Unit (UNTC) 10-Q 2 Nov 17 2017 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 20, 2017
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	798,949
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		52,879,660

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 822,000	$ 893,000
Accounts receivable, net of allowance for doubtful accounts of $2,393 and $3,773 at September 30, 2017 and December 31, 2016, respectively	116,292,000	83,954,000
Materials and supplies	3,323,000	3,340,000
Current derivative asset (Note 10)	1,064,000	0
Current income tax receivable	114,000	99,000
Current deferred tax asset (Note 8)	0	25,211,000
Prepaid expenses and other	7,351,000	7,699,000
Total current assets	128,966,000	121,196,000
Oil and natural gas properties on the full cost method:
Proved properties	5,605,974,000	5,446,305,000
Unproved properties not being amortized	337,064,000	314,867,000
Drilling equipment	1,593,835,000	1,565,268,000
Gas gathering and processing equipment	715,864,000	705,859,000
Saltwater disposal systems	62,387,000	60,638,000
Corporate land and building	59,079,000	59,066,000
Transportation equipment	29,731,000	32,842,000
Other	53,308,000	48,590,000
Property, plant, and equipment, gross	8,457,242,000	8,233,435,000
Less accumulated depreciation, depletion, amortization, and impairment	6,099,229,000	5,952,330,000
Net property and equipment	2,358,013,000	2,281,105,000
Goodwill	62,808,000	62,808,000
Non-current derivative asset (Note 10)	0	377,000
Other assets	16,085,000	13,817,000
Total assets	2,565,872,000	2,479,303,000
Current liabilities:
Accounts payable	116,152,000	88,793,000
Accrued liabilities (Note 5)	60,132,000	39,651,000
Current derivative liability (Note 10)	636,000	21,564,000
Current portion of other long-term liabilities (Note 6)	14,227,000	14,907,000
Total current liabilities	191,147,000	164,915,000
Long-term debt less debt issuance costs (Note 6)	803,833,000	800,917,000
Non-current derivative liability (Note 10)	282,000	415,000
Other long-term liabilities (Note 6)	105,468,000	103,064,000
Deferred income taxes (Note 8)	213,237,000	215,922,000
Commitments and contingencies (Note 12)	0	0
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, 52,879,660 and 51,494,318 shares issued as of September 30, 2017 and December 31, 2016, respectively	10,277,000	10,016,000
Capital in excess of par value	531,328,000	502,500,000
Accumulated other comprehensive income (Note 13)	53,000	0
Retained earnings	710,247,000	681,554,000
Total shareholders' equity	1,251,905,000	1,194,070,000
Total liabilities and shareholders' equity	$ 2,565,872,000	$ 2,479,303,000

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 2,393	$ 3,773
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	52,879,660	51,494,318

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Oil and natural gas	$ 85,470	$ 78,854	$ 256,241	$ 206,318
Contract drilling	51,619	25,819	128,059	88,786
Gas gathering and processing	51,399	48,735	150,493	132,793
Total revenues	188,488	153,408	534,793	427,897
Operating costs:
Oil and natural gas	33,911	26,014	95,873	92,691
Contract drilling	34,747	19,137	91,213	66,489
Gas gathering and processing	38,116	35,738	111,862	99,185
Total operating costs	106,774	80,889	298,948	258,365
Depreciation, depletion, and amortization	54,533	49,969	151,545	158,437
Impairments (Note 2)	0	49,443	0	161,563
General and administrative	9,235	8,852	26,902	25,811
Gain on disposition of assets	(81)	(154)	(1,153)	(823)
Total operating expenses	170,461	188,999	476,242	603,353
Income (loss) from operations	18,027	(35,591)	58,551	(175,456)
Other income (expense):
Interest, net	(9,944)	(10,002)	(28,807)	(30,225)
Gain (loss) on derivatives	(2,614)	6,969	21,019	(4,774)
Other, net	5	3	14	(11)
Total other income (expense)	(12,553)	(3,030)	(7,774)	(35,010)
Income (loss) before income taxes	5,474	(38,621)	50,777	(210,466)
Income tax expense (benefit):
Deferred	1,769	(14,599)	22,084	(73,159)
Total income taxes	1,769	(14,599)	22,084	(73,159)
Net income (loss)	$ 3,705	$ (24,022)	$ 28,693	$ (137,307)
Net income (loss) per common share:
Basic	$ 0.07	$ (0.48)	$ 0.56	$ (2.75)
Diluted	$ 0.07	$ (0.48)	$ 0.56	$ (2.75)

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 3,705	$ (24,022)	$ 28,693	$ (137,307)
Other comprehensive income, net of taxes:
Unrealized appreciation on securities, net of tax of $20, $0, $32, and $0	33	0	53	0
Comprehensive income (loss)	$ 3,738	$ (24,022)	$ 28,746	$ (137,307)

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Unrealized appreciation on securities, tax	$ 20	$ 0	$ 32	$ 0

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
OPERATING ACTIVITIES:
Net income (loss)	$ 28,693	$ (137,307)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	151,545	158,437
Impairments (Note 2)	0	161,563
Amortization of debt issuance costs and debt discount (Note 6)	1,616	1,586
(Gain) loss on derivatives	(21,019)	4,774
Cash (payments) receipts on derivatives settled, net	(729)	11,735
Deferred tax expense (benefit)	22,084	(73,159)
Gain on disposition of assets	(1,153)	(1,100)
Stock compensation plans	12,478	10,664
Other, net	1,397	(3,055)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(36,381)	759
Accounts payable	4,873	26,940
Material and supplies	17	231
Accrued liabilities	20,280	14,073
Income taxes	(15)	20,636
Other, net	1,106	985
Net cash provided by operating activities	184,792	197,762
INVESTING ACTIVITIES:
Capital expenditures	(167,392)	(154,558)
Producing properties and other acquisitions (Note 3)	(55,429)	0
Proceeds from disposition of assets	20,137	46,880
Other	(1,500)	169
Net cash used in investing activities	(204,184)	(107,509)
FINANCING ACTIVITIES:
Borrowings under credit agreement	251,401	195,700
Payments under credit agreement	(250,100)	(261,700)
Payments on capitalized leases	(2,967)	(2,756)
Proceeds from common stock issued, net of issue costs (Note 13)	18,623	0
Tax benefit from stock compensation	0	(376)
Book overdrafts	2,364	(21,043)
Net cash provided by (used in) financing activities	19,321	(90,175)
Net increase (decrease) in cash and cash equivalents	(71)	78
Cash and cash equivalents, beginning of period	893	835
Cash and cash equivalents, end of period	822	913
Cash paid during the year for:
Interest paid (net of capitalized)	14,601	16,650
Income taxes	0	0
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(20,122)	36,934
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations	$ (3,203)	$ 29,423

Basis of Preparation and Presen

Basis of Preparation and Presentation	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Preparation and Presentation	BASIS OF PREPARATION AND PRESENTATION The 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 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 28, 2017, for the year ended December 31, 2016 . In the opinion of our management, the 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 September 30, 2017 and December 31, 2016 ; • Statements of Operations for the three and nine months ended September 30, 2017 and 2016 ; • Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016 ; and • Statements of Cash Flows for the nine months ended September 30, 2017 and 2016 . 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 notes. Actual results may differ from those estimates. Results for the nine months ended September 30, 2017 and 2016 are not necessarily indicative of the results to be realized for the full year of 2017 , or that we realized for the full year of 2016 . Certain amounts in the 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	9 Months Ended
	Sep. 30, 2017
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. We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6 million ( $100.6 million net of tax). We did no t have a write-down in the first nine months of 2017.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Acquisitions and divestitures	ACQUISITIONS AND DIVESTITURES Acquisitions On April 3, 2017, we closed on an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million . As of January 1, 2017 , the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction. We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations , which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It is based on information available to us at the time these unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands): Adjusted Purchase Price Total consideration given $ 54,332 Adjusted Allocation of Purchase Price Oil and natural gas properties included in the full cost pool: Proved oil and natural gas properties $ 43,745 Undeveloped oil and natural gas properties 8,650 Total oil and natural gas properties included in the full cost pool (1) 52,395 Gas gathering equipment and other 2,340 Asset retirement obligation (403 ) Fair value of net assets acquired $ 54,332 (1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. The pro forma effects of this acquired business is immaterial to the results of operations. During the third quarter of 2017, we had approximately $2.1 million in other acquisitions. Divestitures We sold non-core oil and natural gas assets, net of related expenses, for $18.0 million during the first nine months of 2017, compared to $43.6 million during the first nine months of 2016. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	EARNINGS (LOSS) PER SHARE Information related to the calculation of earnings (loss) per share follows: Earnings (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the three months ended September 30, 2017 Basic earnings per common share $ 3,705 51,386 $ 0.07 Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) — 586 — Diluted earnings per common share $ 3,705 51,972 $ 0.07 For the three months ended September 30, 2016 Basic loss per common share $ (24,022 ) 50,081 $ (0.48 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (24,022 ) 50,081 $ (0.48 ) Due to the net loss for the three months ended September 30, 2016, approximately 546,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above. 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 September 30, 2017 2016 Stock options and SARs 178,755 240,270 Average exercise price $ 47.75 $ 49.29 Earnings (Loss) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the nine months ended September 30, 2017 Basic earnings per common share $ 28,693 51,019 $ 0.56 Effect of dilutive stock options, restricted stock, and SARs — 550 — Diluted earnings per common share $ 28,693 51,569 $ 0.56 For the nine months ended September 30, 2016 Basic loss per common share $ (137,307 ) 50,012 $ (2.75 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (137,307 ) 50,012 $ (2.75 ) Because of the net loss for the nine months ended September 30, 2016, approximately 424,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above. 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: Nine Months Ended September 30, 2017 2016 Stock options and SARs 178,755 240,270 Average exercise price $ 47.75 $ 49.29

Accrued Liabilities

Accrued Liabilities	9 Months Ended
	Sep. 30, 2017
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES Accrued liabilities consisted of: September 30, December 31, (In thousands) Interest payable $ 17,480 $ 6,524 Employee costs 14,526 15,394 Lease operating expenses 12,686 10,075 Taxes 9,982 2,219 Third-party credits 2,184 2,998 Other 3,274 2,441 Total accrued liabilities $ 60,132 $ 39,651

Long-Term Debt And Other Long-T

Long-Term Debt And Other Long-Term Liabilities	9 Months Ended
	Sep. 30, 2017
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 as of the dates indicated consisted of the following: September 30, December 31, (In thousands) Credit agreement with an average interest rate of 3.3% and 2.8% at September 30, 2017 and December 31, 2016, respectively $ 162,100 $ 160,800 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount 812,100 810,800 Less: unamortized discount (2,380 ) (2,804 ) Less: debt issuance costs, net (5,887 ) (7,079 ) Total long-term debt $ 803,833 $ 800,917 Credit Agreement. Our Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020 . Under the credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million . Our borrowing base and elected commitment is $475.0 million . We are charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage 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. Under the credit agreement, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8% ) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C. The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The October 2017 redetermination did not result in any changes. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements 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 LIBOR base for the 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 September 30, 2017 , we had $162.1 million of 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 following quarter, 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 September 30, 2017 , we were in compliance with the credit agreement covenants. 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 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 issuing 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. We may redeem all or, occasionally, 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 to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that 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 September 30, 2017 . Other Long-Term Liabilities Other long-term liabilities consisted of the following: September 30, December 31, (In thousands) Asset retirement obligation (ARO) liability $ 75,485 $ 70,170 Capital lease obligations 16,161 18,918 Workers’ compensation 13,420 15,163 Separation benefit plans 6,020 4,943 Deferred compensation plan 5,287 4,578 Gas balancing liability 3,322 3,789 Other — 410 119,695 117,971 Less current portion 14,227 14,907 Total other long-term liabilities $ 105,468 $ 103,064 Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve month periods beginning October 1, 2017 (and through 2022) are $14.2 million , $48.3 million , $172.4 million , $657.0 million , and $2.5 million , respectively. Capital Leases In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.8 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $12.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 . These capital leases are discounted using annual rates of 4.00% . Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million , respectively, at September 30, 2017 . Annual payments, net of maintenance and interest, average $4.1 million annually through 2021 . At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value. Future payments required under the capital leases at September 30, 2017 : Amount Beginning October 1, (In thousands) 2017 $ 6,168 2018 6,168 2019 6,168 2020 5,310 Total future payments 23,814 Less payments related to: Maintenance 6,320 Interest 1,333 Present value of future minimum payments $ 16,161

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. 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 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: Nine Months Ended September 30, 2017 2016 (In thousands) ARO liability, January 1: $ 70,170 $ 98,297 Accretion of discount 2,112 2,147 Liability incurred 1,123 311 Liability settled (1,350 ) (874 ) Liability sold (1) (1,563 ) (10,758 ) Revision of estimates (2) 4,993 (18,102 ) ARO liability, September 30: 75,485 71,021 Less current portion 2,947 3,498 Total long-term ARO $ 72,538 $ 67,523 _______________________ (1) We sold our interest in a number of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively. (2) Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Compensation—Stock Compensation. The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements. Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the subsequent measurement of goodwill. The amendments eliminate Step 2 from the goodwill impairment test. The amendments will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements. Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendments will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements. Leases. The FASB has issued ASU 2016-02. The amendments will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are in the process of evaluating the impact these amendments will have on our financial statements. Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. These amendments affect 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 amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which will be codified in the new Topic 606, and it is effective January 1. 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We will adopt these amendments January 1, 2018. The new revenue standard provides a five-step analysis of transactions to determine the amount and timing of revenue recognition. Entities can choose to apply Topic 606 using either the full retrospective approach or a modified retrospective approach. We plan to adopt using the modified retrospective approach, which will result in a cumulative effect adjustment upon adoption. Currently, management believes the effect of adoption will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but the adoption will result in more robust footnote disclosures in regards to revenue. We anticipate a cumulative effect of applying the new revenue standard as an adjustment to the opening balance of retained earnings at the beginning of 2018 in relation to certain mid-stream segment and contract drilling segment contracts that include adjustments to the timing of revenue recognition of certain demand fee and mobilization/demobilization expenses and revenue, respectively. We believe this adjustment will not be material due to the short-term nature of the majority of our current contract drilling segment contracts and the limited number of mid-stream segment contracts with demand fees that we anticipate to be in place at the adoption date. Part of our review included evaluation of the following issues: • Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees that are collectible in the early stages of a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract. • Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period of time. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires that these types of arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue at the time it is not expected to be subject to a significant reversal. Adopted Standards Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations are 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 were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments require current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset which is now netted with our noncurrent deferred tax liability. P rior periods were not retrospectively adjusted. 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 were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily impact classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.

Stock-Based Compensation

Stock-Based Compensation	9 Months Ended
	Sep. 30, 2017
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 Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In millions) Recognized stock compensation expense $ 3.2 $ 1.9 $ 9.0 $ 7.2 Capitalized stock compensation cost for our oil and natural gas properties 0.5 0.4 1.3 1.6 Tax benefit on stock based compensation 1.2 0.7 3.4 2.7 The remaining unrecognized compensation cost related to unvested awards at September 30, 2017 is approximately $14.2 million , of which $1.7 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one year . Our 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 7,000,000 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 nine month periods ending September 30, 2017 or 2016 . We did not grant any restricted stock awards during either of the three month periods ending September 30, 2017 or 2016 . The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated: Nine Months Ended Nine Months Ended September 30, 2017 September 30, 2016 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees 475,799 173,373 486,578 152,373 Non-employee directors 49,104 — 90,000 — 524,903 173,373 576,578 152,373 Estimated fair value (in millions): (1) Employees $ 11.8 $ 4.5 $ 2.6 $ 0.8 Non-employee directors 0.9 — 0.9 — $ 12.7 $ 4.5 $ 3.5 $ 0.8 Percentage of shares granted expected to be distributed: Employees 95 % 91 % 94 % 89 % 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 nine months of 2017 and 2016 are being recognized over a three -year vesting period. During the first two quarters of 2017 and 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 subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200% . Based on a probability assessment of the selected performance criteria at September 30, 2017, the participants are estimated to receive 81% of the 2017, 153% of the 2016, and 40% of the 2015 performance based shares. The CFTA performance measurement at September 30, 2017 was assessed to vest at target or 100% . The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2017 awards for the first nine months of 2017 was $5.8 million .

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	DERIVATIVES Commodity Derivatives We have entered into various types of derivative transactions covering some of our projected natural gas 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 September 30, 2017 , our derivative transactions were comprised of 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. Any changes in the fair value of our derivative transactions 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 September 30, 2017 , the following derivatives were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Oct'17 Natural gas – swap 70,000 MMBtu/day $3.038 IF – NYMEX (HH) Nov’17 – Dec'17 Natural gas – swap 60,000 MMBtu/day $2.960 IF – NYMEX (HH) Jan’18 – Dec'18 Natural gas – swap 20,000 MMBtu/day $3.013 IF – NYMEX (HH) Nov’17 – Dec'17 Natural gas – basis swap 20,000 MMBtu/day $(0.215) IF – NYMEX (HH) Jan’18 – Mar'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH) Nov’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH) Oct'17 Natural gas – collar 20,000 MMBtu/day $2.88 - $3.10 IF – NYMEX (HH) Oct'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH) Nov’17 – Dec'17 Natural gas – three-way collar 25,000 MMBtu/day $2.90 - $2.30 - $3.59 IF – NYMEX (HH) Jan'18 – Mar'18 Natural gas – three-way collar 60,000 MMBtu/day $3.29 - $2.63 - $4.07 IF – NYMEX (HH) Apr'18 – Dec'18 Natural gas – three-way collar 20,000 MMBtu/day $3.00 - $2.50 - $3.51 IF – NYMEX (HH) Oct’17 – Dec'17 Crude oil – three-way collar 3,750 Bbl/day $49.79 - $39.58 - $60.98 WTI – NYMEX Jan'18 – Dec'18 Crude oil – three-way collar 2,000 Bbl/day $47.50 - $37.50 - $56.08 WTI – NYMEX Jan'18 – Dec'18 Crude oil – swap 2,000 Bbl/day $50.140 WTI – NYMEX After September 30, 2017 , the following derivative was entered into: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Apr'18 – Oct'18 Natural gas – swap 10,000 MMBtu/day $2.990 IF – NYMEX (HH) Apr'18 – Sep'18 Liquids – swap (1) 1,000 Bbl/day $31.164 OPIS – Mont Belvieu _______________________ (1) Type of liquid involved is propane. 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 September 30, December 31, (In thousands) Commodity derivatives: Current Current derivative asset $ 1,064 $ — Long-term Non-current derivative asset — 377 Total derivative assets $ 1,064 $ 377 Derivative Liabilities Fair Value Balance Sheet Location September 30, December 31, (In thousands) Commodity derivatives: Current Current derivative liability $ 636 $ 21,564 Long-term Non-current derivative liability 282 415 Total derivative liabilities $ 918 $ 21,979 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 in our Unaudited Condensed Consolidated Balance Sheets. Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended September 30 : Derivatives Instruments Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative 2017 2016 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (2,614 ) $ 6,969 Total $ (2,614 ) $ 6,969 _______________________ (1) Amounts settled during the 2017 and 2016 periods include net proceeds of $0.8 million and net payments of $0.5 million , respectively. Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30 : Derivatives Instruments Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative 2017 2016 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ 21,019 $ (4,774 ) Total $ 21,019 $ (4,774 ) _______________________ (1) Amounts settled during the 2017 and 2016 periods include net payments of $0.7 million and net proceeds of $11.7 million , respectively.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities: Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (In thousands) Equity Securities: September 30, 2017 $ 830 $ 85 $ — $ 915 December 31, 2016 $ — $ — $ — $ — During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. 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: September 30, 2017 Level 1 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ — $ 662 $ 1,964 $ (1,562 ) $ 1,064 Liabilities — (2,002 ) (478 ) 1,562 (918 ) Total commodity derivatives — (1,340 ) 1,486 — 146 Equity securities 915 — — — 915 $ 915 $ (1,340 ) $ 1,486 $ — $ 1,061 December 31, 2016 Level 1 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ — $ 878 $ 43 $ (544 ) $ 377 Liabilities — (15,358 ) (7,165 ) 544 (21,979 ) $ — $ (14,480 ) $ (7,122 ) $ — $ (21,602 ) All 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 cash collateral with our counterparties and no collateral has been posted as of September 30, 2017 . We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities). Level 1 Fair Value Measurements Equity Securities. We measure the fair values of our available for sale securities based on market quotes. 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 table is a reconciliation of our level 3 fair value measurements: Net Derivatives Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Beginning of period $ 4,093 $ (4,761 ) $ (7,122 ) $ 9,094 Total gains or losses (realized and unrealized): Included in earnings (1) (2,015 ) 3,077 9,102 (3,257 ) Settlements (592 ) (443 ) (494 ) (7,964 ) End of period $ 1,486 $ (2,127 ) $ 1,486 $ (2,127 ) Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period $ (2,607 ) $ 2,634 $ 8,608 $ (11,221 ) _______________________ (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 September 30, 2017 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil three-way collars $ (9 ) Discounted cash flow Forward commodity price curve ($3.65) - $5.02 Natural gas collar $ 25 Discounted cash flow Forward commodity price curve ($0.11) - $0.06 Natural gas three-way collars $ 1,470 Discounted cash flow Forward commodity price curve ($0.34) - $0.54 _______________________ (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. Our valuation at September 30, 2017 reflected that the 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 September 30, 2017 , 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 considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at September 30, 2017 and December 31, 2016 was $162.1 million and $160.8 million , respectively. This debt would be classified as Level 2. The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 were $641.7 million and $640.1 million , respectively. We estimate the fair value of the Notes using quoted marked prices at September 30, 2017 and December 31, 2016 was $654.6 million and $649.9 million , respectively. The 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.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $3.2 million , $0.8 million , $0.4 million , $0.3 million , and less than $0.1 million in twelve month periods beginning October 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $6.4 million and $8.7 million for the first nine months of 2017 and 2016, respectively. In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the four successive twelve month periods beginning October 1, 2017 (and through the end of 2021) are $6.2 million , $6.2 million , $6.2 million , and $5.3 million . Total maintenance and interest remaining related to these leases are $6.3 million and $1.3 million , respectively at September 30, 2017 . Annual payments, net of maintenance and interest, average $4.1 million annually through 2021 . At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value. The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first nine months of 2016. We made repurchases of $2,900 during the first nine months of 2017. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well. For the next twelve months, we have committed to purchase approximately $3.9 million of new drilling rig components.

Equity

Equity	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Equity	EQUITY At-the-Market (ATM) Common Stock Program On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million . We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes. Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms and conditions of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose). We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights. As of September 30, 2017 , we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million . Accumulated Other Comprehensive Income Components of accumulated other comprehensive income were as follows for the three months ended September 30 : 2017 2016 (In thousands) Unrealized appreciation on securities, before tax $ 53 $ — Tax expense (20 ) — Unrealized appreciation on securities, net of tax $ 33 $ — Changes in accumulated other comprehensive income by component, net of tax, for the three months ended September 30 are as follows: Net Gains on Equity Securities 2017 2016 (In thousands) Balance at July 1: $ 20 $ — Unrealized appreciation before reclassifications 33 — Amounts reclassified from accumulated other comprehensive income — — Net current-period other comprehensive income 33 — Balance at September 30: $ 53 $ — Components of accumulated other comprehensive income were as follows for the nine months ended September 30 : 2017 2016 (In thousands) Unrealized appreciation on securities, before tax $ 85 $ — Tax expense (32 ) — Unrealized appreciation on securities, net of tax $ 53 $ — Changes in accumulated other comprehensive income by component, net of tax, for the nine months ended September 30 are as follows: Net Gains on Equity Securities 2017 2016 (In thousands) Balance at January 1: $ — $ — Unrealized appreciation before reclassifications 53 — Amounts reclassified from accumulated other comprehensive income — — Net current-period other comprehensive income 53 — Balance at September 30: $ 53 $ —

Industry Segment Information

Industry Segment Information	9 Months Ended
	Sep. 30, 2017
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 acquisition, development, 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 tables provide certain information about the operations of each of our segments: Three Months Ended September 30, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 85,470 $ — $ — $ — $ — $ 85,470 Contract drilling — 55,588 — — (3,969 ) 51,619 Gas gathering and processing — — 69,057 — (17,658 ) 51,399 Total revenues 85,470 55,588 69,057 — (21,627 ) 188,488 Expenses: Operating costs: Oil and natural gas 35,082 — — — (1,171 ) 33,911 Contract drilling — 38,115 — — (3,368 ) 34,747 Gas gathering and processing — — 54,602 — (16,486 ) 38,116 Total operating costs 35,082 38,115 54,602 — (21,025 ) 106,774 Depreciation, depletion, and amortization 26,460 15,280 10,880 1,913 — 54,533 Total expenses 61,542 53,395 65,482 1,913 (21,025 ) 161,307 Total operating income (loss) (1) 23,928 2,193 3,575 (1,913 ) (602 ) General and administrative expense — — — (9,235 ) — (9,235 ) Gain (loss) on disposition of assets (1 ) 68 14 — — 81 Loss on derivatives — — — (2,614 ) — (2,614 ) Interest expense, net — — — (9,944 ) — (9,944 ) Other — — — 5 — 5 Income (loss) before income taxes $ 23,927 $ 2,261 $ 3,589 $ (23,701 ) $ (602 ) $ 5,474 _______________________ (1) Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes. Three Months Ended September 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 78,854 $ — $ — $ — $ — $ 78,854 Contract drilling — 25,819 — — — 25,819 Gas gathering and processing — — 63,090 — (14,355 ) 48,735 Total revenues 78,854 25,819 63,090 — (14,355 ) 153,408 Expenses: Operating costs: Oil and natural gas 27,710 — — — (1,696 ) 26,014 Contract drilling — 19,137 — — — 19,137 Gas gathering and processing — — 48,397 — (12,659 ) 35,738 Total operating costs 27,710 19,137 48,397 — (14,355 ) 80,889 Depreciation, depletion, and amortization 27,135 11,318 11,436 80 — 49,969 Impairments 49,443 — — — — 49,443 Total expenses 104,288 30,455 59,833 80 (14,355 ) 180,301 Total operating income (loss) (1) (25,434 ) (4,636 ) 3,257 (80 ) — General and administrative expense — — — (8,852 ) — (8,852 ) Gain on disposition of assets — 151 — 3 — 154 Gain on derivatives — — — 6,969 — 6,969 Interest expense, net — — — (10,002 ) — (10,002 ) Other — — — 3 — 3 Income (loss) before income taxes $ (25,434 ) $ (4,485 ) $ 3,257 $ (11,959 ) $ — $ (38,621 ) _______________________ (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. Nine Months Ended September 30, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 256,241 $ — $ — $ — $ — $ 256,241 Contract drilling — 137,617 — — (9,558 ) 128,059 Gas gathering and processing — — 198,632 — (48,139 ) 150,493 Total revenues 256,241 137,617 198,632 — (57,697 ) 534,793 Expenses: Operating costs: Oil and natural gas 99,349 — — — (3,476 ) 95,873 Contract drilling — 99,794 — — (8,581 ) 91,213 Gas gathering and processing — — 156,525 — (44,663 ) 111,862 Total operating costs 99,349 99,794 156,525 — (56,720 ) 298,948 Depreciation, depletion, and amortization 71,544 41,896 32,547 5,558 — 151,545 Total expenses 170,893 141,690 189,072 5,558 (56,720 ) 450,493 Total operating income (loss) (1) 85,348 (4,073 ) 9,560 (5,558 ) (977 ) General and administrative expense — — — (26,902 ) — (26,902 ) Gain on disposition of assets 176 106 58 813 — 1,153 Gain on derivatives — — — 21,019 — 21,019 Interest expense, net — — — (28,807 ) — (28,807 ) Other — — — 14 — 14 Income (loss) before income taxes $ 85,524 $ (3,967 ) $ 9,618 $ (39,421 ) $ (977 ) $ 50,777 _______________________ (1) Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes. Nine Months Ended September 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 206,318 $ — $ — $ — $ — $ 206,318 Contract drilling — 88,786 — — — 88,786 Gas gathering and processing — — 168,668 — (35,875 ) 132,793 Total revenues 206,318 88,786 168,668 — (35,875 ) 427,897 Expenses: Operating costs: Oil and natural gas 98,070 — — — (5,379 ) 92,691 Contract drilling — 66,489 — — — 66,489 Gas gathering and processing — — 129,681 — (30,496 ) 99,185 Total operating costs 98,070 66,489 129,681 — (35,875 ) 258,365 Depreciation, depletion, and amortization 89,378 34,431 34,410 218 — 158,437 Impairments 161,563 — — — — 161,563 Total expenses 349,011 100,920 164,091 218 (35,875 ) 578,365 Total operating income (loss) (1) (142,693 ) (12,134 ) 4,577 (218 ) — General and administrative expense — — — (25,811 ) — (25,811 ) Gain (loss) on disposition of assets (324 ) 1,467 (302 ) — (18 ) — 823 Loss on derivatives — — — (4,774 ) — (4,774 ) Interest expense, net — — — (30,225 ) — (30,225 ) Other — — — (11 ) — (11 ) Income (loss) before income taxes $ (143,017 ) $ (10,667 ) $ 4,275 $ (61,057 ) $ — $ (210,466 ) _______________________ (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.

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Fair Value of Acquired Assets and Liabilities	We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands): Adjusted Purchase Price Total consideration given $ 54,332 Adjusted Allocation of Purchase Price Oil and natural gas properties included in the full cost pool: Proved oil and natural gas properties $ 43,745 Undeveloped oil and natural gas properties 8,650 Total oil and natural gas properties included in the full cost pool (1) 52,395 Gas gathering equipment and other 2,340 Asset retirement obligation (403 ) Fair value of net assets acquired $ 54,332 (1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Schedule of Earnings (Loss) Per Share	Information related to the calculation of earnings (loss) per share follows: Earnings (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the three months ended September 30, 2017 Basic earnings per common share $ 3,705 51,386 $ 0.07 Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) — 586 — Diluted earnings per common share $ 3,705 51,972 $ 0.07 For the three months ended September 30, 2016 Basic loss per common share $ (24,022 ) 50,081 $ (0.48 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (24,022 ) 50,081 $ (0.48 ) Earnings (Loss) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the nine months ended September 30, 2017 Basic earnings per common share $ 28,693 51,019 $ 0.56 Effect of dilutive stock options, restricted stock, and SARs — 550 — Diluted earnings per common share $ 28,693 51,569 $ 0.56 For the nine months ended September 30, 2016 Basic loss per common share $ (137,307 ) 50,012 $ (2.75 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (137,307 ) 50,012 $ (2.75 )
Schedule of Antidilutive Securities Excluded From Computation of Earnings (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 September 30, 2017 2016 Stock options and SARs 178,755 240,270 Average exercise price $ 47.75 $ 49.29 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: Nine Months Ended September 30, 2017 2016 Stock options and SARs 178,755 240,270 Average exercise price $ 47.75 $ 49.29

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2017
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	Accrued liabilities consisted of: September 30, December 31, (In thousands) Interest payable $ 17,480 $ 6,524 Employee costs 14,526 15,394 Lease operating expenses 12,686 10,075 Taxes 9,982 2,219 Third-party credits 2,184 2,998 Other 3,274 2,441 Total accrued liabilities $ 60,132 $ 39,651

Long-Term Debt And Other Long25

Long-Term Debt And Other Long-Term Liabilities (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Our long-term debt as of the dates indicated consisted of the following: September 30, December 31, (In thousands) Credit agreement with an average interest rate of 3.3% and 2.8% at September 30, 2017 and December 31, 2016, respectively $ 162,100 $ 160,800 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount 812,100 810,800 Less: unamortized discount (2,380 ) (2,804 ) Less: debt issuance costs, net (5,887 ) (7,079 ) Total long-term debt $ 803,833 $ 800,917
Other Long-Term Liabilities	Other long-term liabilities consisted of the following: September 30, December 31, (In thousands) Asset retirement obligation (ARO) liability $ 75,485 $ 70,170 Capital lease obligations 16,161 18,918 Workers’ compensation 13,420 15,163 Separation benefit plans 6,020 4,943 Deferred compensation plan 5,287 4,578 Gas balancing liability 3,322 3,789 Other — 410 119,695 117,971 Less current portion 14,227 14,907 Total other long-term liabilities $ 105,468 $ 103,064
Capital leases	Future payments required under the capital leases at September 30, 2017 : Amount Beginning October 1, (In thousands) 2017 $ 6,168 2018 6,168 2019 6,168 2020 5,310 Total future payments 23,814 Less payments related to: Maintenance 6,320 Interest 1,333 Present value of future minimum payments $ 16,161

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The following table shows certain information about our AROs for the periods indicated: Nine Months Ended September 30, 2017 2016 (In thousands) ARO liability, January 1: $ 70,170 $ 98,297 Accretion of discount 2,112 2,147 Liability incurred 1,123 311 Liability settled (1,350 ) (874 ) Liability sold (1) (1,563 ) (10,758 ) Revision of estimates (2) 4,993 (18,102 ) ARO liability, September 30: 75,485 71,021 Less current portion 2,947 3,498 Total long-term ARO $ 72,538 $ 67,523 _______________________ (1) We sold our interest in a number of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively. (2) Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2017
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 Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In millions) Recognized stock compensation expense $ 3.2 $ 1.9 $ 9.0 $ 7.2 Capitalized stock compensation cost for our oil and natural gas properties 0.5 0.4 1.3 1.6 Tax benefit on stock based compensation 1.2 0.7 3.4 2.7
Schedule of Fair Value of the Restricted Stock Awards Granted During the Periods	The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated: Nine Months Ended Nine Months Ended September 30, 2017 September 30, 2016 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees 475,799 173,373 486,578 152,373 Non-employee directors 49,104 — 90,000 — 524,903 173,373 576,578 152,373 Estimated fair value (in millions): (1) Employees $ 11.8 $ 4.5 $ 2.6 $ 0.8 Non-employee directors 0.9 — 0.9 — $ 12.7 $ 4.5 $ 3.5 $ 0.8 Percentage of shares granted expected to be distributed: Employees 95 % 91 % 94 % 89 % 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)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives outstanding	At September 30, 2017 , the following derivatives were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Oct'17 Natural gas – swap 70,000 MMBtu/day $3.038 IF – NYMEX (HH) Nov’17 – Dec'17 Natural gas – swap 60,000 MMBtu/day $2.960 IF – NYMEX (HH) Jan’18 – Dec'18 Natural gas – swap 20,000 MMBtu/day $3.013 IF – NYMEX (HH) Nov’17 – Dec'17 Natural gas – basis swap 20,000 MMBtu/day $(0.215) IF – NYMEX (HH) Jan’18 – Mar'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH) Nov’18 – Dec'18 Natural gas – basis swap 10,000 MMBtu/day $(0.208) IF – NYMEX (HH) Oct'17 Natural gas – collar 20,000 MMBtu/day $2.88 - $3.10 IF – NYMEX (HH) Oct'17 Natural gas – three-way collar 15,000 MMBtu/day $2.50 - $2.00 - $3.32 IF – NYMEX (HH) Nov’17 – Dec'17 Natural gas – three-way collar 25,000 MMBtu/day $2.90 - $2.30 - $3.59 IF – NYMEX (HH) Jan'18 – Mar'18 Natural gas – three-way collar 60,000 MMBtu/day $3.29 - $2.63 - $4.07 IF – NYMEX (HH) Apr'18 – Dec'18 Natural gas – three-way collar 20,000 MMBtu/day $3.00 - $2.50 - $3.51 IF – NYMEX (HH) Oct’17 – Dec'17 Crude oil – three-way collar 3,750 Bbl/day $49.79 - $39.58 - $60.98 WTI – NYMEX Jan'18 – Dec'18 Crude oil – three-way collar 2,000 Bbl/day $47.50 - $37.50 - $56.08 WTI – NYMEX Jan'18 – Dec'18 Crude oil – swap 2,000 Bbl/day $50.140 WTI – NYMEX
Subsequent Derivatives Outstanding	After September 30, 2017 , the following derivative was entered into: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Apr'18 – Oct'18 Natural gas – swap 10,000 MMBtu/day $2.990 IF – NYMEX (HH) Apr'18 – Sep'18 Liquids – swap (1) 1,000 Bbl/day $31.164 OPIS – Mont Belvieu
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 September 30, December 31, (In thousands) Commodity derivatives: Current Current derivative asset $ 1,064 $ — Long-term Non-current derivative asset — 377 Total derivative assets $ 1,064 $ 377 Derivative Liabilities Fair Value Balance Sheet Location September 30, December 31, (In thousands) Commodity derivatives: Current Current derivative liability $ 636 $ 21,564 Long-term Non-current derivative liability 282 415 Total derivative liabilities $ 918 $ 21,979
Effect of Derivative Instruments Recognized in Statements of Operations, Derivative Instruments	Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended September 30 : Derivatives Instruments Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative 2017 2016 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ (2,614 ) $ 6,969 Total $ (2,614 ) $ 6,969 _______________________ (1) Amounts settled during the 2017 and 2016 periods include net proceeds of $0.8 million and net payments of $0.5 million , respectively. Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30 : Derivatives Instruments Location of Gain (Loss) Recognized in Income on Derivative Amount of Gain (Loss) Recognized in Income on Derivative 2017 2016 (In thousands) Commodity derivatives Gain (loss) on derivatives (1) $ 21,019 $ (4,774 ) Total $ 21,019 $ (4,774 ) _______________________ (1) Amounts settled during the 2017 and 2016 periods include net payments of $0.7 million and net proceeds of $11.7 million , respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value of Available-for-sale Securities	The following is a summary of available-for-sale securities: Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value (In thousands) Equity Securities: September 30, 2017 $ 830 $ 85 $ — $ 915 December 31, 2016 $ — $ — $ — $ —
Recurring Fair Value Measurements	The following tables set forth our recurring fair value measurements: September 30, 2017 Level 1 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ — $ 662 $ 1,964 $ (1,562 ) $ 1,064 Liabilities — (2,002 ) (478 ) 1,562 (918 ) Total commodity derivatives — (1,340 ) 1,486 — 146 Equity securities 915 — — — 915 $ 915 $ (1,340 ) $ 1,486 $ — $ 1,061 December 31, 2016 Level 1 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ — $ 878 $ 43 $ (544 ) $ 377 Liabilities — (15,358 ) (7,165 ) 544 (21,979 ) $ — $ (14,480 ) $ (7,122 ) $ — $ (21,602 )
Reconciliations Of Level 3 Fair Value Measurements	The following table is a reconciliation of our level 3 fair value measurements: Net Derivatives Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Beginning of period $ 4,093 $ (4,761 ) $ (7,122 ) $ 9,094 Total gains or losses (realized and unrealized): Included in earnings (1) (2,015 ) 3,077 9,102 (3,257 ) Settlements (592 ) (443 ) (494 ) (7,964 ) End of period $ 1,486 $ (2,127 ) $ 1,486 $ (2,127 ) Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period $ (2,607 ) $ 2,634 $ 8,608 $ (11,221 ) _______________________ (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 September 30, 2017 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil three-way collars $ (9 ) Discounted cash flow Forward commodity price curve ($3.65) - $5.02 Natural gas collar $ 25 Discounted cash flow Forward commodity price curve ($0.11) - $0.06 Natural gas three-way collars $ 1,470 Discounted cash flow Forward commodity price curve ($0.34) - $0.54 _______________________ (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.

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Components of accumulated other comprehensive income were as follows for the three months ended September 30 : 2017 2016 (In thousands) Unrealized appreciation on securities, before tax $ 53 $ — Tax expense (20 ) — Unrealized appreciation on securities, net of tax $ 33 $ — Components of accumulated other comprehensive income were as follows for the nine months ended September 30 : 2017 2016 (In thousands) Unrealized appreciation on securities, before tax $ 85 $ — Tax expense (32 ) — Unrealized appreciation on securities, net of tax $ 53 $ —
Reclassification Out of Accumulated Other Comprehensive Income (Loss)	Changes in accumulated other comprehensive income by component, net of tax, for the three months ended September 30 are as follows: Net Gains on Equity Securities 2017 2016 (In thousands) Balance at July 1: $ 20 $ — Unrealized appreciation before reclassifications 33 — Amounts reclassified from accumulated other comprehensive income — — Net current-period other comprehensive income 33 — Balance at September 30: $ 53 $ — Changes in accumulated other comprehensive income by component, net of tax, for the nine months ended September 30 are as follows: Net Gains on Equity Securities 2017 2016 (In thousands) Balance at January 1: $ — $ — Unrealized appreciation before reclassifications 53 — Amounts reclassified from accumulated other comprehensive income — — Net current-period other comprehensive income 53 — Balance at September 30: $ 53 $ —

Industry Segment Information (T

Industry Segment Information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Industry segment information	The following tables provide certain information about the operations of each of our segments: Three Months Ended September 30, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 85,470 $ — $ — $ — $ — $ 85,470 Contract drilling — 55,588 — — (3,969 ) 51,619 Gas gathering and processing — — 69,057 — (17,658 ) 51,399 Total revenues 85,470 55,588 69,057 — (21,627 ) 188,488 Expenses: Operating costs: Oil and natural gas 35,082 — — — (1,171 ) 33,911 Contract drilling — 38,115 — — (3,368 ) 34,747 Gas gathering and processing — — 54,602 — (16,486 ) 38,116 Total operating costs 35,082 38,115 54,602 — (21,025 ) 106,774 Depreciation, depletion, and amortization 26,460 15,280 10,880 1,913 — 54,533 Total expenses 61,542 53,395 65,482 1,913 (21,025 ) 161,307 Total operating income (loss) (1) 23,928 2,193 3,575 (1,913 ) (602 ) General and administrative expense — — — (9,235 ) — (9,235 ) Gain (loss) on disposition of assets (1 ) 68 14 — — 81 Loss on derivatives — — — (2,614 ) — (2,614 ) Interest expense, net — — — (9,944 ) — (9,944 ) Other — — — 5 — 5 Income (loss) before income taxes $ 23,927 $ 2,261 $ 3,589 $ (23,701 ) $ (602 ) $ 5,474 _______________________ (1) Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes. Three Months Ended September 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 78,854 $ — $ — $ — $ — $ 78,854 Contract drilling — 25,819 — — — 25,819 Gas gathering and processing — — 63,090 — (14,355 ) 48,735 Total revenues 78,854 25,819 63,090 — (14,355 ) 153,408 Expenses: Operating costs: Oil and natural gas 27,710 — — — (1,696 ) 26,014 Contract drilling — 19,137 — — — 19,137 Gas gathering and processing — — 48,397 — (12,659 ) 35,738 Total operating costs 27,710 19,137 48,397 — (14,355 ) 80,889 Depreciation, depletion, and amortization 27,135 11,318 11,436 80 — 49,969 Impairments 49,443 — — — — 49,443 Total expenses 104,288 30,455 59,833 80 (14,355 ) 180,301 Total operating income (loss) (1) (25,434 ) (4,636 ) 3,257 (80 ) — General and administrative expense — — — (8,852 ) — (8,852 ) Gain on disposition of assets — 151 — 3 — 154 Gain on derivatives — — — 6,969 — 6,969 Interest expense, net — — — (10,002 ) — (10,002 ) Other — — — 3 — 3 Income (loss) before income taxes $ (25,434 ) $ (4,485 ) $ 3,257 $ (11,959 ) $ — $ (38,621 ) _______________________ (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. Nine Months Ended September 30, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 256,241 $ — $ — $ — $ — $ 256,241 Contract drilling — 137,617 — — (9,558 ) 128,059 Gas gathering and processing — — 198,632 — (48,139 ) 150,493 Total revenues 256,241 137,617 198,632 — (57,697 ) 534,793 Expenses: Operating costs: Oil and natural gas 99,349 — — — (3,476 ) 95,873 Contract drilling — 99,794 — — (8,581 ) 91,213 Gas gathering and processing — — 156,525 — (44,663 ) 111,862 Total operating costs 99,349 99,794 156,525 — (56,720 ) 298,948 Depreciation, depletion, and amortization 71,544 41,896 32,547 5,558 — 151,545 Total expenses 170,893 141,690 189,072 5,558 (56,720 ) 450,493 Total operating income (loss) (1) 85,348 (4,073 ) 9,560 (5,558 ) (977 ) General and administrative expense — — — (26,902 ) — (26,902 ) Gain on disposition of assets 176 106 58 813 — 1,153 Gain on derivatives — — — 21,019 — 21,019 Interest expense, net — — — (28,807 ) — (28,807 ) Other — — — 14 — 14 Income (loss) before income taxes $ 85,524 $ (3,967 ) $ 9,618 $ (39,421 ) $ (977 ) $ 50,777 _______________________ (1) Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes. Nine Months Ended September 30, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 206,318 $ — $ — $ — $ — $ 206,318 Contract drilling — 88,786 — — — 88,786 Gas gathering and processing — — 168,668 — (35,875 ) 132,793 Total revenues 206,318 88,786 168,668 — (35,875 ) 427,897 Expenses: Operating costs: Oil and natural gas 98,070 — — — (5,379 ) 92,691 Contract drilling — 66,489 — — — 66,489 Gas gathering and processing — — 129,681 — (30,496 ) 99,185 Total operating costs 98,070 66,489 129,681 — (35,875 ) 258,365 Depreciation, depletion, and amortization 89,378 34,431 34,410 218 — 158,437 Impairments 161,563 — — — — 161,563 Total expenses 349,011 100,920 164,091 218 (35,875 ) 578,365 Total operating income (loss) (1) (142,693 ) (12,134 ) 4,577 (218 ) — General and administrative expense — — — (25,811 ) — (25,811 ) Gain (loss) on disposition of assets (324 ) 1,467 (302 ) — (18 ) — 823 Loss on derivatives — — — (4,774 ) — (4,774 ) Interest expense, net — — — (30,225 ) — (30,225 ) Other — — — (11 ) — (11 ) Income (loss) before income taxes $ (143,017 ) $ (10,667 ) $ 4,275 $ (61,057 ) $ — $ (210,466 ) _______________________ (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.

Oil and Natural Gas (Narrative)

Oil and Natural Gas (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2017	Sep. 30, 2016
Property, Plant and Equipment [Abstract]
Future discounted net cash flows discounted				10.00%
Impairment of oil and natural gas properties	$ 0	$ 0	$ 0		$ 161,600
Non-cash ceiling test write-down net of tax					$ 100,600

Acquisitions and Divestitures (

Acquisitions and Divestitures (Fair Value of Acquired Assets and Liabilities) (Details) - USD ($) $ in Thousands		Apr. 03, 2017	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Proved oil and natural gas properties			$ 5,605,974	$ 5,446,305
Undeveloped oil and natural gas properties			337,064	314,867
Asset retirement obligation			$ (75,485)	$ (70,170)	$ (71,021)	$ (98,297)
EOG Acquisition [Member]
Total consideration given		$ 54,332
Proved oil and natural gas properties		43,745
Undeveloped oil and natural gas properties		8,650
Total oil and natural gas properties included in the full cost pool (1)	[1]	52,395
Gas gathering equipment and other		2,340
Asset retirement obligation		(403)
Fair value of net assets acquired		$ 54,332
[1]	We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.

Acquisitions and Divestitures34

Acquisitions and Divestitures (Narrative) (Details) $ in Thousands, MBoe in Millions	Apr. 03, 2017USD ($)aMBoewells	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)
Acquisitions and Divestitures
Other acquisitions		$ 2,100
Proceeds from non-core oil and natural gas asset sales, net of related expenses		$ 18,000	$ 43,600
EOG Acquisition [Member]
Acquisitions and Divestitures
Total consideration given	$ 54,332
Business Acquisition, Effective Date of Acquisition	Jan. 1, 2017
Proved Developed Reserves (Volume) | MBoe	3.2
Natural Gas Gathering System	1
EOG Acquisition [Member] | Hoxbar [Member]
Acquisitions and Divestitures
Area of Real Estate Property | a	8,300
Proved developed producing wells | wells	47
Acquired land with existing production capacity, percent	71.00%

Earnings (Loss) Per Share (Sche

Earnings (Loss) Per Share (Schedule of Earnings (Loss) Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Earnings (loss) of basic earnings (loss) per common share	$ 3,705	$ (24,022)	$ 28,693	$ (137,307)
Income of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0	0	0	0
Earnings (loss) of diluted loss per common share	$ 3,705	$ (24,022)	$ 28,693	$ (137,307)
Weighted shares of basic earnings (loss) per common share	51,386	50,081	51,019	50,012
Weighted shares of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	586	0	550	0
Weighted shares of diluted earnings (loss) per common share	51,972	50,081	51,569	50,012
Per-Share amount of basic earnings (loss) per common share	$ 0.07	$ (0.48)	$ 0.56	$ (2.75)
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 earnings (loss) per common share	$ 0.07	$ (0.48)	$ 0.56	$ (2.75)

Earnings (Loss) Per Share (Sc36

Earnings (Loss) Per Share (Schedule of Antidilutive Securities Excluded From Computation of Earnings (Loss) Per Share) (Details) - Stock options and SARs - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings (Loss) Per Share [Line Items]
Antidilutive securities excluded from computation of earnings (loss) per share	178,755	240,270	178,755	240,270
Average exercise price	$ 47.75	$ 49.29	$ 47.75	$ 49.29

Earnings (Loss) Per Share (Narr

Earnings (Loss) Per Share (Narrative) (Details) - shares	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Stock options, restricted stock, and SARs [Member]
Antidilutive Securities Excluded from Computation of Earnings (Loss) Per Share [Line Items]
Antidilutive securities excluded from computation of earnings (loss) per share due to net loss	546,000	424,000

Accrued Liabilities (Accrued Li

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accrued Liabilities, Current [Abstract]
Interest payable	$ 17,480	$ 6,524
Employee costs	14,526	15,394
Lease operating expenses	12,686	10,075
Taxes	9,982	2,219
Third-party credits	2,184	2,998
Other	3,274	2,441
Total accrued liabilities	$ 60,132	$ 39,651

Long-Term Debt And Other Long39

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Credit agreement with an average interest rate of 3.3% and 2.8% at September 30, 2017 and December 31, 2016, respectively	$ 162,100	$ 160,800
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	812,100	810,800
Less: unamortized discount	(2,380)	(2,804)
Less: debt issuance costs, net	(5,887)	(7,079)
Total long-term debt	$ 803,833	$ 800,917
Revolving credit facility interest rate	3.30%	2.80%
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 Long40

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Asset retirement obligation (ARO) liability	$ 75,485	$ 70,170	$ 71,021	$ 98,297
Capital lease obligations	16,161	18,918
Workers' compensation	13,420	15,163
Separation benefit plans	6,020	4,943
Deferred compensation plan	5,287	4,578
Gas balancing liability	3,322	3,789
Other	0	410
Other liabilities	119,695	117,971
Less current portion	14,227	14,907
Total other long-term liabilities	$ 105,468	$ 103,064

Long-Term Debt And Other Long41

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt And Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Beginning October 1,
2,017	$ 6,168
2,018	6,168
2,019	6,168
2,020	5,310
Total future payments	23,814
Less payments related to:
Maintenance	6,320
Interest	1,333
Present value of future minimum payments	$ 16,161	$ 18,918

Long-Term Debt And Other Long42

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
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	$ 162,100	$ 160,800
Current ratio of credit facility	1 to 1
Aggregate principal amount	$ 650,000	$ 650,000
Interest percentage of senior subordinated notes	6.625%
Debt instrument maturity date	May 15, 2021
Original debt issuance fees	$ 14,700
Senior notes repurchase price in percentage	101.00%
Estimated principal payments in year 1	$ 14,200
Estimated principal payments in year 2	48,300
Estimated principal payments in year 3	172,400
Estimated principal payments in year 4	657,000
Estimated principal payments in year 5	$ 2,500
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,800
Capital Lease Obligations, Noncurrent	$ 12,400
Discount rate capital leases	4.00%
Maintenance	$ 6,320
Interest	1,333
Capital leases, future minimum payments, average annual payment	$ 4,100
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) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
ARO liability, January 1:		$ 70,170	$ 98,297
Accretion of discount		2,112	2,147
Liability incurred		1,123	311
Liability settled		(1,350)	(874)
Liability sold	[1]	(1,563)	(10,758)
Revision of estimates	[2]	4,993	(18,102)
ARO liability, September 30:		75,485	71,021
Less current portion		2,947	3,498
Total long-term ARO		$ 72,538	$ 67,523
[1]	We sold our interest in a number of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively.
[2]	Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Abstract]
Recognized stock compensation expense	$ 3.2	$ 1.9	$ 9	$ 7.2
Capitalized stock compensation cost for our oil and natural gas properties	0.5	0.4	1.3	1.6
Tax benefit on stock based compensation	$ 1.2	$ 0.7	$ 3.4	$ 2.7

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		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016
Time Vested [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		524,903	576,578
Estimated fair value (in millions)	[1]	$ 12.7	$ 3.5
Time Vested [Member] | Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		475,799	486,578
Estimated fair value (in millions)	[1]	$ 11.8	$ 2.6
Percentage of shares granted expected to be distributed		95.00%	94.00%
Time Vested [Member] | Non-employee Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		49,104	90,000
Estimated fair value (in millions)	[1]	$ 0.9	$ 0.9
Percentage of shares granted expected to be distributed		100.00%	100.00%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		173,373	152,373
Estimated fair value (in millions)	[1]	$ 4.5	$ 0.8
Performance Shares [Member] | Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		173,373	152,373
Estimated fair value (in millions)	[1]	$ 4.5	$ 0.8
Percentage of shares granted expected to be distributed		91.00%	89.00%
Performance Shares [Member] | Non-employee Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		0	0
Estimated fair value (in millions)	[1]	$ 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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 14.2		$ 14.2
Unrecognized compensation cost, expected to be capitalized	$ 1.7		$ 1.7
Weighted average years over which this cost will be recognized			1 year
Increase in stock compensation expense due to the restricted stock awards granted			$ 5.8
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					7,000,000
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%
Cash flow to total assets performance [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			100.00%
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			524,903	576,578
Performance Shares [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted			173,373	152,373
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
2017 [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			81.00%
2016 [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			153.00%
2015 [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria			40.00%

Derivatives (Schedule of Deriva

Derivatives (Schedule of Derivatives Outstanding) (Details)	9 Months Ended
	Sep. 30, 2017$ / UnitMMBTUbbl
Swap [Member] | Oct'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	3.038
Hedged volume (MMBtu/day) | MMBTU	70,000
Swap [Member] | Nov'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] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Weighted average price	50.140
Hedged volume (Bbl/day) | bbl	2,000
Swap [Member] | Jan'18 - Dec'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	3.013
Hedged volume (MMBtu/day) | MMBTU	20,000
Basis swap [Member] | Nov'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 - Mar'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Weighted average price	(0.208)
Hedged volume (MMBtu/day) | MMBTU	10,000
Basis swap [Member] | Nov'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] | Oct'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	20,000
Cap Price	3.10
Floor Price	2.88
Three-way collar [Member] | Oct'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
Three-way collar [Member] | Oct'17 - Dec'17 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	3,750
Cap Price	60.98
Subfloor price	39.58
Floor Price	49.79
Three-way collar [Member] | Nov'17 - Dec'17 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	25,000
Cap Price	3.59
Subfloor price	2.30
Floor Price	2.90
Three-way collar [Member] | Jan'18 - Mar'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	60,000
Cap Price	4.07
Subfloor price	2.63
Floor Price	3.29
Three-way collar [Member] | Apr'18 - Dec'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	20,000
Cap Price	3.51
Subfloor price	2.50
Floor Price	3
Three-way collar [Member] | Jan'18 - Dec'18 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	2,000
Cap Price	56.08
Subfloor price	37.50
Floor Price	47.50

Derivatives Derivatives (Schedu

Derivatives Derivatives (Schedule of Subsequent Derivatives Outstanding) (Details) - Swap [Member] - Subsequent Event [Member]	1 Months Ended
	Nov. 02, 2017$ / UnitMMBTUbbl
IF - NYMEX (HH) [Member] | Apr'18 - Oct'18 [Member] | Natural Gas [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) | MMBTU	10,000
Weighted average price	2.990
OPIS - Mont Belvieu [Member] | Apr'18 - Sep'18 [Member] | Natural Gas Liquids [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) | bbl	1,000	[1]
Weighted average price	31.164	[1]
[1]	Type of liquid involved is propane.

Derivatives (Fair Value of Deri

Derivatives (Fair Value of Derivative Instruments and Locations in Balance Sheets) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative asset	$ 1,064	$ 0
Non-current derivative asset	0	377
Total derivatives assets	1,064	377
Current derivative liability	(636)	(21,564)
Non-current derivative liability	(282)	(415)
Total derivative liabilities	$ 918	$ 21,979

Derivatives (Effect of Derivati

Derivatives (Effect of Derivative Instruments Recognized in Statement of Operations, Derivative Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2017		Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	$ (2,614)		$ 6,969		$ 21,019		$ (4,774)
Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	(2,614)		6,969		21,019		(4,774)
Amount of gain (loss) settled during the period	800		(500)		(700)		11,700
Gain (loss) on derivatives [Member] | Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivatives	$ (2,614)	[1]	$ 6,969	[1]	$ 21,019	[2]	$ (4,774)	[1]
[1]	Amounts settled during the 2017 and 2016 periods include net proceeds of $0.8 million and net payments of $0.5 million, respectively.
[2]	Amounts settled during the 2017 and 2016 periods include net payments of $0.7 million and net proceeds of $11.7 million, respectively.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Fair Value of Available-for-sale Securities) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Fair Value Measurements [Abstract]
Cost	$ 830	$ 0
Gross unrealized gains	85	0
Gross unrealized losses	0	0
Estimated fair value	$ 915	$ 0

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 1,064	$ 377
Derivative Liability	(918)	(21,979)
Equity securities	915	0
Financial assets (liabilities)	1,061	(21,602)
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	915	0
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	(1,340)	(14,480)
Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	1,486	(7,122)
Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	0	0
Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	1,064	377
Derivative Liability	(918)	(21,979)
Total commodity derivatives	146	(21,602)
Commodity Derivatives [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	0	0
Gross Liabilities	0	0
Total commodity derivatives	0	0
Commodity Derivatives [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	662	878
Gross Liabilities	(2,002)	(15,358)
Total commodity derivatives	(1,340)	(14,480)
Commodity Derivatives [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	1,964	43
Gross Liabilities	(478)	(7,165)
Total commodity derivatives	1,486	(7,122)
Commodity Derivatives [Member] | Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Effect of netting on assets	(1,562)	(544)
Effect of netting on liabilities	1,562	544
Total commodity derivatives	0	0
Available-for-sale Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	915	0
Available-for-sale Securities [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities		0
Available-for-sale Securities [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	0	0
Available-for-sale Securities [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	0	0
Available-for-sale Securities [Member] | Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	$ 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		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Beginning of period		$ 4,093	$ (4,761)	$ (7,122)	$ 9,094
Included in earnings	[1]	(2,015)	3,077	9,102	(3,257)
Settlements		(592)	(443)	(494)	(7,964)
End of period		1,486	(2,127)	1,486	(2,127)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period		$ (2,607)	$ 2,634	$ 8,608	$ (11,221)
[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	9 Months Ended
	Sep. 30, 2017USD ($)$ / Unit	[1]
Oil [Member] | Three-way collar [Member]
Derivative fair value | $	$ (9)
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	(3.65)
Oil [Member] | Three-way collar [Member] | Maximum [Member]
Forward commodity price curve	5.02
Natural Gas [Member] | Collar [Member]
Derivative fair value | $	$ 25
Derivatives Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward commodity price curve
Natural Gas [Member] | Collar [Member] | Minimum [Member]
Forward commodity price curve	(0.11)
Natural Gas [Member] | Collar [Member] | Maximum [Member]
Forward commodity price curve	0.06
Natural Gas [Member] | Three-way collar [Member]
Derivative fair value | $	$ 1,470
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	(0.34)
Natural Gas [Member] | Three-way collar [Member] | Maximum [Member]
Forward commodity price curve	0.54
[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	Sep. 30, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral posted	$ 0
Line of credit facility, amount outstanding	162,100	$ 160,800
6.625% senior subordinated notes due 2021	641,700	640,100
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Estimated fair value of long-term debt	$ 654,600	$ 649,900

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($)	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 3,200,000
Operating Leases, Future Minimum Payments, Due in Two Years	800,000
Operating Leases, Future Minimum Payments, Due in Three Years	400,000
Operating Leases, Future Minimum Payments, Due in Four Years	300,000
Operating Leases, Future Minimum Payments, Due in Five Years	25,000
Operating Leases, Rent Expense, Net	$ 6,400,000	$ 8,700,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Leases, Future Minimum Payments Due, Next Twelve Months	$ 6,168,000
Capital Leases, Future Minimum Payments Due in Two Years	6,168,000
Capital Leases, Future Minimum Payments Due in Three Years	6,168,000
Capital Leases, Future Minimum Payments Due in Four Years	5,310,000
Maintenance	6,320,000
Interest	1,333,000
Capital leases, future minimum payments, average annual payment	$ 4,100,000
Capital lease fair market value percentage for purchase	10.00%
Percentage of repurchase of limited units outstanding	20.00%
Repurchase Of Limited Units Outstanding Amount	$ 2,900	$ 0
Drilling Equipment [Member]
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 3,900,000

Equity (Schedule of Accumulated

Equity (Schedule of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule of Accumulated Other Comprehensive Income (Loss) [Abstract]
Unrealized appreciation on securities, before tax	$ 53	$ 0	$ 85	$ 0
Tax expense	(20)	0	(32)	0
Unrealized appreciation on securities, net of tax	$ 33	$ 0	$ 53	$ 0

Equity (Reclassification out of

Equity (Reclassification out of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance	$ 20	$ 0	$ 0	$ 0
Unrealized appreciation before reclassifications	33	0	53	0
Amounts reclassified from accumulated other comprehensive income	0	0	0	0
Net current-period other comprehensive income	33	0	53	0
Ending Balance	$ 53	$ 0	$ 53	$ 0

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Apr. 04, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Common stock, par value	$ 0.20			$ 0.20
Common stock, shares issued	52,879,660			51,494,318
Proceeds from issuance of common stock, net of issuance costs	$ 18,623	$ 0
At-the-Market Common Stock Program [Member]
Class of Stock [Line Items]
Common stock, par value			$ 0.20
Aggregate Offering Price			$ 100,000
Commission of the gross sales price by share paid percentage			2.00%
Common stock, shares issued	787,547
Proceeds from issuance of common stock, net of issuance costs	$ 18,623

Industry Segment Information (I

Industry Segment Information (Industry Segment Information) (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2017		Sep. 30, 2016
Revenues:
Oil and natural gas	$ 85,470		$ 78,854		$ 256,241		$ 206,318
Contract drilling	51,619		25,819		128,059		88,786
Gas gathering and processing	51,399		48,735		150,493		132,793
Total revenues	188,488		153,408		534,793		427,897
Operating costs:
Oil and natural gas	33,911		26,014		95,873		92,691
Contract drilling	34,747		19,137		91,213		66,489
Gas gathering and processing	38,116		35,738		111,862		99,185
Total operating costs	106,774		80,889		298,948		258,365
Depreciation, depletion, and amortization	54,533		49,969		151,545		158,437
Impairments	0		49,443		0		161,563
Total expenses	161,307		180,301		450,493		578,365
General and administrative expense	(9,235)		(8,852)		(26,902)		(25,811)
Gain (loss) on disposition of assets	81		154		1,153		823
Gain (loss) on derivatives	(2,614)		6,969		21,019		(4,774)
Interest expense, net	(9,944)		(10,002)		(28,807)		(30,225)
Other	5		3		14		(11)
Income (loss) before income taxes	5,474		(38,621)		50,777		(210,466)
Oil and Natural Gas [Member]
Revenues:
Oil and natural gas	85,470		78,854		256,241		206,318
Contract drilling	0		0		0		0
Gas gathering and processing	0		0		0		0
Total revenues	85,470		78,854		256,241		206,318
Operating costs:
Oil and natural gas	35,082		27,710		99,349		98,070
Contract drilling	0		0		0		0
Gas gathering and processing	0		0		0		0
Total operating costs	35,082		27,710		99,349		98,070
Depreciation, depletion, and amortization	26,460		27,135		71,544		89,378
Impairments			49,443				161,563
Total expenses	61,542		104,288		170,893		349,011
Total operating income (loss)	23,928	[1]	(25,434)	[2]	85,348		(142,693)	[3]
General and administrative expense	0		0		0		0
Gain (loss) on disposition of assets	(1)		0		176		(324)
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	23,927		(25,434)		85,524		(143,017)
Drilling [Member]
Revenues:
Oil and natural gas	0		0		0		0
Contract drilling	55,588		25,819		137,617		88,786
Gas gathering and processing	0		0		0		0
Total revenues	55,588		25,819		137,617		88,786
Operating costs:
Oil and natural gas	0		0		0		0
Contract drilling	38,115		19,137		99,794		66,489
Gas gathering and processing	0		0		0		0
Total operating costs	38,115		19,137		99,794		66,489
Depreciation, depletion, and amortization	15,280		11,318		41,896		34,431
Impairments			0				0
Total expenses	53,395		30,455		141,690		100,920
Total operating income (loss)	2,193	[1]	(4,636)	[2]	(4,073)	[4]	(12,134)	[3]
General and administrative expense	0		0		0		0
Gain (loss) on disposition of assets	68		151		106		1,467
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	2,261		(4,485)		(3,967)		(10,667)
Mid-Stream [Member]
Revenues:
Oil and natural gas	0		0		0		0
Contract drilling	0		0		0		0
Gas gathering and processing	69,057		63,090		198,632		168,668
Total revenues	69,057		63,090		198,632		168,668
Operating costs:
Oil and natural gas	0		0		0		0
Contract drilling	0		0		0		0
Gas gathering and processing	54,602		48,397		156,525		129,681
Total operating costs	54,602		48,397		156,525		129,681
Depreciation, depletion, and amortization	10,880		11,436		32,547		34,410
Impairments			0				0
Total expenses	65,482		59,833		189,072		164,091
Total operating income (loss)	3,575	[1]	3,257	[2]	9,560	[4]	4,577	[3]
General and administrative expense	0		0		0		0
Gain (loss) on disposition of assets	14		0		58		(302)
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	3,589		3,257		9,618		4,275
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
Operating costs:
Oil and natural gas	0		0		0		0
Contract drilling	0		0		0		0
Gas gathering and processing	0		0		0		0
Total operating costs	0		0		0		0
Depreciation, depletion, and amortization	1,913		80		5,558		218
Impairments			0				0
Total expenses	1,913		80		5,558		218
Total operating income (loss)	(1,913)	[1]	(80)	[2]	(5,558)	[4]	(218)	[3]
General and administrative expense	(9,235)		(8,852)		(26,902)		(25,811)
Gain (loss) on disposition of assets	0		3		813		(18)
Gain (loss) on derivatives	(2,614)		6,969		21,019		(4,774)
Interest expense, net	(9,944)		(10,002)		(28,807)		(30,225)
Other	5		3		14		(11)
Income (loss) before income taxes	(23,701)		(11,959)		(39,421)		(61,057)
Eliminations [Member]
Revenues:
Oil and natural gas	0		0		0		0
Contract drilling	(3,969)		0		(9,558)		0
Gas gathering and processing	(17,658)		(14,355)		(48,139)		(35,875)
Total revenues	(21,627)		(14,355)		(57,697)		(35,875)
Operating costs:
Oil and natural gas	(1,171)		(1,696)		(3,476)		(5,379)
Contract drilling	(3,368)		0		(8,581)		0
Gas gathering and processing	(16,486)		(12,659)		(44,663)		(30,496)
Total operating costs	(21,025)		(14,355)		(56,720)		(35,875)
Depreciation, depletion, and amortization	0		0		0		0
Impairments			0				0
Total expenses	(21,025)		(14,355)		(56,720)		(35,875)
Total operating income (loss)	(602)	[1]	0	[2]	(977)	[4]	0	[3]
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	$ (602)		$ 0		$ (977)		$ 0
[1]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, 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 on disposition of assets, gain 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, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.