Unit (UNTC) 10-Q4 May 172017 Q1 Quarterly reportFinancial data

Company Profile

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
Document And Entity Information - shares	Mar. 31, 2017	Apr. 21, 2017
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
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		52,823,702

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 8,470,000	$ 893,000
Accounts receivable, net of allowance for doubtful accounts of $3,773 at both March 31, 2017 and December 31, 2016, respectively	81,752,000	83,954,000
Materials and supplies	3,267,000	3,340,000
Current income tax receivable	106,000	99,000
Current deferred tax asset (Note 8)	0	25,211,000
Prepaid expenses and other	7,328,000	7,699,000
Total current assets	100,923,000	121,196,000
Oil and natural gas properties on the full cost method:
Proved properties	5,461,119,000	5,446,305,000
Unproved properties not being amortized	328,266,000	314,867,000
Drilling equipment	1,572,335,000	1,565,268,000
Gas gathering and processing equipment	707,786,000	705,859,000
Saltwater disposal systems	60,746,000	60,638,000
Corporate land and building	59,070,000	59,066,000
Transportation equipment	29,562,000	32,842,000
Other	50,610,000	48,590,000
Property, plant, and equipment, gross	8,269,494,000	8,233,435,000
Less accumulated depreciation, depletion, amortization, and impairment	5,996,098,000	5,952,330,000
Net property and equipment	2,273,396,000	2,281,105,000
Goodwill	62,808,000	62,808,000
Non-current derivative asset (Note 10)	0	377,000
Other assets	15,423,000	13,817,000
Total assets	2,452,550,000	2,479,303,000
Current liabilities:
Accounts payable	75,158,000	88,793,000
Accrued liabilities (Note 5)	46,412,000	39,651,000
Current derivative liability (Note 10)	5,604,000	21,564,000
Current portion of other long-term liabilities (Note 6)	15,045,000	14,907,000
Total current liabilities	142,219,000	164,915,000
Long-term debt less debt issuance costs (Note 6)	790,653,000	800,917,000
Non-current derivative liability (Note 10)	108,000	415,000
Other long-term liabilities (Note 6)	101,877,000	103,064,000
Deferred income taxes (Note 8)	204,647,000	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, 52,018,042 and 51,494,318 shares issued as of March 31, 2017 and December 31, 2016, respectively	10,111,000	10,016,000
Capital in excess of par value	505,452,000	502,500,000
Retained earnings	697,483,000	681,554,000
Total shareholders' equity	1,213,046,000	1,194,070,000
Total liabilities and shareholders' equity	$ 2,452,550,000	$ 2,479,303,000

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 3,773	$ 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	52,018,042	51,494,318

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues:
Oil and natural gas	$ 87,598	$ 58,274
Contract drilling	37,185	38,710
Gas gathering and processing	50,941	39,200
Total revenues	175,724	136,184
Operating costs:
Oil and natural gas	29,204	33,346
Contract drilling	29,227	28,098
Gas gathering and processing	37,704	31,066
Total operating costs	96,135	92,510
Depreciation, depletion, and amortization	46,932	55,590
Impairments	0	37,829
General and administrative	8,954	8,611
Gain on disposition of assets	(824)	(192)
Total operating expenses	151,197	194,348
Income (loss) from operations	24,527	(58,164)
Other income (expense):
Interest, net	(9,396)	(9,617)
Gain on derivatives	14,731	10,929
Other	3	(15)
Total other income (expense)	5,338	1,297
Income (loss) before income taxes	29,865	(56,867)
Income tax expense (benefit):
Deferred	13,936	(15,718)
Total income taxes	13,936	(15,718)
Net income (loss)	$ 15,929	$ (41,149)
Net income (loss) per common share:
Basic	$ 0.32	$ (0.83)
Diluted	$ 0.31	$ (0.83)

Condensed Consolidated Stateme5

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING ACTIVITIES:
Net income (loss)	$ 15,929	$ (41,149)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	46,932	55,590
Impairments (Note 2)	0	37,829
Amortization of debt issuance cost and debt discount	536	526
Gain on derivatives	(14,731)	(10,929)
Cash (payments) receipts on derivatives settled	(1,159)	7,140
Deferred tax expense (benefit)	13,936	(15,718)
Gain on disposition of assets	(824)	(469)
Employee stock compensation plans	3,704	4,798
Other, net	626	(1,269)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(1,900)	10,003
Accounts payable	(7,735)	11,013
Material and supplies	73	262
Accrued liabilities	9,832	10,702
Other, net	433	2,384
Net cash provided by operating activities	65,652	70,713
INVESTING ACTIVITIES:
Capital expenditures	(37,636)	(76,035)
Producing properties and other acquisitions	(7,508)	0
Proceeds from disposition of assets	16,116	38,380
Other	0	169
Net cash used in investing activities	(29,028)	(37,486)
FINANCING ACTIVITIES:
Borrowings under credit agreement	49,700	75,000
Payments under credit agreement	(60,500)	(95,800)
Payments on capitalized leases	(946)	(910)
Tax (benefit) expense from stock compensation	0	(376)
Book overdrafts	(17,301)	(11,237)
Net cash used in financing activities	(29,047)	(33,323)
Net increase (decrease) in cash and cash equivalents	7,577	(96)
Cash and cash equivalents, beginning of period	893	835
Cash and cash equivalents, end of period	8,470	739
Cash paid during the year for:
Interest paid (net of capitalized)	(2,389)	(2,024)
Income taxes	0	0
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(11,401)	19,685
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	$ 912	$ 28,417

Basis Of Preparation And Presen

Basis Of Preparation And Presentation	3 Months Ended
Basis Of Preparation And Presentation	Mar. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis Of Preparation And Presentation	BASIS OF PREPARATION AND PRESENTATION The accompanying unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 28, 2017, for the year ended December 31, 2016 . In the opinion of our management, the accompanying unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state the following: • Balance Sheets at March 31, 2017 and December 31, 2016 ; • Statements of Operations for the three months ended March 31, 2017 and 2016 ; and • Statements of Cash Flows for the three months ended March 31, 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 accompanying notes. Actual results may differ from those estimates. Results for the three months ended March 31, 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 accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. There was no impact to consolidated net income (loss) or shareholders' equity.

Oil and Natural Gas Properties

Oil and Natural Gas Properties	3 Months Ended
Oil and Natural Gas Properties	Mar. 31, 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. During the first quarter of 2016, we had a non-cash ceiling test write-down of $37.8 million pre-tax ( $23.5 million , net of tax). We did no t have a non-cash ceiling test write-down for the first quarter of 2017.

Divestitures

Divestitures	3 Months Ended
Divestitures	Mar. 31, 2017
Property, Plant and Equipment Impairment or Disposal [Abstract]
Divestitures	DIVESTITURES Oil and Natural Gas We sold non-core oil and natural gas assets, net of related expenses, for $14.8 million during the first three months of 2017, compared to $37.4 million during the first three 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	3 Months Ended
Earnings (Loss) Per Share	Mar. 31, 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 March 31, 2017 Basic earnings per common share $ 15,929 50,293 $ 0.32 Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) — 568 (0.01 ) Diluted earnings per common share $ 15,929 50,861 $ 0.31 For the three months ended March 31, 2016 Basic loss per common share $ (41,149 ) 49,880 $ (0.83 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (41,149 ) 49,880 $ (0.83 ) Due to the net loss for the three months ended March 31, 2016, approximately 235,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the loss per share 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 March 31, 2017 2016 Stock options and SARs 199,755 261,270 Average exercise price $ 48.79 $ 50.34

Accrued Liabilities

Accrued Liabilities	3 Months Ended
Accrued Liabilities	Mar. 31, 2017
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES Accrued liabilities consisted of: March 31, December 31, (In thousands) Interest payable $ 17,360 $ 6,524 Lease operating expenses 10,627 10,075 Employee costs 8,562 15,394 Taxes 4,461 2,219 Third-party credits 2,458 2,998 Other 2,944 2,441 Total accrued liabilities $ 46,412 $ 39,651

Long-Term Debt And Other Long-T

Long-Term Debt And Other Long-Term Liabilities	3 Months Ended
Long-Term Debt And Other Long-Term Liabilities	Mar. 31, 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 consisted of the following as of the dates indicated: March 31, December 31, (In thousands) Credit agreement with an average interest rate of 2.9% and 2.8% at March 31, 2017 and December 31, 2016, respectively $ 150,000 $ 160,800 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount 800,000 810,800 Less: unamortized discount (2,665 ) (2,804 ) Less: debt issuance costs, net (6,682 ) (7,079 ) Total long-term debt $ 790,653 $ 800,917 Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) which 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 elected commitment amount is $475.0 million . Our borrowing base is $475.0 million . We are charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. With the new amendment, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8% ) total value of our oil and gas properties and (b) 100% of our ownership interest in our midstream affiliate, Superior Pipeline Company, L.L.C. The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The April 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 sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00% . Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At March 31, 2017 , we had $150.0 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 March 31, 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 will mature on May 15, 2021 . In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost over the life of the Notes. The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for the issuance of the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture. Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise. We may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of March 31, 2017 . Other Long-Term Liabilities Other long-term liabilities consisted of the following: March 31, December 31, (In thousands) Asset retirement obligation (ARO) liability $ 70,043 $ 70,170 Capital lease obligations 18,008 18,918 Workers’ compensation 15,066 15,163 Separation benefit plans 5,149 4,943 Deferred compensation plan 4,924 4,578 Gas balancing liability 3,322 3,789 Other 410 410 116,922 117,971 Less current portion 15,045 14,907 Total other long-term liabilities $ 101,877 $ 103,064 Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve month periods beginning April 1, 2017 (and through 2022) are $15.0 million , $44.7 million , $8.9 million , $160.6 million , and $653.0 million , respectively. Capital Leases In 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.7 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $14.3 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 . These capital leases are discounted using annual rates of 4.00% . Total maintenance and interest remaining related to these leases are $7.2 million and $1.7 million , respectively, at March 31, 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 March 31, 2017 : Amount Beginning April 1, (In thousands) 2017 $ 6,168 2018 6,168 2019 6,168 2020 7,815 2021 579 Total future payments 26,898 Less payments related to: Maintenance 7,213 Interest 1,677 Present value of future minimum payments $ 18,008

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
Asset Retirement Obligations	Mar. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to the plugging costs associated with our oil and gas wells. The following table shows certain information about our AROs for the periods indicated: Three Months Ended March 31, 2017 2016 (In thousands) ARO liability, January 1: $ 70,170 $ 98,297 Accretion of discount 785 879 Liability incurred 658 90 Liability settled (630 ) (375 ) Liability sold (1) (432 ) (9,950 ) Revision of estimates (2) (508 ) (18,182 ) ARO liability, March 31: 70,043 70,759 Less current portion 3,243 3,499 Total long-term ARO $ 66,800 $ 67,260 _______________________ (1) We sold our interest in a number of non-core wells to unaffiliated third-parties during the first three 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	3 Months Ended
New Accounting Pronouncements	Mar. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the subsequent measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. This amendment will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe this ASU will have a material impact on our financial statements. Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have on our financial statements. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe this ASU will have a material impact on our financial statements. Leases. The FASB has issued ASU 2016-02. Under the new guidance, lessees will be required to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact these amendments will have on our financial statements. Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This guidance affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASU rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities— Oil and Gas, effective on the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We will adopt these amendments effective January 1, 2018. We have begun the identification and impact assessment of revenue within the scope of the guidance and are utilizing a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts. While we have not identified any material differences in the amount and timing of revenue recognition to date, our evaluation is not complete, and we have not reached a conclusion on the overall impacts of adopting Topic 606. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative effect adjustment to retained earnings at the date of adoption. We currently believe we will adopt the cumulative effect method. Adopted Standards Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require current deferred tax assets to be combined with noncurrent deferred tax assets. We 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 are 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	3 Months Ended
Stock-Based Compensation	Mar. 31, 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 March 31, 2017 2016 (In millions) Recognized stock compensation expense $ 2.6 $ 3.3 Capitalized stock compensation cost for our oil and natural gas properties 0.4 0.8 Tax benefit on stock based compensation 1.0 1.3 The remaining unrecognized compensation cost related to unvested awards at March 31, 2017 is approximately $19.8 million , of which $2.2 million is anticipated to be capitalized. The weighted average period of time 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. As of the date of this report, a total of 4,500,000 shares of the company's common stock was 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 month periods ending March 31, 2017 or 2016 . The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the three month periods ending March 31, 2017 and 2016: Three Months Ended Three Months Ended March 31, 2017 March 31, 2016 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees 461,799 152,373 486,578 152,373 Non-employee directors — — — — 461,799 152,373 486,578 152,373 Estimated fair value (in millions): (1) Employees $ 11.4 $ 4.0 $ 2.6 $ 0.8 Non-employee directors — — — — $ 11.4 $ 4.0 $ 2.6 $ 0.8 Percentage of shares granted expected to be distributed: Employees 94 % 105 % 94 % 52 % Non-employee directors N/A N/A N/A 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 three months of 2017 and 2016 are being recognized over a three year vesting period. During the first quarter of 2017 and 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200% . Based on a probability assessment of the selected performance criteria at March 31, 2017, the participants are estimated to receive 111% of the 2017, 132% of the 2016, and 27% of the 2015 performance based shares. The CFTA performance measurement at March 31, 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 three months of 2017 was $1.0 million .

Derivatives

Derivatives	3 Months Ended
Derivatives	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	DERIVATIVES Commodity Derivatives We have entered into various types of derivative transactions covering some of our projected natural gas 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 March 31, 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 on derivatives in our Unaudited Condensed Consolidated Statements of Operations. At March 31, 2017 , we had the following derivatives outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Apr’17 – 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) Apr’17 – Oct'17 Natural gas – collar 20,000 MMBtu/day $2.88 - $3.10 IF – NYMEX (HH) Apr'17 – 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) Apr’17 – Dec'17 Crude oil – three-way collar 3,750 Bbl/day $49.79 - $39.58 - $60.98 WTI – NYMEX 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 March 31, December 31, (In thousands) Commodity derivatives: Current Current derivative asset $ — $ — Long-term Non-current derivative asset — 377 Total derivative assets $ — $ 377 Derivative Liabilities Fair Value Balance Sheet Location March 31, December 31, (In thousands) Commodity derivatives: Current Current derivative liability $ 5,604 $ 21,564 Long-term Non-current derivative liability 108 415 Total derivative liabilities $ 5,712 $ 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 March 31 : Derivatives Instruments Location of Gain Recognized in Income on Derivative Amount of Gain Recognized in Income on Derivative 2017 2016 (In thousands) Commodity derivatives Gain on derivatives (1) $ 14,731 $ 10,929 Total $ 14,731 $ 10,929 _______________________ (1) Amounts settled during the 2017 and 2016 periods include a loss of $1.2 million and a gain of $7.1 million , respectively.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
Fair Value Measurements	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows: • Level 1—unadjusted quoted prices in active markets for identical assets and liabilities. • Level 2—significant observable pricing inputs other than quoted prices included within level 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data. • Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal data. The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. The following tables set forth our recurring fair value measurements: March 31, 2017 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 778 $ 1,779 $ (2,557 ) $ — Liabilities (5,888 ) (2,381 ) 2,557 (5,712 ) $ (5,110 ) $ (602 ) $ — $ (5,712 ) December 31, 2016 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 of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2017 . We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. Level 2 Fair Value Measurements Commodity Derivatives . We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index. Level 3 Fair Value Measurements Commodity Derivatives . The fair values of our natural gas and crude oil collars and three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements. The following table is a reconciliation of our level 3 fair value measurements: Net Derivatives Three Months Ended March 31, 2017 2016 (In thousands) Beginning of period $ (7,122 ) $ 9,094 Total gains or losses (realized and unrealized): Included in earnings (1) 5,903 5,988 Settlements 617 (5,099 ) End of period $ (602 ) $ 9,983 Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period $ 6,520 $ 889 _______________________ (1) Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain on derivatives. The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2017 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil three-way collars $ 1,378 Discounted cash flow Forward commodity price curve ($1.75) - $3.85 Natural gas collar $ (1,136 ) Discounted cash flow Forward commodity price curve ($0.57) - $0.15 Natural gas three-way collars $ (844 ) Discounted cash flow Forward commodity price curve ($0.54) - $0.55 _______________________ (1) The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period. Based on our valuation at March 31, 2017 , we determined that risk of non-performance by our counterparties was immaterial. Fair Value of Other Financial Instruments The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. At March 31, 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 also considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at March 31, 2017 and December 31, 2016 was $150.0 million and $160.8 million , respectively. This debt would be classified as Level 2. The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016 were $640.7 million and $640.1 million , respectively. We estimate the fair value of the Notes using quoted marked prices at March 31, 2017 and December 31, 2016 was $640.3 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 C

Commitments and Contingencies Commitments and Contingencies	3 Months Ended
Commitments and Contingencies Commitments and Contingencies	Mar. 31, 2017
Commitments and Contingencies [Abstract]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $2.7 million , $0.8 million , $0.2 million , $0.2 million , and $0.1 million in twelve month periods beginning April 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $2.1 million and $3.3 million for the first quarter of 2017 and 2016, respectively. In 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the five successive twelve month periods beginning April 1, 2017 (and through the end of 2021) are $6.2 million , $6.2 million , $6.2 million , $7.8 million , and $0.6 million . Total maintenance and interest remaining related to these leases are $7.2 million and $1.7 million , respectively at March 31, 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 fair market value at that time. The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20% of the units outstanding. We did not have any repurchases in the first quarter of 2017 or 2016. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well. For the next twelve months, we have committed to purchase approximately $4.2 million of new drilling rig components. We have also committed to paying $1.3 million for Enterprise Resource Planning software over the next year.

Industry Segment Information

Industry Segment Information	3 Months Ended
Industry Segment Information	Mar. 31, 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 March 31, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 87,598 $ — $ — $ — $ — $ 87,598 Contract drilling — 37,185 — — — 37,185 Gas gathering and processing — — 66,464 — (15,523 ) 50,941 Total revenues 87,598 37,185 66,464 — (15,523 ) 175,724 Expenses: Operating costs: Oil and natural gas 30,326 — — — (1,122 ) 29,204 Contract drilling — 29,227 — — — 29,227 Gas gathering and processing — — 52,105 — (14,401 ) 37,704 Total operating costs 30,326 29,227 52,105 — (15,523 ) 96,135 Depreciation, depletion, and amortization 21,526 12,847 10,818 1,741 — 46,932 Total expenses 51,852 42,074 62,923 1,741 (15,523 ) 143,067 Total operating income (loss) (1) 35,746 (4,889 ) 3,541 (1,741 ) — General and administrative expense — — — (8,954 ) — (8,954 ) Gain on disposition of assets 9 7 — 808 — 824 Gain on derivatives — — — 14,731 — 14,731 Interest expense, net — — — (9,396 ) — (9,396 ) Other — — — 3 — 3 Income (loss) before income taxes $ 35,755 $ (4,882 ) $ 3,541 $ (4,549 ) $ — $ 29,865 _______________________ (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. Three Months Ended March 31, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 58,274 $ — $ — $ — $ — $ 58,274 Contract drilling — 38,710 — — — 38,710 Gas gathering and processing — — 49,045 — (9,845 ) 39,200 Total revenues 58,274 38,710 49,045 — (9,845 ) 136,184 Expenses: Operating costs: Oil and natural gas 34,804 — — — (1,458 ) 33,346 Contract drilling — 28,098 — — — 28,098 Gas gathering and processing — — 39,453 — (8,387 ) 31,066 Total operating costs 34,804 28,098 39,453 — (9,845 ) 92,510 Depreciation, depletion, and amortization 31,832 12,195 11,459 104 — 55,590 Impairments 37,829 — — — — 37,829 Total expenses 104,465 40,293 50,912 104 (9,845 ) 185,929 Total operating loss (1) (46,191 ) (1,583 ) (1,867 ) (104 ) — General and administrative expense — — — (8,611 ) — (8,611 ) Gain (loss) on disposition of assets — 494 (302 ) — — 192 Gain on derivatives — — — 10,929 — 10,929 Interest expense, net — — — (9,617 ) — (9,617 ) Other — — — (15 ) — (15 ) Loss before income taxes $ (46,191 ) $ (1,089 ) $ (2,169 ) $ (7,418 ) $ — $ (56,867 ) _______________________ (1) Operating loss is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events	3 Months Ended
Subsequent Events Subsequent Events	Mar. 31, 2017
Subsequent Events [Abstract]
Subsequent Events [Text Block]	SUBSEQUENT EVENTS On April 3, 2017, we completed the acquisition of certain oil and natural gas assets from an unrelated third party. The acquisition includes approximately 47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The purchase price was approximately $57.0 million in cash plus the conveyance of 180 net leasehold acres we held in McClain County, Oklahoma. This acquisition is subject to certain post-closing adjustments. The effective date of this acquisition is January 1, 2017 . On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million . We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes. Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended (the Securities Act), 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 April 21, 2017, we sold 770,660 shares of our common stock resulting in net proceeds of approximately $18.3 million .

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	3 Months Ended
Earnings (Loss) Per Share (Tables)	Mar. 31, 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 March 31, 2017 Basic earnings per common share $ 15,929 50,293 $ 0.32 Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) — 568 (0.01 ) Diluted earnings per common share $ 15,929 50,861 $ 0.31 For the three months ended March 31, 2016 Basic loss per common share $ (41,149 ) 49,880 $ (0.83 ) Effect of dilutive stock options, restricted stock, and SARs — — — Diluted loss per common share $ (41,149 ) 49,880 $ (0.83 )
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 March 31, 2017 2016 Stock options and SARs 199,755 261,270 Average exercise price $ 48.79 $ 50.34

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	3 Months Ended
Accrued Liabilities (Tables)	Mar. 31, 2017
Accrued Liabilities, Current [Abstract]
Accrued Liabilities	Accrued liabilities consisted of: March 31, December 31, (In thousands) Interest payable $ 17,360 $ 6,524 Lease operating expenses 10,627 10,075 Employee costs 8,562 15,394 Taxes 4,461 2,219 Third-party credits 2,458 2,998 Other 2,944 2,441 Total accrued liabilities $ 46,412 $ 39,651

Long-Term Debt And Other Long22

Long-Term Debt And Other Long-Term Liabilities (Tables)	3 Months Ended
Long-Term Debt And Other Long-Term Liabilities (Tables)	Mar. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Our long-term debt consisted of the following as of the dates indicated: March 31, December 31, (In thousands) Credit agreement with an average interest rate of 2.9% and 2.8% at March 31, 2017 and December 31, 2016, respectively $ 150,000 $ 160,800 6.625% senior subordinated notes due 2021 650,000 650,000 Total principal amount 800,000 810,800 Less: unamortized discount (2,665 ) (2,804 ) Less: debt issuance costs, net (6,682 ) (7,079 ) Total long-term debt $ 790,653 $ 800,917
Other Long-Term Liabilities	Other long-term liabilities consisted of the following: March 31, December 31, (In thousands) Asset retirement obligation (ARO) liability $ 70,043 $ 70,170 Capital lease obligations 18,008 18,918 Workers’ compensation 15,066 15,163 Separation benefit plans 5,149 4,943 Deferred compensation plan 4,924 4,578 Gas balancing liability 3,322 3,789 Other 410 410 116,922 117,971 Less current portion 15,045 14,907 Total other long-term liabilities $ 101,877 $ 103,064
Capital leases	Future payments required under the capital leases at March 31, 2017 : Amount Beginning April 1, (In thousands) 2017 $ 6,168 2018 6,168 2019 6,168 2020 7,815 2021 579 Total future payments 26,898 Less payments related to: Maintenance 7,213 Interest 1,677 Present value of future minimum payments $ 18,008

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
Asset Retirement Obligations (Tables)	Mar. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Asset Retirement Obligations	The following table shows certain information about our AROs for the periods indicated: Three Months Ended March 31, 2017 2016 (In thousands) ARO liability, January 1: $ 70,170 $ 98,297 Accretion of discount 785 879 Liability incurred 658 90 Liability settled (630 ) (375 ) Liability sold (1) (432 ) (9,950 ) Revision of estimates (2) (508 ) (18,182 ) ARO liability, March 31: 70,043 70,759 Less current portion 3,243 3,499 Total long-term ARO $ 66,800 $ 67,260 _______________________ (1) We sold our interest in a number of non-core wells to unaffiliated third-parties during the first three 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)	3 Months Ended
Stock-Based Compensation (Tables)	Mar. 31, 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 March 31, 2017 2016 (In millions) Recognized stock compensation expense $ 2.6 $ 3.3 Capitalized stock compensation cost for our oil and natural gas properties 0.4 0.8 Tax benefit on stock based compensation 1.0 1.3
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 three month periods ending March 31, 2017 and 2016: Three Months Ended Three Months Ended March 31, 2017 March 31, 2016 Time Vested Performance Vested Time Vested Performance Vested Shares granted: Employees 461,799 152,373 486,578 152,373 Non-employee directors — — — — 461,799 152,373 486,578 152,373 Estimated fair value (in millions): (1) Employees $ 11.4 $ 4.0 $ 2.6 $ 0.8 Non-employee directors — — — — $ 11.4 $ 4.0 $ 2.6 $ 0.8 Percentage of shares granted expected to be distributed: Employees 94 % 105 % 94 % 52 % Non-employee directors N/A N/A N/A 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)	3 Months Ended
Derivatives (Tables)	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives outstanding	At March 31, 2017 , we had the following derivatives outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market Apr’17 – 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) Apr’17 – Oct'17 Natural gas – collar 20,000 MMBtu/day $2.88 - $3.10 IF – NYMEX (HH) Apr'17 – 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) Apr’17 – Dec'17 Crude oil – three-way collar 3,750 Bbl/day $49.79 - $39.58 - $60.98 WTI – NYMEX
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 March 31, December 31, (In thousands) Commodity derivatives: Current Current derivative asset $ — $ — Long-term Non-current derivative asset — 377 Total derivative assets $ — $ 377 Derivative Liabilities Fair Value Balance Sheet Location March 31, December 31, (In thousands) Commodity derivatives: Current Current derivative liability $ 5,604 $ 21,564 Long-term Non-current derivative liability 108 415 Total derivative liabilities $ 5,712 $ 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 March 31 : Derivatives Instruments Location of Gain Recognized in Income on Derivative Amount of Gain Recognized in Income on Derivative 2017 2016 (In thousands) Commodity derivatives Gain on derivatives (1) $ 14,731 $ 10,929 Total $ 14,731 $ 10,929 _______________________ (1) Amounts settled during the 2017 and 2016 periods include a loss of $1.2 million and a gain of $7.1 million , respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
Fair Value Measurements (Tables)	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Recurring Fair Value Measurements	The following tables set forth our recurring fair value measurements: March 31, 2017 Level 2 Level 3 Effect of Netting Net Amounts Presented (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 778 $ 1,779 $ (2,557 ) $ — Liabilities (5,888 ) (2,381 ) 2,557 (5,712 ) $ (5,110 ) $ (602 ) $ — $ (5,712 ) December 31, 2016 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 March 31, 2017 2016 (In thousands) Beginning of period $ (7,122 ) $ 9,094 Total gains or losses (realized and unrealized): Included in earnings (1) 5,903 5,988 Settlements 617 (5,099 ) End of period $ (602 ) $ 9,983 Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period $ 6,520 $ 889 _______________________ (1) Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain on derivatives.
Schedule Of Quantitative Information About Unobservable Inputs	The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2017 : Commodity (1) Fair Value Valuation Technique Unobservable Input Range (In thousands) Oil three-way collars $ 1,378 Discounted cash flow Forward commodity price curve ($1.75) - $3.85 Natural gas collar $ (1,136 ) Discounted cash flow Forward commodity price curve ($0.57) - $0.15 Natural gas three-way collars $ (844 ) Discounted cash flow Forward commodity price curve ($0.54) - $0.55 _______________________ (1) The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Industry Segment Information (T

Industry Segment Information (Tables)	3 Months Ended
Industry Segment Information (Tables)	Mar. 31, 2017
Segment Reporting [Abstract]
Industry segment information	The following tables provide certain information about the operations of each of our segments: Three Months Ended March 31, 2017 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 87,598 $ — $ — $ — $ — $ 87,598 Contract drilling — 37,185 — — — 37,185 Gas gathering and processing — — 66,464 — (15,523 ) 50,941 Total revenues 87,598 37,185 66,464 — (15,523 ) 175,724 Expenses: Operating costs: Oil and natural gas 30,326 — — — (1,122 ) 29,204 Contract drilling — 29,227 — — — 29,227 Gas gathering and processing — — 52,105 — (14,401 ) 37,704 Total operating costs 30,326 29,227 52,105 — (15,523 ) 96,135 Depreciation, depletion, and amortization 21,526 12,847 10,818 1,741 — 46,932 Total expenses 51,852 42,074 62,923 1,741 (15,523 ) 143,067 Total operating income (loss) (1) 35,746 (4,889 ) 3,541 (1,741 ) — General and administrative expense — — — (8,954 ) — (8,954 ) Gain on disposition of assets 9 7 — 808 — 824 Gain on derivatives — — — 14,731 — 14,731 Interest expense, net — — — (9,396 ) — (9,396 ) Other — — — 3 — 3 Income (loss) before income taxes $ 35,755 $ (4,882 ) $ 3,541 $ (4,549 ) $ — $ 29,865 _______________________ (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. Three Months Ended March 31, 2016 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 58,274 $ — $ — $ — $ — $ 58,274 Contract drilling — 38,710 — — — 38,710 Gas gathering and processing — — 49,045 — (9,845 ) 39,200 Total revenues 58,274 38,710 49,045 — (9,845 ) 136,184 Expenses: Operating costs: Oil and natural gas 34,804 — — — (1,458 ) 33,346 Contract drilling — 28,098 — — — 28,098 Gas gathering and processing — — 39,453 — (8,387 ) 31,066 Total operating costs 34,804 28,098 39,453 — (9,845 ) 92,510 Depreciation, depletion, and amortization 31,832 12,195 11,459 104 — 55,590 Impairments 37,829 — — — — 37,829 Total expenses 104,465 40,293 50,912 104 (9,845 ) 185,929 Total operating loss (1) (46,191 ) (1,583 ) (1,867 ) (104 ) — General and administrative expense — — — (8,611 ) — (8,611 ) Gain (loss) on disposition of assets — 494 (302 ) — — 192 Gain on derivatives — — — 10,929 — 10,929 Interest expense, net — — — (9,617 ) — (9,617 ) Other — — — (15 ) — (15 ) Loss before income taxes $ (46,191 ) $ (1,089 ) $ (2,169 ) $ (7,418 ) $ — $ (56,867 ) _______________________ (1) Operating loss is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes.

Oil and Natural Gas (Narrative)

Oil and Natural Gas (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
Future discounted net cash flows discounted	10.00%
Impairment of oil and natural gas properties	$ 0	$ 37.8
Non-cash ceiling test write-down net of tax		$ 23.5

Divestitures (Narrative) (Detai

Divestitures (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
Divestitures (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Mar. 31, 2016
Property, Plant and Equipment Impairment or Disposal [Abstract]
Proceeds from non-core oil and natural gas asset sales, net of related expenses	$ 14.8	$ 37.4

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
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings (loss) of basic earnings (loss) per common share	$ 15,929	$ (41,149)
Income of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0	0
Earnings (loss) of diluted loss per common share	$ 15,929	$ (41,149)
Weighted shares of basic earnings (loss) per common share	50,293	49,880
Weighted shares of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	568	0
Weighted shares of diluted earnings (loss) per common share	50,861	49,880
Per-Share amount of basic earnings (loss) per common share	$ 0.32	$ (0.83)
Per-Share amount of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	(0.01)	0
Per-Share amount of diluted earnings (loss) per common share	$ 0.31	$ (0.83)

Earnings (Loss) Per Share (Sc31

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
	Mar. 31, 2017	Mar. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings (Loss) Per Share [Line Items]
Antidilutive securities excluded from computation of earnings (loss) per share	199,755	261,270
Average exercise price	$ 48.79	$ 50.34

Earnings (Loss) Per Share (Narr

Earnings (Loss) Per Share (Narrative) (Details)	3 Months Ended
Earnings (Loss) Per Share (Narrative) (Details)	Mar. 31, 2016shares
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	235,000

Accrued Liabilities (Accrued Li

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Accrued Liabilities, Current [Abstract]
Interest payable	$ 17,360	$ 6,524
Lease operating expenses	10,627	10,075
Employee costs	8,562	15,394
Taxes	4,461	2,219
Third-party credits	2,458	2,998
Other	2,944	2,441
Total accrued liabilities	$ 46,412	$ 39,651

Long-Term Debt And Other Long34

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Credit agreement with an average interest rate of 2.9% and 2.8% at March 31, 2017 and December 31, 2016, respectively	$ 150,000	$ 160,800
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	800,000	810,800
Less: unamortized discount	(2,665)	(2,804)
Less: debt issuance costs, net	(6,682)	(7,079)
Total long-term debt	$ 790,653	$ 800,917
Revolving credit facility interest rate	2.90%	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 Long35

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Asset retirement obligation (ARO) liability	$ 70,043	$ 70,170	$ 70,759	$ 98,297
Capital lease obligations	18,008	18,918
Workers' compensation	15,066	15,163
Separation benefit plans	5,149	4,943
Deferred compensation plan	4,924	4,578
Gas balancing liability	3,322	3,789
Other	410	410
Other liabilities	116,922	117,971
Less current portion	15,045	14,907
Total other long-term liabilities	$ 101,877	$ 103,064

Long-Term Debt And Other Long36

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt And Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Beginning April 1,
2,017	$ 6,168
2,018	6,168
2,019	6,168
2,020	7,815
2,021	579
Total future payments	26,898
Less payments related to:
Maintenance	7,213
Interest	1,677
Present value of future minimum payments	$ 18,008	$ 18,918

Long-Term Debt And Other Long37

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 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	$ 150,000	$ 160,800
Current ratio of credit facility	1 to 1
Aggregate principal amount	$ 650,000	$ 650,000
Interest percentage of senior subordinated notes	6.625%
Debt instrument maturity date	May 15, 2021
Original debt issuance fees	$ 14,700
Senior notes repurchase price in percentage	101.00%
Estimated principal payments in year 1	$ 15,000
Estimated principal payments in year 2	44,700
Estimated principal payments in year 3	8,900
Estimated principal payments in year 4	160,600
Estimated principal payments in year 5	$ 653,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,700
Capital Lease Obligations, Noncurrent	$ 14,300
Discount rate capital leases	4.00%
Maintenance	$ 7,213
Interest	1,677
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		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
ARO liability, January 1:		$ 70,170	$ 98,297
Accretion of discount		785	879
Liability incurred		658	90
Liability settled		(630)	(375)
Liability sold	[1]	(432)	(9,950)
Revision of estimates	[2]	(508)	(18,182)
ARO liability, March 31:		70,043	70,759
Less current portion		3,243	3,499
Total long-term ARO		$ 66,800	$ 67,260

[1]	We sold our interest in a number of non-core wells to unaffiliated third-parties during the first three 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
	Mar. 31, 2017	Mar. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Abstract]
Recognized stock compensation expense	$ 2.6	$ 3.3
Capitalized stock compensation cost for our oil and natural gas properties	0.4	0.8
Tax benefit on stock based compensation	$ 1	$ 1.3

Stock-Based Compensation (Sched

Stock-Based Compensation (Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods) (Details) - Restricted Stock [Member] - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Time Vested [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		461,799	486,578
Estimated fair value (in millions)	[1]	$ 11.4	$ 2.6
Time Vested [Member] \| Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		461,799	486,578
Estimated fair value (in millions)	[1]	$ 11.4	$ 2.6
Percentage of shares granted expected to be distributed		94.00%	94.00%
Time Vested [Member] \| Non-employee Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		0	0
Estimated fair value (in millions)	[1]	$ 0	$ 0
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		152,373	152,373
Estimated fair value (in millions)	[1]	$ 4	$ 0.8
Performance Shares [Member] \| Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		152,373	152,373
Estimated fair value (in millions)	[1]	$ 4	$ 0.8
Percentage of shares granted expected to be distributed		105.00%	52.00%
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
	Mar. 31, 2017	Mar. 31, 2016	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 19.8
Unrecognized compensation cost, expected to be capitalized	$ 2.2
Weighted average years over which this cost will be recognized	11 months 19 days
Increase in stock compensation expense due to the restricted stock awards granted	$ 1
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	0	0
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized			4,500,000
Incentive Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized			2,000,000
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options granted	0	0
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	461,799	486,578
Performance Shares [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	152,373	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	111.00%
2016 [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	132.00%
2015 [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	27.00%

Derivatives (Schedule of Deriva

Derivatives (Schedule of Derivatives Outstanding) (Details)	3 Months Ended
Derivatives (Schedule of Derivatives Outstanding) (Details)	Mar. 31, 2017$ / UnitMMBTUbbl
Swap [Member] \| Apr'17 - 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] \| 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] \| Apr'17 - 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] \| Apr'17 - 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] \| Apr'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	2.5
Floor Price	3

Derivatives (Fair Value Of Deri

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative asset	$ 0	$ 0
Non-current derivative asset	0	377
Total derivatives assets	0	377
Current derivative liability	5,604	21,564
Non-current derivative liability	108	415
Total derivative liabilities	$ 5,712	$ 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
		Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain on derivatives		$ 14,731	$ 10,929
Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain on derivatives		14,731	10,929
Amount of gain (loss) settled during the period		(1,200)	7,100
Gain on derivatives [Member] \| Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain on derivatives	[1]	$ 14,731	$ 10,929

[1]	Amounts settled during the 2017 and 2016 periods include a loss of $1.2 million and a gain of $7.1 million, respectively.

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 0	$ 377
Derivative Liability	5,712	21,979
Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	377
Derivative Liability	5,712	21,979
Financial assets (liabilities)	(5,712)	(21,602)
Commodity Derivatives [Member] \| Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	778	878
Gross Liabilities	(5,888)	(15,358)
Financial assets (liabilities)	(5,110)	(14,480)
Commodity Derivatives [Member] \| Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	1,779	43
Gross Liabilities	(2,381)	(7,165)
Financial assets (liabilities)	(602)	(7,122)
Commodity Derivatives [Member] \| Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Effect of netting on assets	(2,557)	(544)
Effect of netting on liabilities	2,557	544
Financial assets (liabilities)	$ 0	$ 0

Fair Value Measurements (Reconc

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) - Level 3 [Member] - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Beginning of period		$ (7,122)	$ 9,094
Included in earnings	[1]	5,903	5,988
Settlements		617	(5,099)
End of period		(602)	9,983
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period		$ 6,520	$ 889

[1]	Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain on derivatives

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) - Level 3 [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)$ / Unit	[1]
Oil [Member] \| Three-way collar [Member]
Derivative fair value \| $	$ 1,378
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	(1.75)
Oil [Member] \| Three-way collar [Member] \| Maximum [Member]
Forward commodity price curve	3.85
Natural Gas [Member] \| Collar [Member]
Derivative fair value \| $	$ (1,136)
Derivatives Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward commodity price curve
Natural Gas [Member] \| Collar [Member] \| Minimum [Member]
Forward commodity price curve	(0.57)
Natural Gas [Member] \| Collar [Member] \| Maximum [Member]
Forward commodity price curve	0.15
Natural Gas [Member] \| Three-way collar [Member]
Derivative fair value \| $	$ (844)
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	(0.54)
Natural Gas [Member] \| Three-way collar [Member] \| Maximum [Member]
Forward commodity price curve	0.55

[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	Mar. 31, 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	150,000	$ 160,800
6.625% senior subordinated notes due 2021	640,700	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	$ 640,300	$ 649,900

Commitments and Contingencies49

Commitments and Contingencies Commitments and Contingencies (Narrative) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 2,700,000
Operating Leases, Future Minimum Payments, Due in Two Years	800,000
Operating Leases, Future Minimum Payments, Due in Three Years	200,000
Operating Leases, Future Minimum Payments, Due in Four Years	200,000
Operating Leases, Future Minimum Payments, Due in Five Years	100,000
Operating Leases, Rent Expense, Net	$ 2,100,000	$ 3,300,000
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	7,815,000
Capital Leases, Future Minimum Payments Due in Five Years	579,000
Maintenance	7,213,000
Interest	1,677,000
Capital leases, future minimum payments, average annual payment	$ 4,100,000
Capital lease fair market value percentage for purchase	10.00%
Repurchase Of Limited Units Outstanding Amount	$ 0	$ 0
Drilling Equipment [Member]
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	4,200,000
Corporate, Non-Segment [Member]
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 1,300,000

Industry Segment Information (I

Industry Segment Information (Industry Segment Information) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017		Mar. 31, 2016
Revenues:
Oil and natural gas	$ 87,598		$ 58,274
Contract drilling	37,185		38,710
Gas gathering and processing	50,941		39,200
Total revenues	175,724		136,184
Operating costs:
Oil and natural gas	29,204		33,346
Contract drilling	29,227		28,098
Gas gathering and processing	37,704		31,066
Operating Costs and Expenses	96,135		92,510
Depreciation, depletion, and amortization	46,932		55,590
Impairments	0		37,829
Total expenses	143,067		185,929
General and administrative expense	(8,954)		(8,611)
Gain (loss) on disposition of assets	824		192
Gain on derivatives	14,731		10,929
Interest expense, net	(9,396)		(9,617)
Other	3		(15)
Income (loss) before income taxes	29,865		(56,867)
Oil and Natural Gas [Member]
Revenues:
Oil and natural gas	87,598		58,274
Contract drilling	0		0
Gas gathering and processing	0		0
Total revenues	87,598		58,274
Operating costs:
Oil and natural gas	30,326		34,804
Contract drilling	0		0
Gas gathering and processing	0		0
Operating Costs and Expenses	30,326		34,804
Depreciation, depletion, and amortization	21,526		31,832
Impairments			37,829
Total expenses	51,852		104,465
Total operating income (loss)	35,746	[1]	(46,191)	[2]
General and administrative expense	0		0
Gain (loss) on disposition of assets	9		0
Gain on derivatives	0		0
Interest expense, net	0		0
Other	0		0
Income (loss) before income taxes	35,755		(46,191)
Drilling [Member]
Revenues:
Oil and natural gas	0		0
Contract drilling	37,185		38,710
Gas gathering and processing	0		0
Total revenues	37,185		38,710
Operating costs:
Oil and natural gas	0		0
Contract drilling	29,227		28,098
Gas gathering and processing	0		0
Operating Costs and Expenses	29,227		28,098
Depreciation, depletion, and amortization	12,847		12,195
Impairments			0
Total expenses	42,074		40,293
Total operating income (loss)	(4,889)	[1]	(1,583)	[2]
General and administrative expense	0		0
Gain (loss) on disposition of assets	7		494
Gain on derivatives	0		0
Interest expense, net	0		0
Other	0		0
Income (loss) before income taxes	(4,882)		(1,089)
Mid-Stream [Member]
Revenues:
Oil and natural gas	0		0
Contract drilling	0		0
Gas gathering and processing	66,464		49,045
Total revenues	66,464		49,045
Operating costs:
Oil and natural gas	0		0
Contract drilling	0		0
Gas gathering and processing	52,105		39,453
Operating Costs and Expenses	52,105		39,453
Depreciation, depletion, and amortization	10,818		11,459
Impairments			0
Total expenses	62,923		50,912
Total operating income (loss)	3,541	[1]	(1,867)	[2]
General and administrative expense	0		0
Gain (loss) on disposition of assets	0		(302)
Gain on derivatives	0		0
Interest expense, net	0		0
Other	0		0
Income (loss) before income taxes	3,541		(2,169)
Other Segments [Member]
Revenues:
Oil and natural gas	0		0
Contract drilling	0		0
Gas gathering and processing	0		0
Total revenues	0		0
Operating costs:
Oil and natural gas	0		0
Contract drilling	0		0
Gas gathering and processing	0		0
Operating Costs and Expenses	0		0
Depreciation, depletion, and amortization	1,741		104
Impairments			0
Total expenses	1,741		104
Total operating income (loss)	(1,741)	[1]	(104)	[2]
General and administrative expense	(8,954)		(8,611)
Gain (loss) on disposition of assets	808		0
Gain on derivatives	14,731		10,929
Interest expense, net	(9,396)		(9,617)
Other	3		(15)
Income (loss) before income taxes	(4,549)		(7,418)
Eliminations [Member]
Revenues:
Oil and natural gas	0		0
Contract drilling	0		0
Gas gathering and processing	(15,523)		(9,845)
Total revenues	(15,523)		(9,845)
Operating costs:
Oil and natural gas	(1,122)		(1,458)
Contract drilling	0		0
Gas gathering and processing	(14,401)		(8,387)
Operating Costs and Expenses	(15,523)		(9,845)
Depreciation, depletion, and amortization	0		0
Impairments			0
Total expenses	(15,523)		(9,845)
Total operating income (loss)	0	[1]	0	[2]
General and administrative expense	0		0
Gain (loss) on disposition of assets	0		0
Gain on derivatives	0		0
Interest expense, net	0		0
Other	0		0
Income (loss) before income taxes	$ 0		$ 0

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

Subsequent Events Subsequent 51

Subsequent Events Subsequent Events (Narrative) (Details) $ / shares in Units, $ in Millions	Apr. 03, 2017USD ($)awells	Apr. 21, 2017USD ($)shares	Apr. 04, 2017USD ($)$ / shares	Mar. 31, 2017$ / sharesshares	Dec. 31, 2016$ / sharesshares
Subsequent Event [Line Items]
Common stock, par value \| $ / shares				$ 0.20	$ 0.20
Common stock, shares issued \| shares				52,018,042	51,494,318
At-the-market offering [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Common stock, par value \| $ / shares			$ 0.20
Aggregate Offering Price			$ 100
Commission of the gross sales price by share paid percentage			2.00%
Common stock, shares issued \| shares		770,660
Stock offering proceeds		$ 18.3
Acquisition [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Business Combination, Consideration Transferred	$ 57
Business Acquisition, Effective Date of Acquisition	Jan. 1, 2017
Acquisition [Member] \| Grady and Caddo Counties, Oklahoma [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Area of Land \| a	8,300
Proved developed producing wells \| wells	47
Acquisition [Member] \| McClain County, Oklahoma [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Business combination consideration non-monetary \| a	180