtu/day $3.00 - $3.24 IF – NYMEX (HH)
Fair Value Of Derivative Instruments And Locations In Balance Sheets	The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets: Derivative Assets Fair Value Balance Sheet Location June 30, December 31, (In thousands) Commodity derivatives: Current Current derivative asset $ — $ 10,186 Long-term Non-current derivative asset — 968 Total derivative assets $ — $ 11,154 Derivative Liabilities Fair Value Balance Sheet Location June 30, December 31, (In thousands) Commodity derivatives: Current Current derivative liability $ 9,646 $ — Long-term Non-current derivative liability 3,420 285 Total derivative liabilities $ 13,066 $ 285
Effect Of Derivative Instruments Recognized In Statements Of Operations, Derivative Instruments	Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30 : Derivatives Instruments Location of Loss Recognized in Income on Derivative Amount of Loss Recognized in Income on Derivative 2016 2015 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (22,672 ) $ (1,919 ) Total $ (22,672 ) $ (1,919 ) _______________________ (1) Amounts settled during the 2016 and 2015 periods include gains of $5.1 million and $10.1 million , respectively. Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30 : Derivatives Instruments Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative 2016 2015 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (11,743 ) $ 4,667 Total $ (11,743 ) $ 4,667 _______________________ (1) Amounts settled during the 2016 and 2015 periods include gains of $12.2 million and $21.1 million , respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Recurring Fair Value Measurements	The following tables set forth our recurring fair value measurements: June 30, 2016 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 435 $ 515 $ (950 ) $ — Liabilities (8,740 ) (5,276 ) 950 (13,066 ) $ (8,305 ) $ (4,761 ) $ — $ (13,066 ) December 31, 2015 Level 2 Level 3 Effect of Netting Net Amounts Presented (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	The following tables are reconciliations of our level 3 fair value measurements: Net Derivatives Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning of period $ 9,983 $ 857 $ 9,094 $ 3,355 Total gains or losses (realized and unrealized): Included in earnings (1) (12,322 ) 111 (6,334 ) 888 Settlements (2,422 ) (761 ) (7,521 ) (4,036 ) End of period $ (4,761 ) $ 207 $ (4,761 ) $ 207 Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period $ (14,744 ) $ (650 ) $ (13,855 ) $ (3,148 ) _______________________ (1) Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.
Schedule Of Quantitative Information About Unobservable Inputs	The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2016 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil collars $ (151 ) Discounted cash flow Forward commodity price curve $0.07 - $5.31 Oil three-way collars $ 301 Discounted cash flow Forward commodity price curve $0.00 - $6.35 Natural gas collar $ (3,253 ) Discounted cash flow Forward commodity price curve $0.00 - $0.90 Natural gas three-way collars $ (1,658 ) Discounted cash flow Forward commodity price curve $0.00 - $0.51 _______________________ (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 paid or received within the settlement period.

Industry Segment Information (T

Industry Segment Information (Tables)	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Industry segment information	The following table provides certain information about the operations of each of our segments: Three Months Ended June 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 69,190 $ — $ — $ — $ — $ 69,190 Contract drilling — 24,257 — — — 24,257 Gas gathering and processing — — 56,533 — (11,675 ) 44,858 Total revenues 69,190 24,257 56,533 — (11,675 ) 138,305 Expenses: Oil and natural gas: Operating costs 35,555 — — — (2,224 ) 33,331 Depreciation, depletion, and amortization 30,411 — — — — 30,411 Impairment of oil and natural gas properties 74,291 — — — — 74,291 Contract drilling: Operating costs — 19,254 — — — 19,254 Depreciation — 10,918 — — — 10,918 Gas gathering and processing: Operating costs — — 41,832 — (9,451 ) 32,381 Depreciation and amortization — — 11,515 — — 11,515 Total expenses 140,257 30,172 53,347 — (11,675 ) 212,101 Total operating income (loss) (1) (71,067 ) (5,915 ) 3,186 — — (73,796 ) General and administrative expense — — — (8,382 ) — (8,382 ) Gain (loss) on disposition of assets (324 ) 815 — (14 ) — 477 Loss on derivatives — — — (22,672 ) — (22,672 ) Interest expense, net — — — (10,606 ) — (10,606 ) Other — — — 1 — 1 Income (loss) before income taxes $ (71,391 ) $ (5,100 ) $ 3,186 $ (41,673 ) $ — $ (114,978 ) _______________________ (1) 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. Three Months Ended June 30, 2015 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 107,256 $ — $ — $ — $ — $ 107,256 Contract drilling — 60,813 — — (5,798 ) 55,015 Gas gathering and processing — — 69,163 — (16,987 ) 52,176 Total revenues 107,256 60,813 69,163 — (22,785 ) 214,447 Expenses: Oil and natural gas: Operating costs 47,179 — — — (1,207 ) 45,972 Depreciation, depletion, and amortization 68,101 — — — — 68,101 Impairment of oil and natural gas properties 410,536 — — — — 410,536 Contract drilling: Operating costs — 41,746 — — (5,261 ) 36,485 Depreciation — 13,265 — — — 13,265 Impairment of contract drilling properties — 8,314 — — — 8,314 Gas gathering and processing: Operating costs — — 56,372 — (15,780 ) 40,592 Depreciation and amortization — — 10,848 — — 10,848 Total expenses 525,816 63,325 67,220 — (22,248 ) 634,113 Total operating income (loss) (1) (418,560 ) (2,512 ) 1,943 — (537 ) (419,666 ) General and administrative expense — — — (9,624 ) — (9,624 ) Gain (loss) on disposition of assets — (50 ) 465 — — 415 Loss on derivatives — — — (1,919 ) — (1,919 ) Interest expense, net — — — (7,956 ) — (7,956 ) Other — — — 24 — 24 Income (loss) before income taxes $ (418,560 ) $ (2,562 ) $ 2,408 $ (19,475 ) $ (537 ) $ (438,726 ) _______________________ (1) 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. Six Months Ended June 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 127,464 $ — $ — $ — $ — $ 127,464 Contract drilling — 62,967 — — — 62,967 Gas gathering and processing — — 105,578 — (21,520 ) 84,058 Total revenues 127,464 62,967 105,578 — (21,520 ) 274,489 Expenses: Oil and natural gas: Operating costs 70,361 — — — (3,684 ) 66,677 Depreciation, depletion, and amortization 62,243 — — — — 62,243 Impairment of oil and natural gas properties 112,120 — — — — 112,120 Contract drilling: Operating costs — 47,352 — — — 47,352 Depreciation — 23,113 — — — 23,113 Gas gathering and processing: Operating costs — — 81,283 — (17,836 ) 63,447 Depreciation and amortization — — 22,974 — — 22,974 Total expenses 244,724 70,465 104,257 — (21,520 ) 397,926 Total operating income (loss) (1) (117,260 ) (7,498 ) 1,321 — — (123,437 ) General and administrative expense — — — (17,097 ) — (17,097 ) Gain (loss) on disposition of assets (324 ) 1,316 (302 ) (21 ) — 669 Loss on derivatives — — — (11,743 ) — (11,743 ) Interest expense, net — — — (20,223 ) — (20,223 ) Other — — — (14 ) — (14 ) Income (loss) before income taxes $ (117,584 ) $ (6,182 ) $ 1,019 $ (49,098 ) $ — $ (171,845 ) _______________________ (1) 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. Six Months Ended June 30, 2015 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 213,325 $ — $ — $ — $ — $ 213,325 Contract drilling — 165,751 — — (15,659 ) 150,092 Gas gathering and processing — — 142,967 — (36,838 ) 106,129 Total revenues 213,325 165,751 142,967 — (52,497 ) 469,546 Expenses: Oil and natural gas: Operating costs 93,560 — — — (2,377 ) 91,183 Depreciation, depletion, and amortization 145,219 — — — — 145,219 Impairment of oil and natural gas properties 811,129 — — — — 811,129 Contract drilling: Operating costs — 100,443 — — (12,212 ) 88,231 Depreciation — 28,278 — — — 28,278 Impairment of contract drilling properties — 8,314 — — — 8,314 Gas gathering and processing: Operating costs — — 119,228 — (34,461 ) 84,767 Depreciation and amortization — — 21,542 — — 21,542 Total expenses 1,049,908 137,035 140,770 — (49,050 ) 1,278,663 Total operating income (loss) (1) (836,583 ) 28,716 2,197 — (3,447 ) (809,117 ) General and administrative expense — — — (18,994 ) — (18,994 ) Gain on disposition of assets — 495 465 — — 960 Gain on derivatives — — — 4,667 — 4,667 Interest expense, net — — — (15,196 ) — (15,196 ) Other — — — 22 — 22 Income (loss) before income taxes $ (836,583 ) $ 29,211 $ 2,662 $ (29,501 ) $ (3,447 ) $ (837,658 ) _______________________ (1) 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.

Oil and Natural Gas (Narrative)

Oil and Natural Gas (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
Future discounted net cash flows discounted					10.00%
Impairment of oil and natural gas properties	$ 74,291	$ 37,800	$ 410,536	$ 400,600	$ 112,120	$ 811,129
Non-cash ceiling test write-down net of tax	$ 46,300	$ 23,500	$ 255,600	$ 249,400

Divestitures (Narrative) (Detai

Divestitures (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Property, Plant and Equipment Impairment or Disposal [Abstract]
Proceeds from non-core oil and natural gas asset sales, net of related expenses			$ 43,600	$ 87
Impairment of contract drilling equipment	$ 0	$ 8,314	$ 0	$ 8,314

Loss Per Share (Schedule Of Los

Loss Per Share (Schedule Of Loss Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Loss of basic loss per common share	$ (72,136)	$ (274,389)	$ (113,285)	$ (522,743)
Income of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0	0	0	0
Loss of diluted loss per common share	$ (72,136)	$ (274,389)	$ (113,285)	$ (522,743)
Weighted shares of basic loss per common share	50,074	49,148	49,977	49,063
Weighted shares of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0	0	0	0
Weighted shares of diluted loss per common share	50,074	49,148	49,977	49,063
Per-Share amount of basic loss per common share	$ (1.44)	$ (5.58)	$ (2.27)	$ (10.66)
Per-Share amount of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0	0	0	0
Per-Share amount of diluted loss per common share	$ (1.44)	$ (5.58)	$ (2.27)	$ (10.66)

Loss Per Share (Schedule Of Ant

Loss Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Loss Per Share) (Details) - Stock options and SARs - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	240,270	259,085	240,270	261,270
Average exercise price	$ 49.29	$ 50.50	$ 49.29	$ 50.34

Loss Per Share (Narrative) (Det

Loss Per Share (Narrative) (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Stock options, restricted stock, and SARs [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share due to net loss	417,000	307,000	332,000	206,000

Accrued Liabilities (Accrued Li

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accrued Liabilities, Current [Abstract]
Lease operating expenses	$ 19,157	$ 17,220
Taxes	8,722	3,767
Employee costs	7,007	12,641
Interest payable	6,213	6,321
Third-party credits	2,954	3,326
Derivative settlements	278	0
Other	2,037	3,643
Total accrued liabilities	$ 46,368	$ 46,918

Long-Term Debt And Other Long32

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Credit agreement with an average interest rate of 3.9% and 2.6% at June 30, 2016 and December 31, 2015, respectively	$ 236,000	$ 281,000
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	886,000	931,000
Less: unamortized discount	(3,076)	(3,338)
Less: debt issuance costs, net	(7,873)	(8,667)
Total long-term debt	$ 875,051	$ 918,995
Revolving credit facility interest rate	3.90%	2.60%
Interest percentage of senior subordinated notes	6.625%
Debt instrument maturity date	May 15, 2021
6.625% Senior Subordinated Notes Due 2021 [Member]
Debt Instrument [Line Items]
6.625% senior subordinated notes due 2021	$ 650,000

Long-Term Debt And Other Long33

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Asset retirement obligation (ARO) liability	$ 70,926	$ 98,297	$ 96,368	$ 100,567
Capital lease obligations	20,710	22,466
Workers' compensation	15,258	16,551
Separation benefit plans	6,386	9,886
Deferred compensation plan	4,430	4,244
Gas balancing liability	3,805	5,047
Other	410	410
Other liabilities	121,925	156,901
Less current portion	17,999	16,560
Total other long-term liabilities	$ 103,926	$ 140,341

Long-Term Debt And Other Long34

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt And Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Ending June 30,
2,017	$ 6,168
2,018	6,168
2,019	6,168
2,020	6,168
2021 and thereafter	6,853
Total future payments	31,525
Less payments related to:
Maintenance	8,552
Interest	2,263
Present value of future minimum payments	$ 20,710	$ 22,466

Long-Term Debt And Other Long35

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Credit facility maturity date	April 10, 2020
Credit facility maximum credit amount	$ 875,000
Commitment fee percentage under credit facility	0.50%
Origination, agency and syndication and other related fees with the credit agreement	$ 1,000
Present worth discounted	10.00%
Payable assessment term for LIBOR	90 days
LIBOR interest rate plus one percent	LIBOR plus 1.00%
Line of credit facility, amount outstanding	$ 236,000	$ 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
Original debt issuance fees	$ 14,700
Senior notes repurchase price in percentage	101.00%
Estimated principal payments in year 1	$ 18,000
Estimated principal payments in year 2	44,300
Estimated principal payments in year 3	10,200
Estimated principal payments in year 4	244,100
Estimated principal payments in year 5	$ 658,700
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,600
Capital Lease Obligations, Noncurrent	$ 17,100
Discount rate capital leases	4.00%
Maintenance	$ 8,552
Interest	2,263
Capital leases, future minimum payments, average annual payment	$ 4,000
Capital lease fair market value percentage for purchase	10.00%
Minimum [Member]
Debt Instrument [Line Items]
LIBOR plus interest rate	2.00%
Maximum [Member]
Debt Instrument [Line Items]
LIBOR plus interest rate	3.00%
Maximum payment of dividends as a percentage of consolidated net income, prohibited under credit agreement	30.00%
6.625% Senior Subordinated Notes Due 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 650,000
Line Of Credit Facility Lender Determined Amount [Member]
Debt Instrument [Line Items]
Credit facility current credit amount	475,000
Line Of Credit Facility Commitment Amount [Member]
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%
Present worth discounted	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 10, 2020 [Member]
Debt Instrument [Line Items]
Leverage ratio of long-term debt	4 to 1

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) $ in Thousands		6 Months Ended
		Jun. 30, 2016USD ($)wells	Jun. 30, 2015USD ($)
Asset Retirement Obligation Disclosure [Abstract]
ARO liability, January 1:		$ 98,297	$ 100,567
Accretion of discount		1,513	1,757
Liability incurred		212	5,986
Liability settled		(605)	(1,566)
Liability sold	[1]	(10,308)	(246)
Revision of estimates	[2]	(18,183)	(10,130)
ARO liability, June 30:		70,926	96,368
Less current portion		3,523	3,277
Total long-term ARO		$ 67,403	$ 93,091
Wells sold | wells		1,150
[1]	We sold approximately 1,150 wells to unaffiliated third-parties during the first six months of 2016.
[2]	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.

Stock-Based Compensation Stock-

Stock-Based Compensation Stock-Based Compensation (Schedule of Restricted Stock Awards and Stock Options) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Abstract]
Recognized stock compensation expense	$ 2	$ 4.8	$ 5.3	$ 9.1
Capitalized stock compensation cost for our oil and natural gas properties	0.4	1	1.2	1.9
Tax benefit on stock based compensation	$ 0.7	$ 1.7	$ 2	$ 3.4

Stock-Based Compensation (Sched

Stock-Based Compensation (Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods) (Details) - Restricted Stock [Member] - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Time Vested [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		90,000	25,848	576,578	602,209
Estimated fair value (in millions)	[1]	$ 0.9	$ 0.9	$ 3.5	$ 19.4
Time Vested [Member] | Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		0	0	486,578	576,361
Estimated fair value (in millions)	[1]	$ 0	$ 0	$ 2.6	$ 18.5
Percentage of shares granted expected to be distributed				94.00%	94.00%
Time Vested [Member] | Non-employee Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		90,000	25,848	90,000	25,848
Estimated fair value (in millions)	[1]	$ 0.9	$ 0.9	$ 0.9	$ 0.9
Percentage of shares granted expected to be distributed		100.00%	100.00%	100.00%	100.00%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		0	0	152,373	148,081
Estimated fair value (in millions)	[1]	$ 0	$ 0	$ 0.8	$ 5.1
Performance Shares [Member] | Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		0	0	152,373	148,081
Estimated fair value (in millions)	[1]	$ 0	$ 0	$ 0.8	$ 5.1
Percentage of shares granted expected to be distributed				70.00%	3.00%
Performance Shares [Member] | Non-employee Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		0	0	0	0
Estimated fair value (in millions)	[1]	$ 0	$ 0	$ 0	$ 0
[1]	Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

Stock-Based Compensation (Narra

Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 10.9		$ 10.9
Unrecognized compensation cost, expected to be capitalized	$ 1.7		$ 1.7
Weighted average years over which this cost will be recognized			8 months 23 days
Increase in stock compensation expense due to the restricted stock awards granted			$ 0.7
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	0	0	0	0
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized					4,500,000
Incentive Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized					2,000,000
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options granted	0	0	0	0
Stock Performance Measures [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			0.00%
Stock Performance Measures [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			200.00%
Cash flow to total assets performance [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			0.00%
Cash flow to total assets performance [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			200.00%
Time Vested [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Shares granted	90,000	25,848	576,578	602,209
Performance Shares [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	0	0	152,373	148,081
Performance Shares [Member] | Cash flow to total assets performance [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Cliff vest [Member] | Performance Shares [Member] | Stock Performance Measures [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years

Derivatives (Schedule of Deriva

Derivatives (Schedule of Derivatives Outstanding) (Details)	6 Months Ended
	Jun. 30, 2016$ / UnitMMBTUbbl
Swap [Member] | Jul'16 - Sep'16 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Weighted average price	48.45
Hedged volume (Bbl/day) | bbl	1,000
Swap [Member] | Jul'16 - Dec'16 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	2.596
Hedged volume (MMBtu/day) | MMBTU	45,000
Swap [Member] | Jan'17 - Dec'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	2.960
Hedged volume (MMBtu/day) | MMBTU	60,000
Swap [Member] | Jan'18 - Dec'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	3.025
Hedged volume (MMBtu/day) | MMBTU	10,000
Basis swap [Member] | Jan'17 - Dec'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	(0.215)
Hedged volume (MMBtu/day) | MMBTU	20,000
Basis swap [Member] | Jan'18 - Dec'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	(0.208)
Hedged volume (MMBtu/day) | MMBTU	10,000
Collar [Member] | Jul'16 - Sep'16 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	2,450
Cap Price	52.46
Floor Price	44.44
Collar [Member] | Jul'16 - Dec'16 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	42,000
Cap Price	2.88
Floor Price	2.40
Collar [Member] | Oct'16 - Dec'16 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	1,450
Cap Price	56.40
Floor Price	47.50
Collar [Member] | Jan'17 - Oct'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	10,000
Cap Price	2.95
Floor Price	2.75
Three-way collar [Member] | Jul'16 - Dec'16 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	700
Cap Price	57
Subfloor price	35
Floor Price	46.50
Three-way collar [Member] | Jul'16 - Dec'16 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	13,500
Cap Price	3.26
Subfloor price	2.20
Floor Price	2.70
Three-way collar [Member] | Jan'17 - Dec'17 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	750
Cap Price	63.90
Subfloor price	37.50
Floor Price	50
Three-way collar [Member] | Jan'17 - Dec'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	15,000
Cap Price	3.32
Subfloor price	2
Floor Price	2.50
Derivative premium [Member] | Three-way collar [Member] | Jul'16 - Dec'16 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	700	[1]
Cap Price	63.50	[1]
Subfloor price	35	[1]
Floor Price	47.50	[1]
[1]	We pay our counterparty a premium, which can be and is being deferred until settlement.

Derivatives Derivatives (Schedu

Derivatives Derivatives (Schedule of Subsequent Derivatives Outstanding (Details) - Jan'17 - Oct'17 [Member] - Natural Gas [Member] - Collar [Member] - IF - NYMEX (HH) [Member]	1 Months Ended	6 Months Ended
	Aug. 04, 2016MMBTU$ / Unit	Jun. 30, 2016MMBTU$ / Unit
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU		10,000
Floor Price		2.75
Cap Price		2.95
Subsequent Event [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	10,000
Floor Price	3
Cap Price	3.24

Derivatives (Fair Value Of Deri

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative asset	$ 0	$ 10,186
Non-current derivative asset	0	968
Total derivatives assets	0	11,154
Current derivative liability	9,646	0
Non-current derivative liability	3,420	285
Total derivative liabilities	$ 13,066	$ 285

Derivatives (Effect Of Derivati

Derivatives (Effect Of Derivative Instruments Recognized In Statement Of Operations, Derivative Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	$ (22,672)		$ (1,919)		$ (11,743)		$ 4,667
Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	(22,672)		(1,919)		(11,743)		4,667
Amount of gain settled during the period	5,100		10,100		12,200		21,100
Gain (loss) on derivatives [Member] | Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	$ (22,672)	[1]	$ (1,919)	[1]	$ (11,743)	[2]	$ 4,667	[2]
[1]	Amounts settled during the 2016 and 2015 periods include gains of $5.1 million and $10.1 million, respectively.
[2]	Amounts settled during the 2016 and 2015 periods include gains of $12.2 million and $21.1 million, respectively.

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 0	$ 11,154
Derivative Liability	13,066	285
Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	11,154
Derivative Liability	13,066	285
Financial assets (liabilities)	(13,066)	10,869
Commodity Derivatives [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	435	2,794
Gross Liabilities	(8,740)	(1,019)
Financial assets (liabilities)	(8,305)	1,775
Commodity Derivatives [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	515	10,145
Gross Liabilities	(5,276)	(1,051)
Financial assets (liabilities)	(4,761)	9,094
Commodity Derivatives [Member] | Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Effect of netting on assets	(950)	(1,785)
Effect of netting on liabilities	950	1,785
Financial assets (liabilities)	$ 0	$ 0

Fair Value Measurements (Reconc

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) - Level 3 [Member] - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Beginning of period		$ 9,983	$ 857	$ 9,094	$ 3,355
Included in earnings	[1]	(12,322)	111	(6,334)	888
Settlements		(2,422)	(761)	(7,521)	(4,036)
End of period		(4,761)	207	(4,761)	207
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period		$ (14,744)	$ (650)	$ (13,855)	$ (3,148)
[1]	Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) - Level 3 [Member] $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)$ / Unit	[1]
Oil [Member] | Collar [Member]
Derivative fair value | $	$ (151)
Derivatives Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward commodity price curve
Oil [Member] | Collar [Member] | Minimum [Member]
Forward commodity price curve	0.07
Oil [Member] | Collar [Member] | Maximum [Member]
Forward commodity price curve	5.31
Oil [Member] | Three-way collar [Member]
Derivative fair value | $	$ 301
Derivatives Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward commodity price curve
Oil [Member] | Three-way collar [Member] | Minimum [Member]
Forward commodity price curve	0
Oil [Member] | Three-way collar [Member] | Maximum [Member]
Forward commodity price curve	6.35
Natural Gas [Member] | Collar [Member]
Derivative fair value | $	$ (3,253)
Derivatives Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward commodity price curve
Natural Gas [Member] | Collar [Member] | Minimum [Member]
Forward commodity price curve	0
Natural Gas [Member] | Collar [Member] | Maximum [Member]
Forward commodity price curve	0.90
Natural Gas [Member] | Three-way collar [Member]
Derivative fair value | $	$ (1,658)
Derivatives Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward commodity price curve
Natural Gas [Member] | Three-way collar [Member] | Minimum [Member]
Forward commodity price curve	0
Natural Gas [Member] | Three-way collar [Member] | Maximum [Member]
Forward commodity price curve	0.51
[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 paid or received within the settlement period.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral posted	$ 0
Line of credit facility, amount outstanding	236,000	$ 281,000
6.625% senior subordinated notes due 2021	639,100	638,000
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Estimated fair value of long-term debt	$ 505,400	$ 455,500

Industry Segment Information (I

Industry Segment Information (Industry Segment Information) (Details) - USD ($) $ in Thousands	3 Months Ended						6 Months Ended
	Jun. 30, 2016		Mar. 31, 2016	Jun. 30, 2015		Mar. 31, 2015	Jun. 30, 2016		Jun. 30, 2015
Revenues:
Oil and natural gas	$ 69,190			$ 107,256			$ 127,464		$ 213,325
Contract drilling	24,257			55,015			62,967		150,092
Gas gathering and processing	44,858			52,176			84,058		106,129
Total revenues	138,305			214,447			274,489		469,546
Oil and natural gas:
Operating costs	33,331			45,972			66,677		91,183
Depreciation, depletion, and amortization	30,411			68,101			62,243		145,219
Impairment of oil and natural gas properties	74,291		$ 37,800	410,536		$ 400,600	112,120		811,129
Contract drilling:
Operating costs	19,254			36,485			47,352		88,231
Depreciation	10,918			13,265			23,113		28,278
Impairment of contract drilling equipment	0			8,314			0		8,314
Gas gathering and processing:
Operating costs	32,381			40,592			63,447		84,767
Depreciation and amortization	11,515			10,848			22,974		21,542
Total expenses	212,101			634,113			397,926		1,278,663
Total operating income (loss)	(73,796)	[1]		(419,666)	[2]		(123,437)	[3]	(809,117)	[4]
General and administrative expense	(8,382)			(9,624)			(17,097)		(18,994)
Gain (loss) on disposition of assets	477			415			669		960
Gain (loss) on derivatives	(22,672)			(1,919)			(11,743)		4,667
Interest expense, net	(10,606)			(7,956)			(20,223)		(15,196)
Other	1			24			(14)		22
Income (loss) before income taxes	(114,978)			(438,726)			(171,845)		(837,658)
Oil and Natural Gas [Member]
Revenues:
Oil and natural gas	69,190			107,256			127,464		213,325
Contract drilling	0			0			0		0
Gas gathering and processing	0			0			0		0
Total revenues	69,190			107,256			127,464		213,325
Oil and natural gas:
Operating costs	35,555			47,179			70,361		93,560
Depreciation, depletion, and amortization	30,411			68,101			62,243		145,219
Impairment of oil and natural gas properties	74,291			410,536			112,120		811,129
Contract drilling:
Operating costs	0			0			0		0
Depreciation	0			0			0		0
Impairment of contract drilling equipment				0					0
Gas gathering and processing:
Operating costs	0			0			0		0
Depreciation and amortization	0			0			0		0
Total expenses	140,257			525,816			244,724		1,049,908
Total operating income (loss)	(71,067)	[1]		(418,560)	[2]		(117,260)	[3]	(836,583)	[4]
General and administrative expense	0			0			0		0
Gain (loss) on disposition of assets	(324)			0			(324)		0
Gain (loss) on derivatives	0			0			0		0
Interest expense, net	0			0			0		0
Other	0			0			0		0
Income (loss) before income taxes	(71,391)			(418,560)			(117,584)		(836,583)
Drilling [Member]
Revenues:
Oil and natural gas	0			0			0		0
Contract drilling	24,257			60,813			62,967		165,751
Gas gathering and processing	0			0			0		0
Total revenues	24,257			60,813			62,967		165,751
Oil and natural gas:
Operating costs	0			0			0		0
Depreciation, depletion, and amortization	0			0			0		0
Impairment of oil and natural gas properties	0			0			0		0
Contract drilling:
Operating costs	19,254			41,746			47,352		100,443
Depreciation	10,918			13,265			23,113		28,278
Impairment of contract drilling equipment				8,314					8,314
Gas gathering and processing:
Operating costs	0			0			0		0
Depreciation and amortization	0			0			0		0
Total expenses	30,172			63,325			70,465		137,035
Total operating income (loss)	(5,915)	[1]		(2,512)	[2]		(7,498)	[3]	28,716	[4]
General and administrative expense	0			0			0		0
Gain (loss) on disposition of assets	815			(50)			1,316		495
Gain (loss) on derivatives	0			0			0		0
Interest expense, net	0			0			0		0
Other	0			0			0		0
Income (loss) before income taxes	(5,100)			(2,562)			(6,182)		29,211
Mid-Stream [Member]
Revenues:
Oil and natural gas	0			0			0		0
Contract drilling	0			0			0		0
Gas gathering and processing	56,533			69,163			105,578		142,967
Total revenues	56,533			69,163			105,578		142,967
Oil and natural gas:
Operating costs	0			0			0		0
Depreciation, depletion, and amortization	0			0			0		0
Impairment of oil and natural gas properties	0			0			0		0
Contract drilling:
Operating costs	0			0			0		0
Depreciation	0			0			0		0
Impairment of contract drilling equipment				0					0
Gas gathering and processing:
Operating costs	41,832			56,372			81,283		119,228
Depreciation and amortization	11,515			10,848			22,974		21,542
Total expenses	53,347			67,220			104,257		140,770
Total operating income (loss)	3,186	[1]		1,943	[2]		1,321	[3]	2,197	[4]
General and administrative expense	0			0			0		0
Gain (loss) on disposition of assets	0			465			(302)		465
Gain (loss) on derivatives	0			0			0		0
Interest expense, net	0			0			0		0
Other	0			0			0		0
Income (loss) before income taxes	3,186			2,408			1,019		2,662
Other Segments [Member]
Revenues:
Oil and natural gas	0			0			0		0
Contract drilling	0			0			0		0
Gas gathering and processing	0			0			0		0
Total revenues	0			0			0		0
Oil and natural gas:
Operating costs	0			0			0		0
Depreciation, depletion, and amortization	0			0			0		0
Impairment of oil and natural gas properties	0			0			0		0
Contract drilling:
Operating costs	0			0			0		0
Depreciation	0			0			0		0
Impairment of contract drilling equipment				0					0
Gas gathering and processing:
Operating costs	0			0			0		0
Depreciation and amortization	0			0			0		0
Total expenses	0			0			0		0
Total operating income (loss)	0	[1]		0	[2]		0	[3]	0	[4]
General and administrative expense	(8,382)			(9,624)			(17,097)		(18,994)
Gain (loss) on disposition of assets	(14)			0			(21)		0
Gain (loss) on derivatives	(22,672)			(1,919)			(11,743)		4,667
Interest expense, net	(10,606)			(7,956)			(20,223)		(15,196)
Other	1			24			(14)		22
Income (loss) before income taxes	(41,673)			(19,475)			(49,098)		(29,501)
Intersubsegment Eliminations [Member]
Revenues:
Oil and natural gas	0			0			0		0
Contract drilling	0			(5,798)			0		(15,659)
Gas gathering and processing	(11,675)			(16,987)			(21,520)		(36,838)
Total revenues	(11,675)			(22,785)			(21,520)		(52,497)
Oil and natural gas:
Operating costs	(2,224)			(1,207)			(3,684)		(2,377)
Depreciation, depletion, and amortization	0			0			0		0
Impairment of oil and natural gas properties	0			0			0		0
Contract drilling:
Operating costs	0			(5,261)			0		(12,212)
Depreciation	0			0			0		0
Impairment of contract drilling equipment				0					0
Gas gathering and processing:
Operating costs	(9,451)			(15,780)			(17,836)		(34,461)
Depreciation and amortization	0			0			0		0
Total expenses	(11,675)			(22,248)			(21,520)		(49,050)
Total operating income (loss)	0	[1]		(537)	[2]		0	[3]	(3,447)	[4]
General and administrative expense	0			0			0		0
Gain (loss) on disposition of assets	0			0			0		0
Gain (loss) on derivatives	0			0			0		0
Interest expense, net	0			0			0		0
Other	0			0			0		0
Income (loss) before income taxes	$ 0			$ (537)			$ 0		$ (3,447)
[1]	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.
[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]	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.
[4]	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.