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Document And Entity Information - shares	3 Months Ended
Document And Entity Information - shares	Mar. 31, 2018	Apr. 20, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	0000798949
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		54,046,361

Condensed Consolidated Balance Sheets (Unaudited) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 752,000	$ 701,000
Accounts receivable, net of allowance for doubtful accounts of $2,450 at both March 31, 2018 and December 31, 2017, respectively	98,506,000	111,512,000
Materials and supplies	455,000	505,000
Current derivative asset (Note 10)	537,000	721,000
Current income tax receivable	61,000	0
Prepaid expenses and other	7,724,000	6,233,000
Total current assets	108,035,000	119,672,000
Oil and natural gas properties on the full cost method:
Proved properties	5,762,069,000	5,712,813,000
Unproved properties not being amortized	305,621,000	296,764,000
Drilling equipment	1,601,777,000	1,593,611,000
Gas gathering and processing equipment	731,006,000	726,236,000
Saltwater disposal systems	63,124,000	62,618,000
Corporate land and building	59,080,000	59,080,000
Transportation equipment	29,908,000	29,631,000
Other	56,142,000	53,439,000
Property, plant, and equipment, gross	8,608,727,000	8,534,192,000
Less accumulated depreciation, depletion, amortization, and impairment	6,207,449,000	6,151,450,000
Net property and equipment	2,401,278,000	2,382,742,000
Goodwill	62,808,000	62,808,000
Other assets	27,470,000	16,230,000
Total assets	2,599,591,000	2,581,452,000
Current liabilities:
Accounts payable	131,064,000	112,648,000
Accrued liabilities (Note 5)	52,964,000	48,523,000
Current derivative liability (Note 10)	12,104,000	7,763,000
Current portion of other long-term liabilities (Note 6)	14,587,000	13,002,000
Total current liabilities	210,719,000	181,936,000
Long-term debt less debt issuance costs (Note 6)	790,522,000	820,276,000
Non-current derivative liability (Note 10)	164,000	0
Other long-term liabilities (Note 6)	104,286,000	100,203,000
Deferred income taxes	136,600,000	133,477,000
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, 54,046,361 and 52,880,134 shares issued as of March 31, 2018 and December 31, 2017, respectively	10,403,000	10,280,000
Capital in excess of par value	541,004,000	535,815,000
Accumulated other comprehensive income (Note 13)	(100,000)	63,000
Retained earnings	805,993,000	799,402,000
Total shareholders' equity	1,357,300,000	1,345,560,000
Total liabilities and shareholders' equity	$ 2,599,591,000	$ 2,581,452,000

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 2,450	$ 2,450
Preferred stock, par value	$ 1.00	$ 1.00
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	54,046,361	52,880,134

Condensed Consolidated Income Statements (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Oil and natural gas	$ 103,099	$ 87,598
Contract drilling	45,989	37,185
Gas gathering and processing	56,044	50,941
Total revenues	205,132	175,724
Operating costs:
Oil and natural gas	35,962	29,204
Contract drilling	31,667	29,227
Gas gathering and processing	41,604	37,704
Total operating costs	109,233	96,135
Depreciation, depletion, and amortization	57,066	46,932
General and administrative	10,762	8,954
Gain on disposition of assets	(161)	(824)
Total operating expenses	176,900	151,197
Income from operations	28,232	24,527
Other income (expense):
Interest, net	(10,004)	(9,396)
Gain (loss) on derivatives	(6,762)	14,731
Other, net	6	3
Total other income (expense)	(16,760)	5,338
Income before income taxes	11,472	29,865
Income tax expense:
Deferred	3,607	13,936
Total income taxes	3,607	13,936
Net income	$ 7,865	$ 15,929
Net income per common share:
Basic	$ 0.15	$ 0.32
Diluted	$ 0.15	$ 0.31

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 7,865	$ 15,929
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax of ($58) and $0	(176)	0
Comprehensive income	$ 7,689	$ 15,929

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Unrealized loss on securities, tax	$ (58)	$ 0

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
OPERATING ACTIVITIES:
Net income	$ 7,865	$ 15,929
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	57,066	46,932
Amortization of debt issuance costs and debt discount (Note 6)	546	536
(Gain) loss on derivatives	6,762	(14,731)
Cash payments on derivatives settled, net	(2,073)	(1,159)
Deferred tax expense	3,607	13,936
Gain on disposition of assets	(161)	(824)
Stock compensation plans	6,609	3,704
Contract assets and liabilities, net (Note 2)	(1,192)	0
Other, net	937	626
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	8,005	(1,900)
Accounts payable	(55,638)	(7,735)
Material and supplies	50	73
Accrued liabilities	6,757	9,832
Other, net	(494)	433
Net cash provided by operating activities	38,646	65,652
INVESTING ACTIVITIES:
Capital expenditures	(45,327)	(37,636)
Producing properties and other acquisitions	0	(7,508)
Proceeds from disposition of assets	22,084	16,116
Net cash used in investing activities	(23,243)	(29,028)
FINANCING ACTIVITIES:
Borrowings under credit agreement	67,400	49,700
Payments under credit agreement	(97,700)	(60,500)
Payments on capitalized leases	(946)	(946)
Book overdrafts	15,894	(17,301)
Net cash used in financing activities	(15,352)	(29,047)
Net increase in cash and cash equivalents	51	7,577
Cash and cash equivalents, beginning of period	701	893
Cash and cash equivalents, end of period	752	8,470
Cash paid during the year for:
Interest paid (net of capitalized)	(1,731)	(2,389)
Income taxes	0	0
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(58,160)	(11,401)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations	$ 6,340	$ 912

Basis of Preparation and Presentation

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Preparation and Presentation

BASIS OF PREPARATION AND PRESENTATION

The unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires.

The condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 27, 2018, for the year ended December 31, 2017.

In the opinion of our management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state:


•	Balance Sheets at March 31, 2018 and December 31, 2017;


•	Income Statements for the three months ended March 31, 2018 and 2017;


•	Statements of Comprehensive Income for the three months ended March 31, 2018 and 2017; and


•	Statements of Cash Flows for the three months ended March 31, 2018 and 2017.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. Results for the three months ended March 31, 2018 and 2017 are not necessarily indicative of the results to be realized for the full year of 2018, or that we realized for the full year of 2017.

Accounting Changes - Recent Accounting Pronouncements - Adopted

As of January 1, 2018, the company adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This standard is explained further in Note 8 - New Accounting Pronouncements. We adopted this amendment early and it did not have a material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 13 - Equity.

Also, as of January 1, 2018, the company adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606) and all later amendments that modified ASC 606. The new revenue standard is explained further in Note 8 - New Accounting Pronouncements. The company has elected to apply the standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect upon adoption, which only impacted our mid-stream segment is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.

The additional disclosures required by the ASU have been included in Note 2 – Revenue from Contracts with Customers.

Revenue from Contracts with Customers

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer

REVENUE FROM CONTRACTS WITH CUSTOMERS

The company’s revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 14 - Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period of time. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. The company sells its hydrocarbons (from the oil and natural gas and mid-stream segments) to midstream and downstream oil and gas companies.

We satisfy performance obligation for each contract as follows: for the contract drilling and mid-stream contracts, we satisfy the performance obligation over the agreed-on time period within the contracts, and for oil and natural gas contracts, we satisfy the performance obligation with each delivery of volumes. For oil and natural gas contracts, as it is more feasible, we account for these deliveries on a monthly basis. Per the contracts for all segments, customers pay for the services/goods received on a monthly basis within an agreed on number of days following the end of the month. Besides the mid-stream demand fees discussed further below, there were no other contract assets or liabilities.

Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations

Typical types of revenue contracts signed are Oil Sales Contracts, Gas Purchase Agreements, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract term can range from single month to extended term contracts spanning a decade or more; some include evergreen provisions. Revenues from sales are recognized when the customer obtains control of the company’s product. For sales to other midstream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. On adoption of the standard, no adjustment to opening retained earnings was required.

Certain costs as either a deduction from revenue or an expense is determined based on when control of the commodity transfers to the customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs that are included as part of the contract price with the customer upon transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs. The following table summarizes the impact of the adoption of ASC 606 on revenue and operating costs, as the change did not impact income from operations or net income for the three months ended March 31, 2018:



	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Oil and natural gas revenues	$	103,099	$	(3,169	)	$	106,268
Oil and natural gas operating costs	35,962		(3,169		)	39,131
Gross profit	$	67,137	$	—		$	67,137

Our performance obligation for all contracts is the delivery of oil and gas volumes to the customer. Typically the contract will establish a period of time (for example, a month or a year); however, each delivery can be considered separately identifiable as each delivery provides benefits to the customer on its own. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we conclude this performance obligation is satisfied monthly. We typically receive payment within a set number of days following the end of the month and includes payment for all deliveries in that month. Depending on contract circumstances, judgment could be required to determine when the transfer of control occurs. Generally, depending of the facts and circumstances, we consider the transfer of control of the asset in a commodity sale to occur at the point the commodity transfers to our final purchaser.

The majority of the consideration received for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by an agreed-on index price less deductions related to gathering, transportation, fractionation, and related fuel charges. There are also instances where the consideration is quantity multiplied by a weighted average sales price. These different pricing tools can change the perception of when control transfers; however, when analyzed with other control factors, typically the accounting conclusion is the same for both pricing methods. In these instances, the variable consideration is partially constrained. In addition, all variable consideration is settled at the end of the month; therefore, whether the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period. An estimation and allocation of transaction price and future obligations are not required.

Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations

The contract drilling contracts we use primarily are industry standard IADC contracts 2003 and 2013. Contract terms can range from six months to two or more years or can be based on terms to drill a specific number of wells. These allocation rules in ASC 606 are referred to as the series guidance which states that a contract may contain a single performance obligation composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same method as it relates to the satisfaction of the overall performance obligation. The company determined that the delivery of drilling services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment of service (i.e. hour available to drill) that the driller promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the driller would use the same method for measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under the new standard will allow the company to recognize revenues associated with contract drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Such liabilities will generally only arise in relation to upfront mobilization fees which are paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue. On adoption of the standard, no adjustment to opening retained earnings was required.

Our performance obligation for all contracts is to drill the agreed-on number of wells or drill over an agreed-on period of time as stated in the contract. Mobilization and demobilization activities associated with a drilling contract are not considered to be distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to two years. Most of the drilling contracts are for less than one year. As the customer simultaneously received and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and includes payment for all services performed that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-upon depth or by a set date.

All consideration received for contract drilling contracts is variable, excluding termination fees, which we concluded will not be applicable to our current contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items per the contract include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the financial statements was immaterial. As of March 31, 2018, we had 32 contract drilling contracts (six long-term) for a duration of two to fourteen months.

Per the new guidance in relation to disclosures regarding remaining performance obligations, there is a practical expedient for contracts that have an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). The majority of contract drilling contracts have an original term of less than one year; however, there are a few contracts with a longer duration that are not material.

Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations

Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. Typical types of revenue contracts signed are Gas Gathering and Processing agreements. Contract terms can range from single month to extended term contracts spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.

On adoption of the standard, an adjustment to opening retained earnings was made in the amount of $1.7 million ($1.3 million, net of tax). This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Balance Sheet:



	Balance at December 31, 2017		Adjustments due to ASC 606			Balance at January 1, 2018
	(In thousands)
Assets:
Other assets	$	16,230	$	10,798		$	27,028
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	13,002		2,748			15,750
Other long-term liabilities	100,203		9,737			109,940
Deferred income taxes	133,477		(413		)	133,064
Retained earnings	799,402		(1,274		)	798,128

The following impact of these demand fees to the Unaudited Condensed Consolidated Balance Sheet on at March 31, 2018:



	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Assets:
Prepaid expenses and other	$	7,724	$	50		$	7,674
Other assets	27,470		11,397			16,073
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	14,587		2,824			11,763
Other long-term liabilities	104,286		9,118			95,168
Deferred income taxes	136,600		(121		)	136,479
Retained earnings	805,993		(374		)	805,619

This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Income Statement for the three months ended March 31, 2018:



	As Reported		Adjustments due to ASC 606		Amounts without the Adoption of ASC 606
	(In thousands)
Gas gathering and processing revenues	$	56,044	$	1,192	$	54,852
Deferred income tax expense	3,607		292		3,315
Net income	7,865		900		6,965

The only fixed consideration related to mid-stream consideration is the demand fee which is calculated by multiplying an agreed-on price by a fixed number of volumes per month over a specified term in the contract.

Included below is the additional fixed revenue the company will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.



Contract	Remaining Term of Contract	April - December 2018		2019		2020			2021			2022		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	4-5 years	$	3,777	$	2,632	$	(3,781	)	$	(3,507	)	$	1,374	$	495

Before the implementation of ASC 606, we recognized the entire demand fee as the fee was payable the first five years after the effective date, not the entire term of the contract. However, as the demand fee does not specifically relate to a distinct performance obligation, the amount should be recognized over the life of the contract. Therefore, the demand fee already recognized for $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018, and will be recognized over the remaining term of the contract. As this amount is fixed consideration, recognition of the remaining portion will be stable. For the first three months of March 31, 2018, $1.2 million was recognized in revenue for these demand fees.

Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported.)



	March 31, 2018			January 1, 2018			Change
	(In thousands)
Contract assets	$	11,447		$	10,798		$	649
Contract liabilities	11,942			12,485			(543		)
Contract liabilities, net	$	(495	)	$	(1,687	)	$	1,192

Our performance obligations for all contracts is to gather, transport, or process an agreed-on number of volumes as stated in the contract. Typically the contract will establish a period of time over which the company will perform the mid-stream services. Certain contracts also include an agreed-on quantity (or an agreed-on minimum quantity) of volumes that the company will deliver or service. The term under mid-stream service contracts is typically five to ten years. Under service contracts, as the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs, the performance obligation to gather, transport, or process occurs over time. We typically receive payment within a set number of days following the end of the month and includes payment for all services performed that month. The company satisfies its overall performance obligation at the end of the contract term.

Most of the consideration received for mid-stream service contracts is variable. The consideration is calculated by multiplying a variable quantity (number of volumes) by an agreed-on price per MCF (commodity fee and the gathering fee). One fixed component of revenue is calculated by multiplying an agreed-on price by a certain volume commitment (MCF per day). Other revenue items may include shortfall fees. All variable consideration is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. However, this excludes the shortfall fee as this fee could be based on a set number of volumes over the course of more than one month.

Per the new guidance related to disclosures for remaining performance obligations, there is a practical expedient for contracts that have an original expected duration of one year or less (ASC 606-10-50-14). There is also a practical expedient for “variable consideration [that] is allocated entirely to a wholly unsatisfied performance obligation… that forms part of a single performance obligation… for which the criteria in paragraph 606-10-32-40 have been met” (ASC 606-10-50-14A). As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee. The last time we received a shortfall fee was in 2016 and the amount was immaterial to total mid-stream revenues. These terms have historically been limited in our contracts.

We calculate revenue earned from the variable consideration related to mid-stream services by multiplying the number of volumes serviced times an agreed-on price. Therefore, the variable portion of this consideration is due to the change in volumes. This variability is resolved at the end of each month as the company will know the number of volumes serviced under each contract and payment is received monthly. The mid-stream gathering service contracts remaining are for a duration of less than one year to 15 years.

While long term service contracts are in place as of the reporting date, due to the variable volumes an estimation and allocation of transaction price and future obligations are not required.

Divestitures	3 Months Ended
Divestitures	Mar. 31, 2018
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 $21.7 million during the first three months of 2018, compared to $14.8 million during the first three months of 2017. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Earnings Per Share

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:



	Earnings (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended March 31, 2018
Basic earnings per common share	$	7,865	51,730	$	0.15
Effect of dilutive stock options and restricted stock	—		542	—
Diluted earnings per common share	$	7,865	52,272	$	0.15
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

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,
	2018		2017
Stock options and SARs	87,500		199,755
Average exercise price	$	51.34	$	48.79

Accrued Liabilities

3 Months Ended

Mar. 31, 2018

Accrued Liabilities [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of:



	March 31, 2018		December 31, 2017
	(In thousands)
Interest payable	$	17,560	$	6,745
Lease operating expenses	11,570		11,819
Employee costs	9,754		19,521
Taxes	4,139		3,404
Third-party credits	2,051		2,240
Derivative settlements	1,527		—
Other	6,363		4,794
Total accrued liabilities	$	52,964	$	48,523

Long-Term Debt And Other Long-Term Liabilities

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Long-Term Debt And Other Long-Term Liabilities

LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

Our long-term debt as of the dates indicated consisted of the following:



	March 31, 2018			December 31, 2017
	(In thousands)
Credit agreement with an average interest rate of 3.8% and 3.4% at March 31, 2018 and December 31, 2017, respectively	$	147,700		$	178,000
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	797,700			828,000
Less: unamortized discount	(2,085		)	(2,234		)
Less: debt issuance costs, net	(5,093		)	(5,490		)
Total long-term debt	$	790,522		$	820,276

Credit Agreement. On April 2, 2018, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The details of this amendment are discussed in Note 15 — Subsequent Events.

Before the amendment and through March 31, 2018, the amount we could borrow was the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our borrowing base and elected commitment was $475.0 million. We were charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. Under the credit agreement, we have pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. 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 could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At March 31, 2018, we had $147.7 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, 2018, we were in compliance with the credit agreement covenants.

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

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

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes

(registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of March 31, 2018.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	March 31, 2018		December 31, 2017
	(In thousands)
Asset retirement obligation (ARO) liability	$	63,763	$	69,444
Capital lease obligations	14,277		15,224
Workers’ compensation	13,049		13,340
Contract liability	11,942		—
Separation benefit plans	7,087		6,524
Deferred compensation plan	5,472		5,390
Gas balancing liability	3,283		3,283
	118,873		113,205
Less current portion	14,587		13,002
Total other long-term liabilities	$	104,286	$	100,203

Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve-month periods beginning April 1, 2018 (and through 2023) are $14.6 million, $41.9 million, $156.1 million, $653.2 million, and $2.0 million, respectively.

Capital Leases

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.9 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $10.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $5.4 million and $1.0 million, respectively, at March 31, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

Future payments required under the capital leases at March 31, 2018:



	Amount
Beginning April 1,	(In thousands)
2018	$	6,168
2019	6,168
2020	7,815
2021	579
Total future payments	20,730
Less payments related to:
Maintenance	5,428
Interest	1,025
Present value of future minimum payments	$	14,277

Asset Retirement Obligations

3 Months Ended

Mar. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.

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



	Three Months Ended
	March 31,
	2018			2017
	(In thousands)
ARO liability, January 1:	$	69,444		$	70,170
Accretion of discount	659			785
Liability incurred	118			658
Liability settled	(1,626		)	(630		)
Liability sold	(81		)	(432		)
Revision of estimates ⁽¹⁾	(4,751		)	(508		)
ARO liability, March 31:	63,763			70,043
Less current portion	1,477			3,243
Total long-term ARO	$	62,286		$	66,800

_______________________


(1)	Plugging liability estimates were revised in both 2018 and 2017 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	3 Months Ended
New Accounting Pronouncements	Mar. 31, 2018
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 measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements. Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. In January 2018, the FASB issued ASU 2018-01, "Leases - Land Easement practical expedient for Transition to Topic 842", which provides clarifying guidance regarding land easements and adds practical expedients. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We have begun the identification of leases and impact assessment within the scope of the guidance. Our evaluation of the impact of the new guidance on our financial statements in on-going. Adopted Standards Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The FASB issued ASU 2018-02, an amendment which provides financial statement preparers with an option to reclassify stranded tax effects within AOCI to retained earnings caused by the Tax Cuts and Jobs Act of 2017. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. Organizations should apply the proposed amendments either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We adopted this amendment early and it did not have a material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 13 - Equity. Revenue from Contracts with Customers. Effective January 1, 2018, the company adopted ASC 606. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The guidance in this update supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Under the standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The company applied the five step method outlined in the ASU to all revenue streams in the scope of ASC 606 and elected the modified retrospective approach method. Under that approach the cumulative effect on adoption is recognized as an adjustment to opening retained earnings at January 1, 2018. Only our mid-stream segment was affected. This adjustment related to the timing of revenue on certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605. The additional disclosures required by ASC 606 have been included in Note 2 – Revenue from Contracts with Customers. Our internal control framework did not materially change, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.

Stock-Based Compensation

3 Months Ended

Mar. 31, 2018

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,
	2018		2017
	(In millions)
Recognized stock compensation expense	$	4.6	$	2.6
Capitalized stock compensation cost for our oil and natural gas properties	1.3		0.4
Tax benefit on stock based compensation	1.1		1.0

The remaining unrecognized compensation cost related to unvested awards at March 31, 2018 is approximately $27.4 million, of which $3.5 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one year.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. 7,230,000 shares of the company's common stock are 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 granted no SARs or stock options during either of the three-month periods ending March 31, 2018 or 2017. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:



	Three Months Ended						Three Months Ended
	March 31, 2018						March 31, 2017
	Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	839,498			362,070			461,799			152,373
Non-employee directors	—			—			—			—
	839,498			362,070			461,799			152,373
Estimated fair value (in millions):⁽¹⁾
Employees	$	16.1		$	7.3		$	11.4		$	4.0
Non-employee directors	—			—			—			—
	$	16.1		$	7.3		$	11.4		$	4.0
Percentage of shares granted expected to be distributed:
Employees	95		%	63		%	94		%	105		%
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 2018 and 2017 are being recognized over a three-year vesting period. During the the first quarter of 2018 and 2017, there were two 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 (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected TSR performance criteria at March 31, 2018, the participants are estimated to receive 27% of the 2018, 93% of the 2017, and 164% of the 2016 performance based shares. The CFTA performance measurement at March 31, 2018 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 2018 awards for the first three months of 2018 was $1.1 million.

Derivatives

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

Commodity Derivatives

We have signed 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, 2018, our derivative transactions comprised these 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 before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Income Statements.

At March 31, 2018, these derivatives were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Apr’18 – Sep'18	Natural gas – swap	40,000 MMBtu/day	$2.985	IF – NYMEX (HH)
Oct'18	Natural gas – swap	30,000 MMBtu/day	$3.005	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
Apr'18 – Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.190)	NGPL TEXOK
Apr'18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Apr’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.568)	NGPL MIDCON
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.728)	PEPL
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.625)	NGL MIDCON
Jan'19 – Dec'19	Natural gas – basis swap	30,000 MMBtu/day	$(0.265)	NGPL TEXOK
Jan'20 – Dec'20	Natural gas – basis swap	20,000 MMBtu/day	$(0.280)	NGPL TEXOK
Apr'18 – Sep'18	Natural gas – collar	30,000 MMBtu/day	$2.67 - $2.97	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'18 – Dec'18	Crude oil – swap	4,000 Bbl/day	$53.52	WTI – NYMEX
Apr'18 – Dec'18	Crude oil – three-way collar	2,000 Bbl/day	$47.50 - $37.50 - $56.08	WTI – NYMEX
Apr'18 – Sep'18	NGLs – swap ⁽¹⁾	1,500 Bbl/day	$32.14	OPIS – Mont Belvieu

_______________________


(1)	Type of NGLs involved is propane.

After March 31, 2018, the following derivative was entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Jan'19 – Dec'19	Crude oil – three-way collar	1,000 Bbl/day	$55.00 - $45.00 - $70.25	WTI – NYMEX
Jan'20 – Dec'20	Natural gas – basis swap	10,000 MMBtu/day	$(0.265)	NGPL TEXOK

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, 2018		December 31, 2017
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	537	$	721
Long-term	Non-current derivative asset	—		—
Total derivative assets		$	537	$	721



		Derivative Liabilities
		Fair Value
	Balance Sheet Location	March 31, 2018		December 31, 2017
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	12,104	$	7,763
Long-term	Non-current derivative liability	164		—
Total derivative liabilities		$	12,268	$	7,763

All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the three months ended March 31:



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2018			2017
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(6,762	)	$	14,731
Total		$	(6,762	)	$	14,731

_______________________


(1)	Amounts settled during the 2018 and 2017 periods include net payments of $2.1 million and $1.2 million, respectively.

Fair Value Measurements

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

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



	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	(In thousands)
Equity Securities:
March 31, 2018	$	830	$	—	$	132	$	698
December 31, 2017	$	830	$	102	$	—	$	932

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

Fair value is defined as the amount that would be received from the sale of an asset or paid for transferring 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 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, 2018
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	2,897		$	1,294		$	(3,654	)	$	537
Liabilities	—		(11,422		)	(4,500		)	3,654			(12,268		)
Total commodity derivatives	—		(8,525		)	(3,206		)	—			(11,731		)
Equity securities	698		—			—			—			698
	$	698	$	(8,525	)	$	(3,206	)	$	—		$	(11,033	)



	December 31, 2017
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	2,137		$	3,344		$	(4,760	)	$	721
Liabilities	—		(8,973		)	(3,550		)	4,760			(7,763		)
Total commodity derivatives	$	—	$	(6,836	)	$	(206	)	$	—		$	(7,042	)
Equity securities	932		—			—			—			932
	$	932	$	(6,836	)	$	(206	)	$	—		$	(6,110	)

All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2018.

We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).

Level 1 Fair Value Measurements

Equity Securities. We measure the fair values of our available for sale securities based on market quotes.

Level 2 Fair Value Measurements

Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.

Level 3 Fair Value Measurements

Commodity Derivatives. The fair values of our natural gas and crude oil collars and three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.

The following table is a reconciliation of our level 3 fair value measurements:



	Net Derivatives
	Three Months Ended
	March 31,
	2018			2017
	(In thousands)
Beginning of period	$	(206	)	$	(7,122	)
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	(3,919		)	5,903
Settlements	919			617
End of period	$	(3,206	)	$	(602	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period	$	(3,000	)	$	6,520

_______________________


(1)	Commodity derivatives are reported in the Unaudited Condensed Consolidated Income Statements in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2018:



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil three-way collars	$	(4,457	)	Discounted cash flow	Forward commodity price curve	$0 - $9.41
Natural gas collar	$	(1	)	Discounted cash flow	Forward commodity price curve	$0.01 - $0.12
Natural gas three-way collars	$	1,252		Discounted cash flow	Forward commodity price curve	$0 - $0.28

_______________________


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

Our valuation at March 31, 2018 reflected that the risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

This disclosure of the estimated fair value of financial instruments is made under accounting guidance for financial instruments. We have determined the estimated fair values by using market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At March 31, 2018, 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 available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at March 31, 2018 and December 31, 2017 was $147.7 million and $178.0 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 were $642.8 million and $642.3 million, respectively. We estimate the fair value of the Notes using quoted marked prices at March 31, 2018 and December 31, 2017 was $632.9 million and $649.7 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	3 Months Ended
Commitments and Contingencies	Mar. 31, 2018
Commitments and Contingencies [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $2.7 million, $0.9 million, $0.4 million, and less than $0.1 million in twelve-month periods beginning April 1, 2018 (and through 2021), respectively. Total rent expense incurred was $2.3 million and $2.1 million for the first three months of 2018 and 2017, respectively. In 2014, our mid-stream segment signed capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the four successive twelve-month periods beginning April 1, 2018 (and through the end of 2021) are $6.2 million, $6.2 million, $7.8 million, and $0.6 million. Total maintenance and interest remaining related to these leases are $5.4 million and $1.0 million, respectively at March 31, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value. The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first quarter of 2018 or 2017. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well. For the next twelve months, we have committed to purchase approximately $3.4 million of new drilling rig components.

Equity

3 Months Ended

Mar. 31, 2018

Equity [Abstract]

Equity

EQUITY

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we signed a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.

Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms 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 we may impose).

We do not have 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 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 March 31, 2018, we have sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the first quarter of 2018. On May 2, 2018, we terminated this Agreement, the details are discussed in Note 15 — Subsequent Events.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the three months ended March 31:



	2018				2017
	(In thousands)
Unrealized loss on securities, before tax	$	(234	)		$	—
Tax expense	58			⁽¹⁾	—
Unrealized loss on securities, net of tax	$	(176	)		$	—

_______________________


(1)	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

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



	Net Gains on Equity Securities
	2018				2017
	(In thousands)
Balance at December 31, 2017	$	63			$	—
Adjustment due to ASU 2018-02	13			⁽¹⁾	—
Balance at January 1:	76				—
Unrealized loss before reclassifications	(176		)	⁽¹⁾	—
Amounts reclassified from accumulated other comprehensive income	—				—
Net current-period other comprehensive income	(176		)		—
Balance at March 31:	$	(100	)		$	—

_______________________


(1)	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Industry Segment Information

3 Months Ended

Mar. 31, 2018

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, 2018
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	103,099	$	—	$	—	$	—		$	—		$	103,099
Contract drilling	—		50,710		—		—			(4,721		)	45,989
Gas gathering and processing	—		—		74,650		—			(18,606		)	56,044
Total revenues	103,099		50,710		74,650		—			(23,327		)	205,132
Expenses:
Operating costs:
Oil and natural gas	37,152		—		—		—			(1,190		)	35,962
Contract drilling	—		35,954		—		—			(4,287		)	31,667
Gas gathering and processing	—		—		59,020		—			(17,416		)	41,604
Total operating costs	37,152		35,954		59,020		—			(22,893		)	109,233
Depreciation, depletion, and amortization	30,783		13,312		11,053		1,918			—			57,066
Total expenses	67,935		49,266		70,073		1,918			(22,893		)	166,299
Total operating income (loss) ⁽²⁾	35,164		1,444		4,577		(1,918		)	(434		)
General and administrative expense	—		—		—		(10,762		)	—			(10,762		)
Gain on disposition of assets	71		26		34		30			—			161
Loss on derivatives	—		—		—		(6,762		)	—			(6,762		)
Interest expense, net	—		—		—		(10,004		)	—			(10,004		)
Other	—		—		—		6			—			6
Income (loss) before income taxes	$	35,235	$	1,470	$	4,611	$	(29,410	)	$	(434	)	$	11,472

_______________________


(1)	The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.


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



	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, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income, or income taxes.

Subsequent Event	3 Months Ended
Subsequent Event	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events [Text Block]	SUBSEQUENT EVENTS On April 2, 2018, the company, including certain of its subsidiaries signed a Fourth Amendment to our Senior Credit Agreement (Fourth Amendment) with these lenders: BOKF, NA (dba Bank of Oklahoma); Compass Bank; BMO Harris Financing, Inc.; Bank of America, N.A.; Wells Fargo Bank, N.A.; Comerica Bank; Canadian Imperial Bank of Commerce, New York Branch; and Toronto Dominion (New York), LLC. BOKF, NA is serving as administrative agent for the other lenders under the Fourth Amendment. The Fourth Amendment was signed in connection with our sale of 50% of our ownership interest in our midstream segment, Superior Pipeline Company, L.L.C. One of the conditions of that sale was the release of Superior from the terms of the credit agreement. Since the Fourth Amendment needed to be signed before the closing of the Superior sale it was designed to account for the possibility the Superior sale might not close as anticipated. The Fourth Amendment provides, among other things, for a reduction of the maximum credit amount from $875.0 million to $475.0 million, and an increase in the borrowing base from $475.0 million to $525.0 million; provide that part of the proceeds from the sale be used to pay down the existing outstanding principal balance under the credit agreement. Once that payment was made on April 3, 2018-(i) the total commitment amount was reduced from $475.0 million to $425.0 million; (ii) the maximum credit amount was reduced from $475.0 million to $425.0 million and set as the amount that would otherwise be subject to redetermination in April; (iii) the borrowing base was reduced from $525.0 million to $425.0 million; and (iv) Superior and its subsidiaries (Superior), were fully released as a borrower and co-obligor under the credit agreement. The Superior sale closed on April 3, 2018 and the paydown under the credit agreement was made that same day. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager (Purchaser), for cash consideration of $300.0 million. The sale closed under the purchase and sale agreement (the Purchase Agreement) dated March 28, 2018 and closed on April 3, 2018. Part of the proceeds from the sale were used to pay down our bank debt and the remainder will be used to accelerate the drilling program of our upstream subsidiary, Unit Petroleum Company, make additional capital investments in the jointly owned Superior, and for general working capital purposes. In connection with the sale of the interest in Superior, the company and its board of directors took the necessary actions under the Indenture governing the company's outstanding senior subordinated notes to secure the ability to close the sale and to have Superior released from the Indenture. Superior will be governed and managed by the Amended and Restated Limited Liability Company Agreement and Master Services and Operating Agreement, respectively, both of which are included as exhibits to the Purchase and Sale Agreement filed with this report. On May 2, 2018, we terminated the Distribution Agreement dated April 4, 2017, as amended (the Distribution Agreement), between the company and Raymond James & Associates, Inc. (the Sales Agent). The Distribution Agreement was terminable at will on written notification by the company with no penalty. Under the Distribution Agreement, the company was entitled to issue and sell, from time to time, through or to the Sales Agent shares of its common stock, having an aggregate offering price of up to $100.0 million in an “at-the-market” offering program. As of the date of termination, the company sold 787,547 shares of its Common Stock under the Distribution Agreement. As a result of the termination, there will be no more sales of the our common stock under the Distribution Agreement.

Revenue from Contracts with Customers Revenues from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2018

Revenue From Contracts with Customers [Abstract]

Revenue Impact of the Adoption of ASC606

The following table summarizes the impact of the adoption of ASC 606 on revenue and operating costs, as the change did not impact income from operations or net income for the three months ended March 31, 2018:



	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Oil and natural gas revenues	$	103,099	$	(3,169	)	$	106,268
Oil and natural gas operating costs	35,962		(3,169		)	39,131
Gross profit	$	67,137	$	—		$	67,137



	As Reported		Adjustments due to ASC 606		Amounts without the Adoption of ASC 606
	(In thousands)
Gas gathering and processing revenues	$	56,044	$	1,192	$	54,852
Deferred income tax expense	3,607		292		3,315
Net income	7,865		900		6,965

Balance Sheet Impact of the Adoption of ASC606

This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Balance Sheet:



	Balance at December 31, 2017		Adjustments due to ASC 606			Balance at January 1, 2018
	(In thousands)
Assets:
Other assets	$	16,230	$	10,798		$	27,028
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	13,002		2,748			15,750
Other long-term liabilities	100,203		9,737			109,940
Deferred income taxes	133,477		(413		)	133,064
Retained earnings	799,402		(1,274		)	798,128

The following impact of these demand fees to the Unaudited Condensed Consolidated Balance Sheet on at March 31, 2018:



	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Assets:
Prepaid expenses and other	$	7,724	$	50		$	7,674
Other assets	27,470		11,397			16,073
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	14,587		2,824			11,763
Other long-term liabilities	104,286		9,118			95,168
Deferred income taxes	136,600		(121		)	136,479
Retained earnings	805,993		(374		)	805,619

Revenue, Remaining Performance Obligation

Included below is the additional fixed revenue the company will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.



Contract	Remaining Term of Contract	April - December 2018		2019		2020			2021			2022		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	4-5 years	$	3,777	$	2,632	$	(3,781	)	$	(3,507	)	$	1,374	$	495

Contract with Customer, Asset and Liability

Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported.)



	March 31, 2018			January 1, 2018			Change
	(In thousands)
Contract assets	$	11,447		$	10,798		$	649
Contract liabilities	11,942			12,485			(543		)
Contract liabilities, net	$	(495	)	$	(1,687	)	$	1,192

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

Information related to the calculation of earnings per share follows:



	Earnings (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended March 31, 2018
Basic earnings per common share	$	7,865	51,730	$	0.15
Effect of dilutive stock options and restricted stock	—		542	—
Diluted earnings per common share	$	7,865	52,272	$	0.15
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

Schedule of Antidilutive Securities Excluded From Computation of Earnings Per Share



	Three Months Ended
	March 31,
	2018		2017
Stock options and SARs	87,500		199,755
Average exercise price	$	51.34	$	48.79

Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Accrued Liabilities [Abstract]

Accrued Liabilities

Accrued liabilities consisted of:



	March 31, 2018		December 31, 2017
	(In thousands)
Interest payable	$	17,560	$	6,745
Lease operating expenses	11,570		11,819
Employee costs	9,754		19,521
Taxes	4,139		3,404
Third-party credits	2,051		2,240
Derivative settlements	1,527		—
Other	6,363		4,794
Total accrued liabilities	$	52,964	$	48,523

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

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Long-Term Debt

Our long-term debt as of the dates indicated consisted of the following:



	March 31, 2018			December 31, 2017
	(In thousands)
Credit agreement with an average interest rate of 3.8% and 3.4% at March 31, 2018 and December 31, 2017, respectively	$	147,700		$	178,000
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	797,700			828,000
Less: unamortized discount	(2,085		)	(2,234		)
Less: debt issuance costs, net	(5,093		)	(5,490		)
Total long-term debt	$	790,522		$	820,276

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	March 31, 2018		December 31, 2017
	(In thousands)
Asset retirement obligation (ARO) liability	$	63,763	$	69,444
Capital lease obligations	14,277		15,224
Workers’ compensation	13,049		13,340
Contract liability	11,942		—
Separation benefit plans	7,087		6,524
Deferred compensation plan	5,472		5,390
Gas balancing liability	3,283		3,283
	118,873		113,205
Less current portion	14,587		13,002
Total other long-term liabilities	$	104,286	$	100,203

Capital leases

Future payments required under the capital leases at March 31, 2018:



	Amount
Beginning April 1,	(In thousands)
2018	$	6,168
2019	6,168
2020	7,815
2021	579
Total future payments	20,730
Less payments related to:
Maintenance	5,428
Interest	1,025
Present value of future minimum payments	$	14,277

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

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

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

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21506-112644

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

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

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21521-112644

+ Details

Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2018

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,
	2018			2017
	(In thousands)
ARO liability, January 1:	$	69,444		$	70,170
Accretion of discount	659			785
Liability incurred	118			658
Liability settled	(1,626		)	(630		)
Liability sold	(81		)	(432		)
Revision of estimates ⁽¹⁾	(4,751		)	(508		)
ARO liability, March 31:	63,763			70,043
Less current portion	1,477			3,243
Total long-term ARO	$	62,286		$	66,800

_______________________


(1)	Plugging liability estimates were revised in both 2018 and 2017 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 (Tables)

3 Months Ended

Mar. 31, 2018

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,
	2018		2017
	(In millions)
Recognized stock compensation expense	$	4.6	$	2.6
Capitalized stock compensation cost for our oil and natural gas properties	1.3		0.4
Tax benefit on stock based compensation	1.1		1.0

Schedule of Fair Value of the Restricted Stock Awards Granted During the Periods

This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:



	Three Months Ended						Three Months Ended
	March 31, 2018						March 31, 2017
	Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	839,498			362,070			461,799			152,373
Non-employee directors	—			—			—			—
	839,498			362,070			461,799			152,373
Estimated fair value (in millions):⁽¹⁾
Employees	$	16.1		$	7.3		$	11.4		$	4.0
Non-employee directors	—			—			—			—
	$	16.1		$	7.3		$	11.4		$	4.0
Percentage of shares granted expected to be distributed:
Employees	95		%	63		%	94		%	105		%
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)

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives outstanding

At March 31, 2018, these derivatives were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Apr’18 – Sep'18	Natural gas – swap	40,000 MMBtu/day	$2.985	IF – NYMEX (HH)
Oct'18	Natural gas – swap	30,000 MMBtu/day	$3.005	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
Apr'18 – Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.190)	NGPL TEXOK
Apr'18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Apr’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.568)	NGPL MIDCON
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.728)	PEPL
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.625)	NGL MIDCON
Jan'19 – Dec'19	Natural gas – basis swap	30,000 MMBtu/day	$(0.265)	NGPL TEXOK
Jan'20 – Dec'20	Natural gas – basis swap	20,000 MMBtu/day	$(0.280)	NGPL TEXOK
Apr'18 – Sep'18	Natural gas – collar	30,000 MMBtu/day	$2.67 - $2.97	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'18 – Dec'18	Crude oil – swap	4,000 Bbl/day	$53.52	WTI – NYMEX
Apr'18 – Dec'18	Crude oil – three-way collar	2,000 Bbl/day	$47.50 - $37.50 - $56.08	WTI – NYMEX
Apr'18 – Sep'18	NGLs – swap ⁽¹⁾	1,500 Bbl/day	$32.14	OPIS – Mont Belvieu

_______________________


(1)	Type of NGLs involved is propane.

Subsequent Derivatives Outstanding

After March 31, 2018, the following derivative was entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Jan'19 – Dec'19	Crude oil – three-way collar	1,000 Bbl/day	$55.00 - $45.00 - $70.25	WTI – NYMEX
Jan'20 – Dec'20	Natural gas – basis swap	10,000 MMBtu/day	$(0.265)	NGPL TEXOK

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, 2018		December 31, 2017
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	537	$	721
Long-term	Non-current derivative asset	—		—
Total derivative assets		$	537	$	721



		Derivative Liabilities
		Fair Value
	Balance Sheet Location	March 31, 2018		December 31, 2017
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	12,104	$	7,763
Long-term	Non-current derivative liability	164		—
Total derivative liabilities		$	12,268	$	7,763

Effect of Derivative Instruments Recognized in Income Statements, Derivative Instruments

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the three months ended March 31:



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2018			2017
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(6,762	)	$	14,731
Total		$	(6,762	)	$	14,731

_______________________


(1)	Amounts settled during the 2018 and 2017 periods include net payments of $2.1 million and $1.2 million, respectively.

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Available-for-sale Securities

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



	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	(In thousands)
Equity Securities:
March 31, 2018	$	830	$	—	$	132	$	698
December 31, 2017	$	830	$	102	$	—	$	932

Recurring Fair Value Measurements

The following tables set forth our recurring fair value measurements:



	March 31, 2018
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	2,897		$	1,294		$	(3,654	)	$	537
Liabilities	—		(11,422		)	(4,500		)	3,654			(12,268		)
Total commodity derivatives	—		(8,525		)	(3,206		)	—			(11,731		)
Equity securities	698		—			—			—			698
	$	698	$	(8,525	)	$	(3,206	)	$	—		$	(11,033	)



	December 31, 2017
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	2,137		$	3,344		$	(4,760	)	$	721
Liabilities	—		(8,973		)	(3,550		)	4,760			(7,763		)
Total commodity derivatives	$	—	$	(6,836	)	$	(206	)	$	—		$	(7,042	)
Equity securities	932		—			—			—			932
	$	932	$	(6,836	)	$	(206	)	$	—		$	(6,110	)

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,
	2018			2017
	(In thousands)
Beginning of period	$	(206	)	$	(7,122	)
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	(3,919		)	5,903
Settlements	919			617
End of period	$	(3,206	)	$	(602	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period	$	(3,000	)	$	6,520

_______________________


(1)	Commodity derivatives are reported in the Unaudited Condensed Consolidated Income Statements in gain (loss) on derivatives.

Schedule Of Quantitative Information About Unobservable Inputs

The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2018:



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil three-way collars	$	(4,457	)	Discounted cash flow	Forward commodity price curve	$0 - $9.41
Natural gas collar	$	(1	)	Discounted cash flow	Forward commodity price curve	$0.01 - $0.12
Natural gas three-way collars	$	1,252		Discounted cash flow	Forward commodity price curve	$0 - $0.28

_______________________


(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.

- Definition

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

+ References + Details

Equity (Tables)

3 Months Ended

Mar. 31, 2018

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the three months ended March 31:



	2018				2017
	(In thousands)
Unrealized loss on securities, before tax	$	(234	)		$	—
Tax expense	58			⁽¹⁾	—
Unrealized loss on securities, net of tax	$	(176	)		$	—

_______________________


(1)	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Reclassification Out of Accumulated Other Comprehensive Income

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



	Net Gains on Equity Securities
	2018				2017
	(In thousands)
Balance at December 31, 2017	$	63			$	—
Adjustment due to ASU 2018-02	13			⁽¹⁾	—
Balance at January 1:	76				—
Unrealized loss before reclassifications	(176		)	⁽¹⁾	—
Amounts reclassified from accumulated other comprehensive income	—				—
Net current-period other comprehensive income	(176		)		—
Balance at March 31:	$	(100	)		$	—

_______________________


(1)	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Industry Segment Information (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018
	Oil and Natural Gas		Contract Drilling		Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues: ⁽¹⁾
Oil and natural gas	$	103,099	$	—	$	—	$	—		$	—		$	103,099
Contract drilling	—		50,710		—		—			(4,721		)	45,989
Gas gathering and processing	—		—		74,650		—			(18,606		)	56,044
Total revenues	103,099		50,710		74,650		—			(23,327		)	205,132
Expenses:
Operating costs:
Oil and natural gas	37,152		—		—		—			(1,190		)	35,962
Contract drilling	—		35,954		—		—			(4,287		)	31,667
Gas gathering and processing	—		—		59,020		—			(17,416		)	41,604
Total operating costs	37,152		35,954		59,020		—			(22,893		)	109,233
Depreciation, depletion, and amortization	30,783		13,312		11,053		1,918			—			57,066
Total expenses	67,935		49,266		70,073		1,918			(22,893		)	166,299
Total operating income (loss) ⁽²⁾	35,164		1,444		4,577		(1,918		)	(434		)
General and administrative expense	—		—		—		(10,762		)	—			(10,762		)
Gain on disposition of assets	71		26		34		30			—			161
Loss on derivatives	—		—		—		(6,762		)	—			(6,762		)
Interest expense, net	—		—		—		(10,004		)	—			(10,004		)
Other	—		—		—		6			—			6
Income (loss) before income taxes	$	35,235	$	1,470	$	4,611	$	(29,410	)	$	(434	)	$	11,472

_______________________


(1)	The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.


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



	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, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income, or income taxes.

Basis of Preparation and Presentation Basis of Preparation and Presentation (Narrative) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Basis of Preparation and Presentation [Abstract]
Federal Statutory Income Tax Rate, Percent	24.50%	37.75%

Revenue from Contracts with Customers Revenue from Contracts with Customers (Revenue Impact of the Adoption of ASC606) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Adoption of ASC606 [Line Items]
Oil and natural gas revenues	$ 103,099	$ 87,598
Oil and natural gas operating costs	35,962	29,204
Oil and natural gas gross profit	67,137
Gas gathering and processing	56,044	50,941
Deferred tax expense	3,607	13,936
Net income	7,865	$ 15,929
Adjustments due to ASC606 [Member]
Adoption of ASC606 [Line Items]
Oil and natural gas revenues	(3,169)
Oil and natural gas operating costs	(3,169)
Oil and natural gas gross profit	0
Gas gathering and processing	1,192
Deferred tax expense	292
Net income	900
Amounts without the Adoption of ASC606 [Member]
Adoption of ASC606 [Line Items]
Oil and natural gas revenues	106,268
Oil and natural gas operating costs	39,131
Oil and natural gas gross profit	67,137
Gas gathering and processing	54,852
Deferred tax expense	3,315
Net income	$ 6,965

Revenue from Contracts with Customers Revenue from Contracts with Customers (Balance Sheet Impact of the Adoption of ASC606) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Item Effected [Line Items]
Prepaid expenses and other	$ 7,724		$ 6,233
Other assets	27,470	$ 27,028	16,230
Current portion of other long-term liabilities	14,587	15,750	13,002
Other long-term liabilities	104,286	109,940	100,203
Deferred income taxes	136,600	133,064	133,477
Retained earnings	805,993	798,128	$ 799,402
Mid-Stream [Member] \| Adjustments due to ASC606 [Member]
Item Effected [Line Items]
Prepaid expenses and other	50
Other assets	11,397	10,798
Current portion of other long-term liabilities	2,824	2,748
Other long-term liabilities	9,118	9,737
Deferred income taxes	(121)	(413)
Retained earnings	(374)
Adjustment to opening retained earnings, after tax		$ (1,274)
Mid-Stream [Member] \| Amounts without the Adoption of ASC606 [Member]
Item Effected [Line Items]
Prepaid expenses and other	7,674
Other assets	16,073
Current portion of other long-term liabilities	11,763
Other long-term liabilities	95,168
Deferred income taxes	136,479
Retained earnings	$ 805,619

Revenue from Contracts with Customers Revenue from Contracts with Customers (Revenue, Remaining Performance Obligation) (Details) - Mid-Stream [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($)
Minimum [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Term of Contract	4 years
Maximum [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Term of Contract	5 years
Demand fee contracts [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Impact to Revenue	$ 495
Demand fee contracts [Member] \| April - December 2018
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Impact to Revenue	3,777
Demand fee contracts [Member] \| 2019
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Impact to Revenue	2,632
Demand fee contracts [Member] \| 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Impact to Revenue	(3,781)
Demand fee contracts [Member] \| 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Impact to Revenue	(3,507)
Demand fee contracts [Member] \| 2022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining Impact to Revenue	$ 1,374

Revenue from Contracts with Customers Revenue from Contracts with Customers (Contract with Customer, Asset and Liability) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Jan. 01, 2018	Dec. 31, 2017
Adoption of ASC606 [Line Items]
Contract liability	$ 11,942			$ 0
Change in contract liabilities	1,192	$ 0
Mid-Stream [Member]
Adoption of ASC606 [Line Items]
Contract assets	11,447		$ 10,798
Change in contract assets	649
Contract liability	11,942		12,485
Change in contract liabilities	(543)
Contract liabilities, net	(495)		$ (1,687)
Mid-Stream [Member] \| Adjustments due to ASC606 [Member]
Adoption of ASC606 [Line Items]
Change in contract liabilities, net	$ 1,192

Revenue from Contracts with Customers Revenue from Contracts with Customer (Narrative) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($) contract	Jan. 01, 2018 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Retained earnings	$ 805,993	$ 798,128	$ 799,402
Number of Contracts, Daywork \| contract	32
Oil and Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenue Satisfied at Point in Time, Transfer of Control	Revenues from sales are recognized when the customer obtains control of the company’s product. For sales to other midstream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer.
Drilling [Member]
Segment Reporting Information [Line Items]
Revenue Satisfied over Time, Method Used	At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under the new standard will allow the company to recognize revenues associated with contract drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Such liabilities will generally only arise in relation to upfront mobilization fees which are paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue.
Revenue, Practical Expedient, Initial Application and Transition, Qualitative Assessment	The majority of contract drilling contracts have an original term of less than one year; however, there are a few contracts with a longer duration that are not material.
Mid-Stream [Member]
Segment Reporting Information [Line Items]
Revenue Satisfied over Time, Method Used	Contract terms can range from single month to extended term contracts spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.
Revenue, Practical Expedient, Initial Application and Transition, Qualitative Assessment	As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee.
Minimum [Member] \| Drilling [Member]
Segment Reporting Information [Line Items]
Contract Duration	6 months
Number of Days for Drilling of Wells	10 days
Minimum [Member] \| Mid-Stream [Member]
Segment Reporting Information [Line Items]
Contract Duration	5 years
Remaining Term of Contract	4 years
Maximum [Member] \| Drilling [Member]
Segment Reporting Information [Line Items]
Contract Duration	2 years
Number of Days for Drilling of Wells	90 days
Maximum [Member] \| Mid-Stream [Member]
Segment Reporting Information [Line Items]
Contract Duration	10 years
Remaining Term of Contract	5 years
Short-term Contract with Customer [Member] \| Drilling [Member]
Segment Reporting Information [Line Items]
Contract Duration	2 months
Long-term Contract with Customer [Member]
Segment Reporting Information [Line Items]
Number of Contracts, Daywork \| contract	6
Long-term Contract with Customer [Member] \| Drilling [Member]
Segment Reporting Information [Line Items]
Contract Duration	14 months
Adjustments due to ASC606 [Member] \| Oil and Natural Gas [Member]
Segment Reporting Information [Line Items]
Retained earnings		0
Adjustments due to ASC606 [Member] \| Drilling [Member]
Segment Reporting Information [Line Items]
Retained earnings		0
Adjustments due to ASC606 [Member] \| Mid-Stream [Member]
Segment Reporting Information [Line Items]
Retained earnings	$ (374)
Adjustment to opening retained earnings, before tax		(1,700)
Adjustment to opening retained earnings, after tax		$ (1,274)
Gathering service contracts [Member] \| Minimum [Member] \| Mid-Stream [Member]
Segment Reporting Information [Line Items]
Remaining Term of Contract	1 year
Gathering service contracts [Member] \| Maximum [Member] \| Mid-Stream [Member]
Segment Reporting Information [Line Items]
Remaining Term of Contract	15 years

Divestitures (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
Divestitures (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Mar. 31, 2017
Property, Plant and Equipment Impairment or Disposal [Abstract]
Proceeds from non-core oil and natural gas asset sales, net of related expenses	$ 21.7	$ 14.8

Earnings Per Share (Schedule of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings of basic earnings per common share	$ 7,865	$ 15,929
Income of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0	0
Earnings of diluted income per common share	$ 7,865	$ 15,929
Weighted shares of basic earnings per common share	51,730	50,293
Weighted shares of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	542	568
Weighted shares of diluted earnings per common share	52,272	50,861
Per-Share amount of basic earnings per common share	$ 0.15	$ 0.32
Per-Share amount of effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	0.00	(0.01)
Per-Share amount of diluted earnings per common share	$ 0.15	$ 0.31

Earnings Per Share (Schedule of Antidilutive Securities Excluded From Computation of Earnings Per Share) (Details) - Stock options and SARs - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	87,500	199,755
Average exercise price	$ 51.34	$ 48.79

Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accrued Liabilities [Abstract]
Interest payable	$ 17,560	$ 6,745
Lease operating expenses	11,570	11,819
Employee costs	9,754	19,521
Taxes	4,139	3,404
Third-party credits	2,051	2,240
Derivative settlements	1,527	0
Other	6,363	4,794
Total accrued liabilities	$ 52,964	$ 48,523

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Credit agreement with an average interest rate of 3.8% and 3.4% at March 31, 2018 and December 31, 2017, respectively	$ 147,700	$ 178,000
6.625% senior subordinated notes due 2021	650,000	650,000
Total principal amount	797,700	828,000
Less: unamortized discount	(2,085)	(2,234)
Less: debt issuance costs, net	(5,093)	(5,490)
Total long-term debt	$ 790,522	$ 820,276
Revolving credit facility interest rate	3.80%	3.40%
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 Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Asset retirement obligation (ARO) liability	$ 63,763		$ 69,444	$ 70,043	$ 70,170
Capital lease obligations	14,277		15,224
Workers' compensation	13,049		13,340
Contract liability	11,942		0
Separation benefit plans	7,087		6,524
Deferred compensation plan	5,472		5,390
Gas balancing liability	3,283		3,283
Other liabilities	118,873		113,205
Current portion of other long-term liabilities	14,587	$ 15,750	13,002
Other long-term liabilities	$ 104,286	$ 109,940	$ 100,203

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt And Other Long-Term Liabilities (Capital Leases) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Beginning April 1,
2018	$ 6,168
2019	6,168
2020	7,815
2021	579
Total future payments	20,730
Less payments related to:
Maintenance	5,428
Interest	1,025
Present value of future minimum payments	$ 14,277	$ 15,224

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
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
Payable assessment term for LIBOR	90 days
LIBOR interest rate plus one percent	LIBOR plus 1.00% plus a margin
Line of credit facility, amount outstanding	$ 147,700	$ 178,000
Current ratio of credit facility	1 to 1
Aggregate principal amount	$ 650,000	$ 650,000
Interest percentage of senior subordinated notes	6.625%
Debt instrument maturity date	May 15, 2021
Original debt issuance fees	$ 14,700
Senior notes repurchase price in percentage	101.00%
Estimated principal payments in year 1	$ 14,600
Estimated principal payments in year 2	41,900
Estimated principal payments in year 3	156,100
Estimated principal payments in year 4	653,200
Estimated principal payments in year 5	$ 2,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	$ 3,900
Capital Lease Obligations, Noncurrent	$ 10,400
Discount rate capital leases	4.00%
Maintenance	$ 5,428
Interest	1,025
Capital leases, future minimum payments, average annual payment	$ 4,200
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 (Schedule Of Asset Retirement Obligations) (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

ARO liability, January 1:

$ 69,444

$ 70,170

Accretion of discount

659

785

Liability incurred

118

658

Liability settled

(1,626)

(630)

Liability sold

(81)

(432)

Revision of estimates

^[1]

(4,751)

(508)

ARO liability, March 31:

63,763

70,043

Less current portion

1,477

3,243

Total long-term ARO

$ 62,286

$ 66,800

[1]	Plugging liability estimates were revised in both 2018 and 2017 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-Based Compensation (Schedule of Restricted Stock Awards and Stock Options) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Abstract]
Recognized stock compensation expense	$ 4.6	$ 2.6
Capitalized stock compensation cost for our oil and natural gas properties	1.3	0.4
Tax benefit on stock based compensation	$ 1.1	$ 1.0

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, 2018

Mar. 31, 2017

Time Vested [Member]

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

Shares granted

839,498

461,799

Estimated fair value (in millions)

^[1]

$ 16.1

$ 11.4

Time Vested [Member] | Employees [Member]

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

Shares granted

839,498

461,799

Estimated fair value (in millions)

^[1]

$ 16.1

$ 11.4

Percentage of shares granted expected to be distributed

95.00%

94.00%

Time Vested [Member] | Non-employee Directors [Member]

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

Shares granted

Estimated fair value (in millions)

^[1]

$ 0.0

Performance Shares [Member]

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

Shares granted

362,070

152,373

Estimated fair value (in millions)

^[1]

$ 7.3

$ 4.0

Performance Shares [Member] | Employees [Member]

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

Shares granted

362,070

152,373

Estimated fair value (in millions)

^[1]

$ 7.3

$ 4.0

Percentage of shares granted expected to be distributed

63.00%

105.00%

Performance Shares [Member] | Non-employee Directors [Member]

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

Shares granted

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 (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	May 06, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$ 27.4
Unrecognized compensation cost, expected to be capitalized	$ 3.5
Weighted average years over which this cost will be recognized	1 year
Increase in stock compensation expense due to the restricted stock awards granted	$ 1.1
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			7,230,000
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	839,498	461,799
Performance Shares [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	362,070	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
2018 [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	27.00%
2017 [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	93.00%
2016 [Member] \| Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	164.00%

Derivatives (Schedule of Derivatives Outstanding) (Details)

3 Months Ended

Mar. 31, 2018

$ / Unit

MMBTU

bbl

Swap [Member] | Apr'18 - Sep'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]

Derivative [Line Items]

Weighted average price

2.985

Hedged volume (MMBtu/day) | MMBTU

40,000

Swap [Member] | Apr'18 - Sep'18 [Member] | Natural Gas Liquids [Member] | OPIS - Mont Belvieu [Member]

Derivative [Line Items]

Weighted average price

32.140

^[1]

Hedged NGLs volume (Bbl/day) | bbl

1,500

^[1]

Swap [Member] | Oct'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]

Derivative [Line Items]

Weighted average price

3.005

Hedged volume (MMBtu/day) | MMBTU

30,000

Swap [Member] | Nov'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

Swap [Member] | Apr'18 - Dec'18 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]

Derivative [Line Items]

Weighted average price

53.520

Hedged volume (Bbl/day) | bbl

4,000

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

Basis swap [Member] | Apr'18 - Oct'18 [Member] | Natural Gas [Member] | NGPL Midcon [Member]

Derivative [Line Items]

Weighted average price

(0.190)

Hedged volume (MMBtu/day) | MMBTU

10,000

Basis swap [Member] | Apr'18 - Dec'18 [Member] | Natural Gas [Member] | NGPL Midcon [Member]

Derivative [Line Items]

Weighted average price

(0.568)

Hedged volume (MMBtu/day) | MMBTU

10,000

Basis swap [Member] | Apr'18 - Dec'18 [Member] | Natural Gas [Member] | PEPL [Member]

Derivative [Line Items]

Weighted average price

(0.678)

Hedged volume (MMBtu/day) | MMBTU

10,000

Basis swap [Member] | Jan'19 - Dec'19 [Member] | Natural Gas [Member] | NGPL Midcon [Member]

Derivative [Line Items]

Weighted average price

(0.625)

Hedged volume (MMBtu/day) | MMBTU

10,000

Basis swap [Member] | Jan'19 - Dec'19 [Member] | Natural Gas [Member] | NGPL Texok [Member]

Derivative [Line Items]

Weighted average price

(0.265)

Hedged volume (MMBtu/day) | MMBTU

30,000

Basis swap [Member] | Jan'19 - Dec'19 [Member] | Natural Gas [Member] | PEPL [Member]

Derivative [Line Items]

Weighted average price

(0.728)

Hedged volume (MMBtu/day) | MMBTU

10,000

Basis swap [Member] | Jan'20 - Dec'20 [Member] | Natural Gas [Member] | NGPL Texok [Member]

Derivative [Line Items]

Weighted average price

(0.280)

Hedged volume (MMBtu/day) | MMBTU

20,000

Collar [Member] | Apr'18 - Sep'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]

Derivative [Line Items]

Hedged volume (MMBtu/day) | MMBTU

30,000

Cap Price

2.97

Floor Price

2.67

Three-way collar [Member] | Apr'18 - Dec'18 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]

Derivative [Line Items]

Hedged volume (Bbl/day) | bbl

2,000

Cap Price

56.08

Subfloor price

37.50

Floor Price

47.50

Three-way collar [Member] | Apr'18 - Dec'18 [Member] | Natural Gas [Member] | IF - NYMEX (HH) [Member]

Derivative [Line Items]

Hedged volume (MMBtu/day) | MMBTU

20,000

Cap Price

3.51

Subfloor price

2.50

Floor Price

3.00

[1]	Type of NGLs involved is propane.

Derivatives Derivatives (Schedule of Subsequent Derivatives Outstanding) (Details)	1 Months Ended	3 Months Ended
	May 03, 2018 $ / Unit MMBTU bbl	Mar. 31, 2018 $ / Unit MMBTU
Basis swap [Member] \| NGPL Texok [Member] \| Jan'20 - Dec'20 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) \| MMBTU		20,000
Weighted average price		(0.280)
Basis swap [Member] \| NGPL Texok [Member] \| Jan'19 - Dec'19 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) \| MMBTU		30,000
Weighted average price		(0.265)
Basis swap [Member] \| Subsequent Event [Member] \| NGPL Texok [Member] \| Jan'20 - Dec'20 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Hedged volume (MMBtu/day) \| MMBTU	10,000
Weighted average price	(0.265)
Three-way collar [Member] \| Subsequent Event [Member] \| WTI - NYMEX [Member] \| Jan'19 - Dec'19 [Member] \| Crude Oil [Member]
Derivative [Line Items]
Hedged volume (Bbl/day) \| bbl	1,000
Subfloor price	45.00
Floor Price	55.00
Cap Price	70.25

Derivatives (Fair Value of Derivative Instruments and Locations in Balance Sheets) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative asset	$ 537	$ 721
Non-current derivative asset	0	0
Total derivatives assets	537	721
Current derivative liability	(12,104)	(7,763)
Non-current derivative liability	(164)	0
Total derivative liabilities	$ (12,268)	$ (7,763)

Derivatives (Effect of Derivative Instruments Recognized in Income Statements, Derivative Instruments) (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) on derivatives

$ (6,762)

$ 14,731

Commodity Derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) on derivatives

(6,762)

14,731

Amount of loss settled during the period

(2,100)

(1,200)

Gain (loss) on derivatives [Member] | Commodity Derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) on derivatives

^[1]

$ (6,762)

$ 14,731

[1]	Amounts settled during the 2018 and 2017 periods include net payments of $2.1 million and $1.2 million, respectively.

Fair Value Measurements Fair Value Measurements (Fair Value of Available-for-sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Fair Value Measurements [Abstract]
Cost	$ 830	$ 830
Gross unrealized gains	0	102
Gross unrealized losses	$ 132	0
Estimated fair value		$ 932

Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 537	$ 721
Derivative Liability	(12,268)	(7,763)
Equity securities		932
Financial assets (liabilities)	(11,033)	(6,110)
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	698	932
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	(8,525)	(6,836)
Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	(3,206)	(206)
Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	0	0
Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	537	721
Derivative Liability	(12,268)	(7,763)
Total commodity derivatives	(11,731)	(7,042)
Commodity Derivatives [Member] \| Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	0	0
Gross Liabilities	0	0
Total commodity derivatives	0	0
Commodity Derivatives [Member] \| Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	2,897	2,137
Gross Liabilities	(11,422)	(8,973)
Total commodity derivatives	(8,525)	(6,836)
Commodity Derivatives [Member] \| Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Assets	1,294	3,344
Gross Liabilities	(4,500)	(3,550)
Total commodity derivatives	(3,206)	(206)
Commodity Derivatives [Member] \| Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Effect of netting on assets	(3,654)	(4,760)
Effect of netting on liabilities	3,654	4,760
Total commodity derivatives	0	0
Available-for-sale Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	698	932
Available-for-sale Securities [Member] \| Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	698	932
Available-for-sale Securities [Member] \| Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	0	0
Available-for-sale Securities [Member] \| Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	0	0
Available-for-sale Securities [Member] \| Effect of Netting [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	$ 0	$ 0

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

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

Beginning of period

$ (206)

$ (7,122)

Included in earnings

^[1]

(3,919)

5,903

Settlements

919

617

End of period

(3,206)

(602)

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

$ (3,000)

$ 6,520

[1]	Commodity derivatives are reported in the Unaudited Condensed Consolidated Income Statements in gain (loss) on derivatives.

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

3 Months Ended

Mar. 31, 2018

USD ($)

$ / Unit

^[1]

Oil [Member] | Three-way collar [Member]

Derivative fair value | $

$ (4,457)

Derivatives Valuation Technique(s)

Discounted cash flow

Unobservable Input

Forward commodity price curve

Oil [Member] | Three-way collar [Member] | Minimum [Member]

Forward commodity price curve

0.00

Oil [Member] | Three-way collar [Member] | Maximum [Member]

Forward commodity price curve

9.41

Natural Gas [Member] | Collar [Member]

Derivative fair value | $

$ (1)

Derivatives Valuation Technique(s)

Discounted cash flow

Unobservable Input

Forward commodity price curve

Natural Gas [Member] | Collar [Member] | Minimum [Member]

Forward commodity price curve

0.01

Natural Gas [Member] | Collar [Member] | Maximum [Member]

Forward commodity price curve

0.12

Natural Gas [Member] | Three-way collar [Member]

Derivative fair value | $

$ 1,252

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

0.00

Natural Gas [Member] | Three-way collar [Member] | Maximum [Member]

Forward commodity price curve

0.28

[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 (Narrative) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral posted	$ 0
Line of credit facility, amount outstanding	147,700	$ 178,000
6.625% senior subordinated notes due 2021	642,800	642,300
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Estimated fair value of long-term debt	$ 632,900	$ 649,700

- Definition

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

+ References + Details

Commitments and Contingencies (Narrative) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
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	900,000
Operating Leases, Future Minimum Payments, Due in Three Years	400,000
Operating Leases, Future Minimum Payments, Due in Four Years	100,000
Operating Leases, Rent Expense, Net	$ 2,300,000	$ 2,100,000
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	7,815,000
Capital Leases, Future Minimum Payments Due in Four Years	579,000
Maintenance	5,428,000
Interest	1,025,000
Capital leases, future minimum payments, average annual payment	$ 4,200,000
Capital lease fair market value percentage for purchase	10.00%
Percentage of repurchase of limited units outstanding	20.00%
Repurchase Of Limited Units Outstanding Amount	$ 0	$ 0
Drilling Equipment [Member]
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$ 3,429,000

Equity (Schedule of Accumulated Other Comprehensive Income) (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Schedule of Accumulated Other Comprehensive Income (Loss) [Abstract]

Unrealized loss on securities, before tax

$ (234)

$ 0

Tax expense

^[1]

Unrealized loss on securities, net of tax

$ (176)

$ 0

[1]	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Equity (Reclassification out of Accumulated Other Comprehensive Income) (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Jan. 01, 2018

Dec. 31, 2016

New Accounting Pronouncement, Early Adoption [Line Items]

Beginning Balance

$ 63

$ 0

Balance after adjustment

$ 76

$ 0

Unrealized loss before reclassifications

(176)

^[1]

Amounts reclassified from accumulated other comprehensive income

Net current-period other comprehensive income

(176)

Ending Balance

$ (100)

$ 0

ASU 2018-02 effect

New Accounting Pronouncement, Early Adoption [Line Items]

Adjustment due to ASU 2018-02

^[1]

ASU 2018-02 end balance

New Accounting Pronouncement, Early Adoption [Line Items]

Adjustment due to ASU 2018-02

$ 0

Balance after adjustment

$ 76

[1]	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Apr. 04, 2017
Class of Stock [Line Items]
Common stock, par value	$ 0.20	$ 0.20
Common stock, shares issued	54,046,361	52,880,134
At-the-Market Common Stock Program [Member]
Class of Stock [Line Items]
Common stock, par value			$ 0.20
Aggregate Offering Price			$ 100,000
Commission of the gross sales price by share paid percentage			2.00%
Common stock, shares issued	787,547
Proceeds from issuance of common stock, net of issuance costs	$ 18,623

Industry Segment Information (Industry Segment Information) (Details) - USD ($)
$ in Thousands

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Revenues:

Oil and natural gas

$ 103,099

$ 87,598

Contract drilling

45,989

37,185

Gas gathering and processing

56,044

50,941

Total revenues

205,132

175,724

Operating costs:

Oil and natural gas

35,962

29,204

Contract drilling

31,667

29,227

Gas gathering and processing

41,604

37,704

Total operating costs

109,233

96,135

Depreciation, depletion, and amortization

57,066

46,932

Total expenses

166,299

143,067

General and administrative expense

(10,762)

(8,954)

Gain on disposition of assets

161

824

Gain (loss) on derivatives

(6,762)

14,731

Interest expense, net

(10,004)

(9,396)

Other

Income (loss) before income taxes

11,472

29,865

Oil and Natural Gas [Member]

Revenues:

Oil and natural gas

103,099

^[1]

87,598

Contract drilling

^[1]

Gas gathering and processing

^[1]

Total revenues

103,099

^[1]

87,598

Operating costs:

Oil and natural gas

37,152

30,326

Contract drilling

Gas gathering and processing

Total operating costs

37,152

30,326

Depreciation, depletion, and amortization

30,783

21,526

Total expenses

67,935

51,852

Total operating income (loss)

35,164

^[2]

35,746

^[3]

General and administrative expense

Gain on disposition of assets

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

35,235

35,755

Drilling [Member]

Revenues:

Oil and natural gas

^[1]

Contract drilling

50,710

^[1]

37,185

Gas gathering and processing

^[1]

Total revenues

50,710

^[1]

37,185

Operating costs:

Oil and natural gas

Contract drilling

35,954

29,227

Gas gathering and processing

Total operating costs

35,954

29,227

Depreciation, depletion, and amortization

13,312

12,847

Total expenses

49,266

42,074

Total operating income (loss)

1,444

^[2]

(4,889)

^[3]

General and administrative expense

Gain on disposition of assets

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

1,470

(4,882)

Mid-Stream [Member]

Revenues:

Oil and natural gas

^[1]

Contract drilling

^[1]

Gas gathering and processing

74,650

^[1]

66,464

Total revenues

74,650

^[1]

66,464

Operating costs:

Oil and natural gas

Contract drilling

Gas gathering and processing

59,020

52,105

Total operating costs

59,020

52,105

Depreciation, depletion, and amortization

11,053

10,818

Total expenses

70,073

62,923

Total operating income (loss)

4,577

^[2]

3,541

^[3]

General and administrative expense

Gain on disposition of assets

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

4,611

3,541

Other Segments [Member]

Revenues:

Oil and natural gas

^[1]

Contract drilling

^[1]

Gas gathering and processing

^[1]

^[1]

Gas gathering and processing

Total operating costs

Depreciation, depletion, and amortization

1,918

1,741

Total expenses

1,918

1,741

Total operating income (loss)

(1,918)

^[2]

(1,741)

^[3]

General and administrative expense

(10,762)

(8,954)

Gain on disposition of assets

808

Gain (loss) on derivatives

(6,762)

14,731

Interest expense, net

(10,004)

(9,396)

Other

Income (loss) before income taxes

(29,410)

(4,549)

Eliminations [Member]

Revenues:

Oil and natural gas

Contract drilling

(4,721)

Gas gathering and processing

(18,606)

(15,523)

Total revenues

(23,327)

(15,523)

Operating costs:

Oil and natural gas

(1,190)

(1,122)

Contract drilling

(4,287)

Gas gathering and processing

(17,416)

(14,401)

Total operating costs

(22,893)

(15,523)

Depreciation, depletion, and amortization

Total expenses

(22,893)

(15,523)

Total operating income (loss)

(434)

^[2]

^[3]

General and administrative expense

Gain on disposition of assets

Gain (loss) on derivatives

Interest expense, net

Other

Income (loss) before income taxes

$ (434)

$ 0

[1]	The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
[2]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, loss on derivatives, interest expense, other income, or income taxes.
[3]	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, gain on derivatives, interest expense, other income, or income taxes.

Subsequent Events (Narrative) (Details) - USD ($) $ in Thousands	May 02, 2018	Apr. 03, 2018	Apr. 02, 2018	Mar. 31, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Credit facility maximum credit amount				$ 875,000
Common stock, shares issued				54,046,361	52,880,134
Line of credit facility, amount outstanding				$ 147,700	$ 178,000
Fourth Amendment to Credit Agreement [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Subsequent Event, Date			Apr. 02, 2018
Subsequent Event, Description			the company, including certain of its subsidiaries signed a Fourth Amendment to our Senior Credit Agreement (Fourth Amendment)
Credit facility maximum credit amount		$ 425,000	$ 475,000
Superior 50% ownership interest sale \| Subsequent Event [Member]
Subsequent Event [Line Items]
Subsequent Event, Date		Apr. 03, 2018
Subsequent Event, Description		The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager (Purchaser)
Ownership interest sold		50.00%
Cash consideration received		$ 300,000
Line of credit facility, amount outstanding		0
ATM Distribution Agreement [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Subsequent Event, Date	May 02, 2018
Subsequent Event, Description	we terminated the Distribution Agreement dated April 4, 2017, as amended (the Distribution Agreement), between the company and Raymond James & Associates, Inc. (the Sales Agent)
Common stock, shares issued	787,547
Line Of Credit Facility Lender Determined Amount [Member]
Subsequent Event [Line Items]
Credit facility current credit amount				475,000
Line Of Credit Facility Lender Determined Amount [Member] \| Fourth Amendment to Credit Agreement [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Credit facility current credit amount		425,000	525,000
Line Of Credit Facility Commitment Amount [Member]
Subsequent Event [Line Items]
Credit facility current credit amount				$ 475,000
Line Of Credit Facility Commitment Amount [Member] \| Fourth Amendment to Credit Agreement [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Credit facility current credit amount		$ 425,000	$ 475,000