Carrizo Oil & Gas (CRZO) 10-K 28 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ / shares in Units, $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	CARRIZO OIL & GAS INC
Entity Central Index Key	1,040,593
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		81,469,593
Share Price			$ 17.42
Entity Public Float			$ 1.1
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 9,540,000	$ 4,194,000
Accounts receivable, net	107,441,000	64,208,000
Other current assets	5,897,000	4,586,000
Total current assets	122,878,000	72,988,000
Oil and gas properties, full cost method
Proved properties, net	1,965,347,000	1,294,667,000
Unproved properties, not being amortized	660,287,000	240,961,000
Other property and equipment, net	10,176,000	10,132,000
Total property and equipment, net	2,635,810,000	1,545,760,000
Other assets	19,616,000	7,579,000
Total Assets	2,778,304,000	1,626,327,000
Current liabilities
Accounts payable	74,558,000	55,631,000
Revenues and royalties payable	52,154,000	38,107,000
Accrued capital expenditures	119,452,000	36,594,000
Accrued interest	28,362,000	22,016,000
Accrued lease operating expense	18,223,000	12,377,000
Derivative liabilities	57,121,000	22,601,000
Other current liabilities	22,952,000	24,633,000
Total current liabilities	372,822,000	211,959,000
Long-term debt	1,629,209,000	1,325,418,000
Asset retirement obligations	23,497,000	20,848,000
Derivative liabilities	112,332,000	27,528,000
Deferred income taxes	3,635,000	0
Other liabilities	51,650,000	17,116,000
Liabilities	2,193,145,000	1,602,869,000
Commitments and contingencies
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262,000	0
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 81,454,621 issued and outstanding as of December 31, 2017 and 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016	815,000	651,000
Additional paid-in capital	1,926,056,000	1,665,891,000
Accumulated deficit	(1,555,974,000)	(1,643,084,000)
Total shareholders’ equity	370,897,000	23,458,000
Total Liabilities and Shareholders’ Equity	$ 2,778,304,000	$ 1,626,327,000

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0
Temporary Equity, Shares Authorized	10,000,000	0
Temporary Equity, Shares Issued	250,000	0
Temporary Equity, Shares Outstanding	250,000	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	180,000,000	90,000,000
Common stock, shares issued (in shares)	81,454,621	65,132,499
Common stock, shares outstanding (in shares)	81,454,621	65,132,499

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Crude oil revenue	$ 633,233	$ 378,073	$ 376,094
Natural gas liquids revenue	47,405	22,428	15,608
Natural gas revenue	65,250	43,093	37,501
Total revenues	745,888	443,594	429,203
Costs and Expenses
Lease operating	139,854	98,717	90,052
Production taxes	32,509	19,046	17,683
Ad valorem taxes	7,267	5,559	9,255
Depreciation, depletion and amortization	262,589	213,962	300,035
General and administrative, net	66,229	74,972	67,224
(Gain) loss on derivatives, net	59,103	49,073	(99,261)
Interest expense, net	80,870	79,403	69,195
Impairment of proved oil and gas properties	0	576,540	1,224,367
Loss on extinguishment of debt	4,170	0	38,137
Other expense, net	2,157	1,796	11,276
Total costs and expenses	654,748	1,119,068	1,727,963
OTHER INCOME AND EXPENSES
Income (Loss) From Continuing Operations Before Income Taxes	91,140	(675,474)	(1,298,760)
Income tax (expense) benefit	(4,030)	0	140,875
Income (Loss) From Continuing Operations	87,110	(675,474)	(1,157,885)
Income From Discontinued Operations, Net of Income Taxes	0	0	2,731
Net Income (Loss)	87,110	(675,474)	(1,155,154)
Dividends on preferred stock	(7,781)	0	0
Accretion on preferred stock	(862)	0	0
Net Income (Loss) Attributable to Common Shareholders	$ 78,467	$ (675,474)	$ (1,155,154)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Net income (loss) per share, basic (in dollars per share)	$ 1.07	$ (11.27)	$ (22.45)
Net Income (Loss) Attributable to Common Shareholders Per Common Share - Diluted
Net income (loss) per share, diluted (in dollars per share)	$ 1.06	$ (11.27)	$ (22.45)
Weighted Average Common Shares Outstanding
Basic (in shares)	73,421	59,932	51,457
Diluted (in shares)	73,993	59,932	51,457

Consolidated Statements Of Shar

Consolidated Statements Of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]
Total shareholders' equity at Dec. 31, 2014	$ 1,103,441	$ 461	$ 915,436	$ 187,544
Total shareholders' equity, shares at Dec. 31, 2014		46,127,924
Stock options exercised for cash	46	$ 0	46
Stock options exercised for cash, shares		2,433
Stock-based compensation expense	25,707		25,707
Issuance of common stock upon grants of employee stock awards or units	(144)	$ 6	(150)
Issuance of common stock upon grants of employee stock awards or units, shares		630,723
Sale of common stock, net of offering costs	470,158	$ 115	470,043
Sale of common stock, net of offering costs, shares		11,500,000
Dividends on preferred stock	0
Accretion on preferred stock	0
Other shareholders' equity	0	$ 1	(1)
Other shareholders' equity, shares		71,913
Net income (loss)	(1,155,154)			(1,155,154)
Total shareholders' equity at Dec. 31, 2015	444,054	$ 583	1,411,081	(967,610)
Total shareholders' equity, shares at Dec. 31, 2015		58,332,993
Stock-based compensation expense	31,194		31,194
Issuance of common stock upon grants of employee stock awards or units	(55)	$ 8	(63)
Issuance of common stock upon grants of employee stock awards or units, shares		799,506
Sale of common stock, net of offering costs	$ 223,739	$ 60	223,679
Sale of common stock, net of offering costs, shares	6,000,000	6,000,000
Dividends on preferred stock	$ 0
Accretion on preferred stock	0
Net income (loss)	(675,474)			(675,474)
Total shareholders' equity at Dec. 31, 2016	23,458	$ 651	1,665,891	(1,643,084)
Total shareholders' equity, shares at Dec. 31, 2016		65,132,499
Stock-based compensation expense	23,625		23,625
Issuance of common stock upon grants of employee stock awards or units	(34)	$ 8	(42)
Issuance of common stock upon grants of employee stock awards or units, shares		722,122
Sale of common stock, net of offering costs	$ 222,378	$ 156	222,222
Sale of common stock, net of offering costs, shares	15,600,000	15,600,000
Proceeds from Issuance of Warrants	$ 23,003		23,003
Dividends on preferred stock	(7,781)		(7,781)
Accretion on preferred stock	(862)		(862)
Net income (loss)	87,110			87,110
Total shareholders' equity at Dec. 31, 2017	$ 370,897	$ 815	$ 1,926,056	$ (1,555,974)
Total shareholders' equity, shares at Dec. 31, 2017		81,454,621

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows From Operating Activities
Net income (loss)	$ 87,110	$ (675,474)	$ (1,155,154)
(Income) loss from discontinued operations, net of income taxes	0	0	(2,731)
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities from continuing operations
Depreciation, depletion and amortization	262,589	213,962	300,035
Impairment of proved oil and gas properties	0	576,540	1,224,367
(Gain) loss on derivatives, net	59,103	49,073	(99,261)
Cash received for derivative settlements, net	7,773	119,369	194,296
Loss on extinguishment of debt	4,170	0	38,137
Stock-based compensation expense, net	14,309	36,086	14,729
Deferred income taxes	3,635	0	(140,875)
Non-cash interest expense, net	3,657	4,172	4,289
Other, net	2,337	3,753	5,709
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(41,630)	(12,836)	29,781
Accounts payable	11,822	(30,130)	(12,617)
Accrued liabilities	11,512	(7,938)	(17,517)
Other assets and liabilities, net	(3,406)	(3,809)	(4,453)
Net cash provided by operating activities from continuing operations	422,981	272,768	378,735
Net cash used in operating activities from discontinued operations	0	0	(1,368)
Net cash provided by operating activities	422,981	272,768	377,367
Cash Flows From Investing Activities
Capital expenditures	(654,711)	(480,929)	(675,952)
Acquisitions of oil and gas properties	(695,774)	(153,521)	(1,817)
Net proceeds from divestitures of oil and gas properties	197,564	15,564	8,047
Other, net	(6,531)	(946)	(3,654)
Net cash used in investing activities from continuing operations	(1,159,452)	(619,832)	(673,376)
Net cash used in investing activities from discontinued operations	0	0	(2,678)
Net cash used in investing activities	(1,159,452)	(619,832)	(676,054)
Cash Flows From Financing Activities
Issuance of senior notes	250,000	0	650,000
Tender and redemptions of senior notes	(152,813)	0	(626,681)
Payment of deferred purchase payment	0	0	(150,000)
Borrowings under credit agreement	1,992,523	770,291	1,126,860
Repayments of borrowings under credit agreement	(1,788,223)	(683,291)	(1,126,860)
Payments of debt issuance costs and credit facility amendment fees	(9,051)	(1,330)	(12,420)
Sale of common stock, net of offering costs	222,378	223,739	470,158
Sale of preferred stock, net of offering costs	236,404	0	0
Payment of dividends on preferred stock	(7,781)	0	0
Proceeds from stock options exercised	0	0	46
Other, net	(1,620)	(1,069)	(336)
Net cash provided by financing activities from continuing operations	741,817	308,340	330,767
Net cash provided by financing activities from discontinued operations	0	0	0
Net cash provided by financing activities	741,817	308,340	330,767
Net Increase (Decrease) in Cash and Cash Equivalents	5,346	(38,724)	32,080
Cash and Cash Equivalents, Beginning of Year	4,194	42,918	10,838
Cash and Cash Equivalents, End of Year	$ 9,540	$ 4,194	$ 42,918

Nature Of Operations

Nature Of Operations	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature Of Operations	1. Nature of Operations Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued. Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of derivative assets and liabilities, fair values of contingent consideration, preferred stock fair value upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock. Cash and Cash Equivalents Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $62.6 million and $34.3 million as of December 31, 2017 and 2016 , respectively. Accounts Receivable As of December 31, 2017 payables due to related parties were less than $0.1 million and as of December 31, 2016 , receivables due from related parties were $0.9 million . The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. As of December 31, 2017 and 2016 , the Company’s allowance for doubtful accounts was $0.4 million and $0.8 million , respectively. Concentration of Credit Risk The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners. Major Customers Shell Trading (US) Company accounted for approximately 69% , 56% , and 65% of the Company’s total revenues in 2017 , 2016 , and 2015 , respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 7% , 15% and 9% of the Company’s total revenues in 2017 , 2016 and 2015 , respectively. Oil and Gas Properties Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity and totaled $14.8 million , $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015 , respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred. Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Boe of proved oil and gas properties was $13.09 , $13.50 and $22.05 for the years ended December 31, 2017, 2016 and 2015 , respectively. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds are assessed on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs along with associated capitalized interest are reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The Company capitalized interest costs to unproved properties totaling $28.3 million , $17.0 million and $32.1 million for the years ended December 31, 2017, 2016 and 2015 , respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10% , (b) the costs of unproved properties not being amortized, and (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment. The Company did not recognize impairments of proved oil and gas properties for the year ended December 31, 2017. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million , due primarily to declines in the 12-Month Average Realized Price of crude oil. Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2017 , 2016 and 2015 , the Company did not have any sales of oil and gas properties that significantly altered such relationship. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties.” Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years. Debt Issuance Costs Debt issuance costs associated with the revolving credit facility are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. Debt issuance costs associated with the revolving credit facility are classified in “Other assets” in the consolidated balance sheets while the debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets. Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.” Asset Retirement Obligations The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities from continuing operations in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.” Commitments and Contingencies Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies.” Revenue Recognition Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2017 and 2016 , the Company did not have any material production imbalances. Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 11. Derivative Instruments” for further discussion of the Company’s commodity derivative instruments. The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed certain thresholds during certain specified periods in the future. These contingent consideration liabilities and assets are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheet, with subsequent changes in fair value recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further discussion of the contingent consideration. Preferred Stock and Warrants The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets. When preferred stock is issued in conjunction with warrants, the warrants are evaluated separately as a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the warrants for equity classification and have determined the warrants qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The warrants do not require further adjustments from their relative fair value at the issuance date. Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows. See “Note 9. Preferred Stock and Warrants” for further details of the Company’s outstanding preferred stock and warrants. Stock-Based Compensation The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See “Note 10. Shareholders’ Equity and Stock Based Compensation” for further details of the awards discussed below. Restricted Stock Awards and Units . Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. Stock Appreciation Rights. For SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months and have an exercise price in excess of the market price at the end of the reporting period, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. If SARs expire unexercised, the cumulative compensation costs associated with the unexercised SARs will be zero. Performance Share Awards. For performance share awards, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved. Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized. Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance share awards in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. Supplemental net income (loss) attributable to common shareholders per common share information is provided below: Years Ended December 31, 2017 2016 2015 (In thousands, except per share amounts) Net Income (Loss) Attributable to Common Shareholders $78,467 ($675,474 ) ($1,155,154 ) Basic weighted average common shares outstanding 73,421 59,932 51,457 Effect of dilutive instruments 572 — — Diluted weighted average common shares outstanding 73,993 59,932 51,457 Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.07 ($11.27 ) ($22.45 ) Diluted $1.06 ($11.27 ) ($22.45 ) When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented: Years Ended December 31, 2017 2016 2015 (In thousands) Dilutive 572 — — Anti-dilutive 52 669 649 Recently Adopted Accounting Pronouncement Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption. Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero . Effective January 1, 2017, all windfall tax benefits and tax shortfalls are recorded as income tax expense or benefit in the consolidated statements of operations, whereas prior to adoption, windfall tax benefits were recorded as an increase to additional paid-in capital. In addition, windfall tax benefits, along with tax shortfalls, are now required to be classified as an operating cash flow as opposed to a financing cash flow. Further, the Company has elected to account for forfeitures of share-based payment awards as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings. Recently Issued Accounting Pronouncements Revenue From Contracts With Customers. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new 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 will adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company has performed an analysis of existing contracts and does not expect adoption to have a material impact on its consolidated financial statements, however, certain immaterial natural gas processing fees, which have historically been netted in revenue, will be recorded to lease operating expense. In addition, the Company has evaluated the expected changes to relevant business practices, accounting policies and control activities and does not expect to have a material change as a result of the adoption of ASU 2014-09. Business Combinations. In January 2017, the FASB issued ASU No. 2017

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures [Abstract]
Acquisitions and Divestitures Disclosures	3. Acquisitions and Divestitures of Oil and Gas Properties Acquisitions ExL Acquisition. On June 28, 2017, the Company entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) for an agreed upon price of $648.0 million , with an effective date of May 1, 2017, subject to customary purchase price adjustments (the “ExL Acquisition”). The Company paid $75.0 million as a deposit on June 28, 2017, $601.0 million upon closing on August 10, 2017 and $3.8 million upon post-closing on December 8, 2017, for an aggregate cash consideration of $679.8 million , which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. Upon closing the ExL Acquisition, the Company became the operator of the ExL Properties with an approximate 70% average working interest. The Company also agreed to pay an additional $50.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00 for any of the years of 2018, 2019, 2020 and 2021, with such payments due on January 29, 2019, January 28, 2020, January 28, 2021 and January 28, 2022, respectively. This payment (the “Contingent ExL Consideration”) will be zero for the respective year if such EIA WTI average price of a barrel of oil is $50.00 or below for any of such years, and the Contingent ExL Consideration is capped at $125.0 million in the aggregate. The Company determined that the Contingent ExL Consideration is an embedded derivative and has reflected the liability at fair value in non-current “Derivative liabilities” in the consolidated balance sheets. The fair value of the Contingent ExL Consideration as of December 31, 2017 and August 10, 2017 was $85.6 million and $52.3 million , respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details. The Company funded the ExL Acquisition with net proceeds from the sale of preferred stock on August 10, 2017, net proceeds from the common stock offering completed on July 3, 2017, and net proceeds from the senior notes offering completed on July 14, 2017. See “Note 9. Preferred Stock and Warrants” for details regarding the sale of Preferred Stock, “Note 10. Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering and “Note 6. Long-Term Debt” for details regarding the senior notes offering. The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note 12. Fair Value Measurements” for further details. The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $106 Oil and gas properties Proved properties 294,754 Unproved properties 443,194 Total oil and gas properties $737,948 Total assets acquired $738,054 Liabilities Revenues and royalties payable $5,785 Asset retirement obligations 153 Contingent ExL Consideration 52,300 Total liabilities assumed $58,238 Net Assets Acquired $679,816 Included in the consolidated statements of operations for the year ended December 31, 2017 are total revenues of $53.5 million and net income attributable to common shareholders of $44.3 million from the ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction. Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016 , assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition. Years Ended December 31, 2017 2016 (In thousands, except per share amounts) Total revenues $781,378 $454,913 Net Income (Loss) Attributable to Common Shareholders $91,931 ($688,180 ) Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.25 ($9.11 ) Diluted $1.24 ($9.11 ) Weighted Average Common Shares Outstanding Basic 73,421 75,532 Diluted 73,993 75,532 Sanchez Acquisition. On October 24, 2016, the Company entered into a purchase and sale agreement with Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation to acquire oil and gas properties located in the Eagle Ford Shale (the “Sanchez Acquisition”) for an agreed upon price of $181.0 million , with an effective date of June 1, 2016, subject to customary purchase price adjustments. The Company paid $10.0 million as a deposit on October 24, 2016, $143.5 million upon the initial closing on December 14, 2016, and $7.0 million and $9.8 million on January 9, 2017 and April 13, 2017, respectively, for leases that were not conveyed to the Company at the time of the initial closing, for aggregate cash consideration of $170.3 million , which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Sanchez Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then available information. The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $477 Oil and gas properties Proved properties 99,938 Unproved properties 74,536 Total oil and gas properties 174,474 Total assets acquired $174,951 Liabilities Revenues and royalties payable $1,442 Other current liabilities 323 Asset retirement obligations 2,054 Other liabilities 1,078 Total liabilities assumed $4,897 Net Assets Acquired $170,054 Included in the consolidated statements of operations for the year ended December 31, 2017 are total revenues of $37.8 million and net income attributable to common shareholders of $16.5 million from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction. Divestitures Utica. On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale, located primarily in Guernsey County, Ohio, for an agreed upon price of $62.0 million , with an effective date of April 1, 2017, subject to customary purchase price adjustments. On August 31, 2017, the Company received $6.2 million as a deposit, on November 15, 2017, the Company received $54.4 million at closing, subject to post-closing adjustments, and on December 28, 2017, the Company received $2.5 million , for aggregate net proceeds of $63.1 million , which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Company could also receive contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00 , $53.00 , and $56.00 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Utica Consideration”). The Contingent Utica Consideration will be zero for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years. The Company determined that the Contingent Utica Consideration is an embedded derivative and has reflected the asset at fair value in non-current “Other assets” in the consolidated balance sheets. The fair value of the Contingent Utica Consideration as of December 31, 2017 and November 15, 2017 was $8.0 million and $6.1 million , respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details. The aggregate net proceeds of $63.1 million were recognized as a reduction of proved oil and gas properties. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets. Marcellus. On October 5, 2017, the Company entered into a purchase and sale agreement with BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an agreed upon price of $84.0 million , with an effective date of April 1, 2017, subject to customary purchase price adjustments. On October 5, 2017, the Company received $6.3 million into escrow as a deposit and on November 21, 2017, the Company received $67.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $73.9 million , which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Company could also receive contingent consideration of $3.0 million per year if the average settlement prices of a MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc. (the “CME HH average price”) is above $3.13 , $3.18 , and $3.30 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Marcellus Consideration”). This conditional consideration will be zero for the respective year if such CME HH average price of a MMBtu of Henry Hub natural gas is at or below the per MMBtu amounts listed above for any of such years, and is capped at $7.5 million . The Company determined that the Contingent Marcellus Consideration is an embedded derivative and has reflected the asset at fair value in non-current “Other assets” in the consolidated balance sheets. The fair value of the Contingent Marcellus Consideration as of December 31, 2017 and November 21, 2017 was $2.2 million and $2.7 million , respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details. The aggregate net proceeds of $73.9 million were recognized as a reduction of proved oil and gas properties. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets. Simultaneous with the signing of the Marcellus Shale transaction discussed above, the Company’s existing joint venture partner in the Marcellus Shale, Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, entered into a purchase and sale agreement with BKV Chelsea, LLC to sell its interest in the same oil and gas properties. Simultaneous with the closing of these Marcellus Shale sale transactions, the agreements governing the Reliance joint venture were assigned to the buyer and, after giving effect to such transactions, the Reliance joint venture was terminated except for limited post-closing obligations. Niobrara. On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million , with an effective date of October 1, 2017, subject to customary purchase price adjustments. On November 20, 2017, the Company received $14.0 million as a deposit, which is refundable only in specified circumstances if the transaction is not consummated and is classified as “Other liabilities” in the consolidated balance sheets and as “Net proceeds from divestitures of oil and gas properties” in the cash flows from investing activities section in the consolidated statements of cash flows. On January 19, 2018, the Company received $122.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $136.6 million , which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Company could also receive contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $55.00 for the years of 2018 and 2019 and above $60.00 for 2020, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Niobrara Consideration”). The Contingent Niobrara Consideration will be zero for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years. Eagle Ford. On December 11, 2017, the Company entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of its assets in the Eagle Ford Shale for an agreed upon price of $245.0 million , with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. On December 11, 2017, the Company received $24.5 million as a deposit, which is refundable only in specified circumstances if the transaction is not consummated and is classified as “Other liabilities” in the consolidated balance sheets and as “Net proceeds from divestitures of oil and gas properties” in the cash flows from investing activities section in the consolidated statements of cash flows. On January 31, 2018, the Company received $211.7 million at closing, subject to post-closing adjustments, and on February 16, 2018, the Company received $10.0 million for leases that were not conveyed at closing, for aggregate net proceeds of $246.2 million , which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. In the first quarter of 2018, the aggregate net proceeds that were received for the Niobrara and Eagle Ford divestitures will be recognized as reductions of proved oil and gas properties and the Contingent Niobrara Consideration will be recognized as an asset at fair value in the Company's consolidated balance sheet. Other Assets. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million . The proceeds from this sale were recognized as a reduction of proved oil and gas properties.

Property And Equipment, Net

Property And Equipment, Net	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property And Equipment, Net	4. Property and Equipment, Net As of December 31, 2017 and 2016 , total property and equipment, net consisted of the following: December 31, 2017 2016 Oil and gas properties, full cost method (In thousands) Proved properties $5,615,153 $4,687,416 Accumulated DD&A and impairments (3,649,806 ) (3,392,749 ) Proved properties, net 1,965,347 1,294,667 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 612,589 211,067 Capitalized interest 47,698 29,894 Total unproved properties, not being amortized 660,287 240,961 Other property and equipment 25,625 23,127 Accumulated depreciation (15,449 ) (12,995 ) Other property and equipment, net 10,176 10,132 Total property and equipment, net $2,635,810 $1,545,760 Costs not subject to amortization totaling $660.3 million at December 31, 2017 were incurred in the following periods: $523.1 million in 2017 , $106.8 million in 2016 and $24.0 million in 2015 . Impairments of Proved Oil and Gas Properties The Company did not recognize impairments of proved oil and gas properties for the year ended December 31, 2017 . Primarily due to declines in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of proved oil and gas properties of $576.5 million and $1,224.4 million for the years ended December 31, 2016 and 2015 , respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	5. Income Taxes The components of income tax (expense) benefit from continuing operations were as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Current income tax (expense) benefit U.S. Federal $— $— $— State (395 ) — — Total current income tax (expense) benefit (395 ) — — Deferred income tax (expense) benefit U.S. Federal — — 131,502 State (3,635 ) — 9,373 Total deferred income tax (expense) benefit (3,635 ) — 140,875 Total income tax (expense) benefit from continuing operations ($4,030 ) $— $140,875 The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Income (loss) from continuing operations before income taxes $91,140 ($675,474 ) ($1,298,760 ) Income tax (expense) benefit at the statutory rate (31,899 ) 236,416 454,566 State income tax (expense) benefit, net of U.S. Federal income taxes (4,030 ) 3,894 9,373 Tax shortfalls from stock-based compensation expense (3,089 ) — — Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense — — 1,671 Provisional impact of Tax Cuts and Jobs Act (211,724 ) — — Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act 211,724 — — Change in valuation allowance from current year activity 35,376 (240,864 ) (323,586 ) Other (388 ) 554 (1,149 ) Income tax (expense) benefit ($4,030 ) $— $140,875 Significant changes in the Company’s operations in 2017, including the ExL Acquisition in the Delaware Basin and divestitures of substantially all of the Company's assets in the Utica and Marcellus Shales, resulted in changes to the Company's anticipated future state apportionment for estimated state deferred tax liabilities. As a result of these changes, the Company recorded a $3.6 million state deferred tax expense primarily associated with future Texas deferred tax liabilities. Deferred Income Taxes Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. As of December 31, 2017 and 2016 , deferred tax assets and liabilities are comprised of the following: December 31, 2017 2016 (In thousands) Deferred income tax assets Net operating loss carryforward - U.S. Federal and State $242,915 $221,063 Oil and gas properties 50,177 309,848 Asset retirement obligations 4,996 7,434 Stock-based compensation — 5,238 Derivative liabilities 35,585 17,545 Other 1,496 3,739 Deferred income tax assets 335,169 564,867 Deferred tax asset valuation allowance (333,029 ) (564,434 ) Net deferred income tax assets 2,140 433 Deferred income tax liabilities Oil and gas properties (3,635 ) — Derivative assets (2,140 ) (433 ) Net deferred income tax asset (liability) ($3,635 ) $— Tax Cuts and Jobs Act On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. The income tax effects of changes in tax laws are recognized in the period when enacted. While the Company continues to assess the impact of the tax reform legislation on its business and consolidated financial statements, the Company remeasured its deferred tax balances by applying the reduced rate and and recorded a provisional deferred tax expense of $211.7 million during the year ended December 31, 2017. This provisional deferred tax expense was fully offset by a $211.7 million deferred tax benefit as a result of the associated change in the valuation allowance against the net deferred tax assets. As reflected in the rate reconciliation above, the change in the deferred tax balances due to the rate reduction had no impact on the net deferred tax balances reported in the consolidated balance sheets as of December 31, 2017 and no impact in the consolidated statements of operations for the year ended December 31, 2017 . Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 (“SAB 118”) which allows the Company to provide a provisional estimate of the impacts of the Act in its earnings for the year ended December 31, 2017. The Company's estimate does not reflect changes in current interpretations of performance based executive compensation deduction limitations, effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform. The Company will continue to analyze the effects of the Act in its consolidated financial statements and operations. Additional impacts from the enactment of the Act will be recorded as they are identified during the one-year measurement period provided for in SAB 118. As of December 31, 2017, the Company has not completed its accounting for the tax effects of enactment of the Act; however, the Company has made a reasonable estimate of the effects on it existing deferred tax balances. Deferred Tax Assets Valuation Allowance Deferred tax assets are recorded for net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2017, driven primarily by the impairments of proved oil and gas properties recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the third quarter of 2015 and continuing through the fourth quarter of 2017, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including December 31, 2017 were reduced to zero . Effective January 1, 2017, the Company adopted ASU 2016-09, and the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017. For the year ended December 31, 2017 , the Company reduced the valuation allowance by $247.1 million . This was primarily due to the re-measurement of its deferred tax assets as a result of the Act as mentioned above as well as partial releases of $35.4 million , as a result of current year activity. After the impact of the re-measurement and the partial releases, the valuation allowance as of December 31, 2017 was $333.0 million , of which $12.7 million is a valuation allowance against state deferred tax assets. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes sufficient taxable income within the carryforward periods. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant federal deferred income tax expense or benefit. However, the Company currently expects to continue to have state deferred income tax expense or benefit as a result of change in state deferred tax liabilities as the Company's operations become more heavily weighted towards Texas. Net Operating Loss Carryforwards and Other Net Operating Loss Carryforwards. As of December 31, 2017 , the Company had U.S. federal net operating loss carryforwards of approximately $1,096.2 million . If not utilized in earlier periods, the U.S. federal net operating loss will expire between 2026 and 2037 . The ability of the Company to utilize its U.S. loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the Company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Due to the issuance of the Preferred Stock and the common stock offering associated with the ExL Acquisition, the Company’s calculated ownership change percentage increased, however, as of December 31, 2017, the Company does not believe it has a Section 382 limitation on the ability to utilize its U.S. loss carryforwards. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes and therefore a limitation on the annual utilization of the U. S. loss carryforwards. Other. The Company files income tax returns in the U.S. Federal jurisdiction and various states, each with varying statutes of limitations. The 1999 through 2017 tax years generally remain subject to examination by federal and state tax authorities. As of December 31, 2017 , 2016 and 2015 , the Company had no uncertain tax positions.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	6. Long-Term Debt Long-term debt consisted of the following as of December 31, 2017 and 2016 : December 31, 2017 2016 (In thousands) Senior Secured Revolving Credit Facility due 2022 $291,300 $87,000 7.50% Senior Notes due 2020 450,000 600,000 Unamortized premium for 7.50% Senior Notes 579 1,020 Unamortized debt issuance costs for 7.50% Senior Notes (4,492 ) (7,573 ) 6.25% Senior Notes due 2023 650,000 650,000 Unamortized debt issuance costs for 6.25% Senior Notes (8,208 ) (9,454 ) 8.25% Senior Notes due 2025 250,000 — Unamortized debt issuance costs for 8.25% Senior Notes (4,395 ) — Other long-term debt due 2028 4,425 4,425 Long-term debt $1,629,209 $1,325,418 Senior Secured Revolving Credit Facility The Company has a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2017 , had a borrowing base of $900.0 million , with an elected commitment amount of $800.0 million , and $291.3 million of borrowings outstanding at a weighted average interest rate of 3.73% . As of December 31, 2017 , the Company also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement. On May 4, 2017, the Company entered into a ninth amendment to the credit agreement governing the revolving credit facility to, among other things, (i) extend the maturity date of the revolving credit facility to May 4, 2022, subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced or redeemed on or prior to such time, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion , (iii) increase the borrowing base from $600.0 million to $900.0 million , with an elected commitment amount of $800.0 million , until the next redetermination thereof and (iv) amend certain financial covenants including replacing the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio and removing the minimum EBITDA to Interest Expense ratio. On June 28, 2017, the Company entered into a tenth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) amend the calculation of certain financial covenants to provide that EBITDA will be calculated on an annualized basis as of the end of each of the first three fiscal quarters commencing with the quarter ending September 30, 2017 and (ii) amend the restricted payments covenant. Upon issuance of the 8.25% Senior Notes (described below), in accordance with the credit agreement governing the revolving credit facility, the Company’s borrowing base was reduced by 25% of the aggregate principal amount of the 8.25% Senior Notes, reducing the Company’s borrowing base from $900.0 million to $837.5 million . On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $900.0 million , with an elected commitment amount of $800.0 million , until the next determination thereof, (ii) increase the general basket available for restricted payments from $50.0 million to $75.0 million and (iii) amend certain other provisions, in each case as set forth therein. The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination. Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00% , or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations. Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments Applicable Margin for Base Rate Loans Applicable Margin for Eurodollar Loans Commitment Fee Less than 25% 1.00% 2.00% 0.375% Greater than or equal to 25% but less than 50% 1.25% 2.25% 0.375% Greater than or equal to 50% but less than 75% 1.50% 2.50% 0.500% Greater than or equal to 75% but less than 90% 1.75% 2.75% 0.500% Greater than or equal to 90% 2.00% 3.00% 0.500% The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA for the fiscal quarter ended December 31, 2017 is calculated based on an annualized average of the last two fiscal quarters, EBITDA for the fiscal quarter ending March 31, 2018, will be calculated based on an annualized average of the last three fiscal quarters, and EBITDA for fiscal quarters ending thereafter will be calculated based on the last four fiscal quarters, in each case after giving pro forma effect to EBITDA for material acquisitions and dispositions of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of December 31, 2017 , the ratio of Total Debt to EBITDA was 2.59 to 1.00 and the Current Ratio was 1.98 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings. The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions and divestitures of oil and gas properties, mergers, transactions with affiliates, hedging transactions and other matters. The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). Senior Notes 8.25% Senior Notes due 2025. On July 14, 2017, the Company closed a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 (the “ 8.25% Senior Notes”). The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. The Company used the net proceeds of $245.4 million , net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition. 7.50% Senior Notes due 2020. On November 28, 2017, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes due 2020 (the “ 7.50% Senior Notes”) to call for redemption on December 28, 2017, $150.0 million aggregate principal amount of the 7.50% Senior Notes then outstanding. On December 28, 2017, the Company paid an aggregate redemption price of $156.0 million , which included a redemption premium of $2.8 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $150.0 million of the 7.50% Senior Notes, the Company recorded a loss on extinguishment of debt of $4.2 million , which includes the redemption premium paid to redeem the notes and non-cash charges of $1.3 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes. The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017. See “Note 15. Subsequent Events (Unaudited)” for further details of these redemptions. Since September 15, 2017, the Company has had the right to redeem all or a portion of the 7.50% Senior Notes at redemption prices decreasing from 101.875% to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest. 6.25% Senior Notes due 2023. Before April 15, 2018, the Company may, at its option, redeem all or a portion of the 6.25% Senior Notes due 2023 (the “ 6.25% Senior Notes”) at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 104.688% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest. If a Change of Control (as defined in the indentures governing the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. The indentures governing the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes contain covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments. At December 31, 2017 , the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	7. Asset Retirement Obligations The following table sets forth asset retirement obligations for the years ended December 31, 2017 and 2016 : Years Ended December 31, 2017 2016 (In thousands) Beginning of year asset retirement obligations $21,240 $16,511 Liabilities incurred 3,920 2,137 Increase due to acquisition of oil and gas properties 153 2,037 Liabilities settled (343 ) (599 ) Reduction due to divestitures of oil and gas properties (2,671 ) — Accretion expense 1,799 1,364 Revisions to estimated cash flows (306 ) (210 ) End of year asset retirement obligations 23,792 21,240 Current asset retirement obligations (included in other current liabilities) (295 ) (392 ) Non-current asset retirement obligations $23,497 $20,848

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	8. Commitments and Contingencies From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. The results of operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, natural gas regulation, tax legislation, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable. Rent expense included in general and administrative expense for the years ended December 31, 2017 , 2016 and 2015 was $1.7 million , $2.0 million , and $2.2 million , respectively, and includes rent expense for the Company’s corporate office and field offices. The table below presents total minimum commitments associated with long-term, non-cancelable operating and capital leases, drilling rig contracts and gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered as of December 31, 2017 . The total minimum commitments related to the drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. 2018 2019 2020 2021 2022 2023 and Thereafter Total (In thousands) Operating leases $5,038 $4,895 $4,637 $4,450 $1,854 $— $20,874 Capital leases 1,823 1,800 1,050 — — — 4,673 Drilling rig contracts 23,885 8,881 — — — — 32,766 Delivery commitments 3,657 3,676 2,757 2,438 10 26 12,564 Total $34,403 $19,252 $8,444 $6,888 $1,864 $26 $70,877 In connection with the ExL Acquisition, the Company has agreed to a contingent payment of $50.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2021 with a cap of $125.0 million , which is not included in the table above. Contractual Obligations Executed Subsequent to December 31, 2017 In January and February 2018, the Company extended two of its drilling rig contracts for terms of one and two years. The gross contractual obligations for these extended drilling rig contracts are approximately $22.2 million . Additionally, in January and February 2018, the Company entered into four produced water disposal contracts for terms between five and six years, which require delivery of minimum volumes. The gross contractual obligations for these new produced water disposal contracts, which reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water, are approximately $111.6 million . The gross contractual obligations associated with these drilling rig and produced water disposal contracts are not included in the table above as they were entered into subsequent to December 31, 2017 .

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2017
Preferred Stock [Abstract]
Preferred Stock	9. Preferred Stock and Warrants On June 28, 2017, the Company entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”) to issue and sell in a private placement (i) $250.0 million initial liquidation preference ( 250,000 shares) of 8.875% redeemable preferred stock, par value $0.01 per share (the “Preferred Stock”) and (ii) warrants for 2,750,000 shares of the Company’s common stock, with a term of ten years and an exercise price of $16.08 per share, exercisable only on a net share settlement basis (the “Warrants”), for a cash purchase price equal to $970.00 per share of Preferred Stock. The Company paid the GSO Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement. The closing of the private placement occurred on August 10, 2017, contemporaneously with the closing of the ExL Acquisition. The Company used the net proceeds of approximately $236.4 million , net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. The Company also entered into a registration rights agreement with the GSO Funds at the closing of the private placement, which provided certain registration and other rights for the benefit of the GSO Funds. During the fourth quarter of 2017, the Company filed a registration statement with the SEC to register the resale of the Preferred Stock and the common stock that may be issued in respect of the Preferred Stock and that underlie the Warrants. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition. The Preferred Stock has a liquidation preference of $1,000.00 per share and bears an annual cumulative dividend rate of 8.875% , payable on March 15, June 15, September 15 and December 15 of any given year. The Company may elect to pay all or a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending: Period Percentage On or after December 15, 2017 and on or prior to September 15, 2018 100 % On or after December 15, 2018 and on or prior to September 15, 2019 75 % On or after December 15, 2019 and on or prior to September 15, 2020 50 % If the Company fails to satisfy the Preferred Stock dividend on the applicable dividend payment date, then the unpaid dividend will be added to the liquidation preference until paid. The Preferred Stock outstanding is not mandatorily redeemable, but can be redeemed at the Company’s option and, in certain circumstances, at the option of the holders of the Preferred Stock. On or prior to August 10, 2018, the Company had the right to redeem up to 50,000 shares of Preferred Stock, in cash, at $1,000.00 per share, plus accrued and unpaid dividends in an amount not to exceed the sum of the cash proceeds of divestitures of oil and gas properties and related assets, the sale or issuance of the Company’s common stock and the sale of any of the Company’s wholly owned subsidiaries. On January 24, 2018, the Company redeemed 50,000 shares of Preferred Stock for $50.5 million with a portion of the proceeds from the divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the divestitures of oil and gas properties. In addition, at any time on or prior to August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at a redemption premium of 104.4375% , plus accrued and unpaid dividends and the present value on the redemption date of all quarterly dividends that would be payable from the redemption date through August 10, 2020. After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends. Period Percentage After August 10, 2020 but on or prior to August 10, 2021 104.4375 % After August 10, 2021 but on or prior to August 10, 2022 102.21875 % After August 10, 2022 100 % The holders of the Preferred Stock have the option to cause the Company to redeem the Preferred Stock under the following conditions: • Upon the Company’s failure to pay a quarterly dividend within three months of the applicable payment date; • On or after August 10, 2024, if the Preferred Stock remain outstanding; or • Upon the occurrence of certain changes of control For the first two conditions described above, the Company has the option to settle any such redemption in cash or shares of its common stock and the holders of the Preferred Stock may elect to revoke or reduce the redemption if the Company elects to settle in shares of common stock. The Preferred Stock are non-voting shares except as required by the Company’s articles of incorporation or bylaws. However, so long as the GSO Funds beneficially own more than 50% of the Preferred Stock, the consent of the holders of the Preferred Stock will be required prior to issuing stock senior to or on parity with the Preferred Stock, incurring indebtedness subject to a leverage ratio, agreeing to certain restrictions on dividends on, or redemption of, the Preferred Stock and declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year subject to a leverage ratio. Additionally, if the Company does not redeem the Preferred Stock before August 10, 2024, in connection with a change of control or failure to pay a quarterly dividend within three months of the applicable payment date, the holders of the Preferred Stock are entitled to additional rights including: • Increasing the dividend rate to 12.0% per annum until August 10, 2024 and thereafter to the greater of 12.0% per annum and the one-month LIBOR plus 10.0% ; • Causing the election of up to two directors to the Company’s Board of Directors; and • Requiring approval by the holders of the Preferred Stock to incur indebtedness subject to a leverage ratio, declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year or issuing equity of the Company’s subsidiaries to third parties. The table below summarizes Preferred Stock activity for the year ended December 31, 2017 : December 31, 2017 For the Year Ended December 31, 2017 Preferred Stock, beginning of period $— Relative fair value of Preferred Stock at issuance 213,400 Accretion of discount on Preferred Stock 862 Preferred Stock, end of period $214,262 Net proceeds were allocated between the Preferred Stock and the Warrants based on their relative fair values at the issuance date, with $213.4 million allocated to the Preferred Stock and $23.0 million allocated to the Warrants. The fair value of the Preferred Stock was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation of the Preferred Stock included the per share cash purchase price, redemption premiums, and liquidation preference, all as discussed above, as well as redemption assumptions provided by the Company. The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $16.08 Expected term (in years) 10.0 Expected volatility 62.9 % Risk-free interest rate 2.2 % Dividend yield — % See “Note 12. Fair Value Measurements” for further discussion of the significant inputs used in the Preferred Stock and Warrants fair value calculations. Preferred Stock Dividends and Accretion For the year ended December 31, 2017 , the Company declared and paid an aggregate of $7.8 million of dividends, in cash, to the holders of record of the Preferred Stock on September 1, 2017 and December 1, 2017. For the year ended December 31, 2017 , the Company recorded accretion of the Preferred Stock of $0.9 million , which is presented with the dividends in the consolidated statements of operations.

Shareholders' Equity And Stock

Shareholders' Equity And Stock Incentive Plan	12 Months Ended
	Dec. 31, 2017
Shareholders' Equity And Stock Incentive Plan [Abstract]
Shareholders' Equity And Stock Incentive Plan	10. Shareholders’ Equity and Stock Based Compensation Increase in Authorized Common Shares At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 90,000,000 to 180,000,000 . Sale of Common Stock On July 3, 2017, the Company completed a public offering of 15.6 million shares of its common stock at a price per share of $14.28 . The Company used the net proceeds of $222.4 million , net of offering costs, to fund a portion of the purchase price of the ExL Acquisition and for general corporate purposes. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition. On October 28, 2016, the Company completed a public offering of 6.0 million shares of its common stock at a price per share of $37.32 . The Company used the net proceeds of $223.7 million , net of offering costs, to fund the Sanchez Acquisition and repay borrowings under the revolving credit facility. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition. On October 21, 2015, the Company completed a public offering of 6.3 million shares of its common stock at a price per share of $37.80 . The Company used the net proceeds of $238.8 million , net of offering costs, to repay borrowings under the Company’s revolving credit facility and for general corporate purposes. On March 20, 2015, the Company completed a public offering of 5.2 million shares of its common stock at a price per share of $44.75 . The Company used the net proceeds of $231.3 million , net of offering costs, to repay a portion of the borrowings under the Company’s revolving credit facility and for general corporate purposes. Stock-Based Compensation At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. The 2017 Incentive Plan provides that up to 2,675,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan, may be issued. As of December 31, 2017 , there were 1,750,908 common shares remaining available for grant under the 2017 Incentive Plan. Each restricted stock award, restricted stock unit, or performance share granted under the 2017 Incentive Plan counts as 1.35 shares while a stock option or stock-settled stock appreciation right granted under the 2017 Incentive Plan counts as 1.00 share against the number of common shares available for grant under the 2017 Incentive Plan. Restricted Stock Awards and Units. Restricted stock awards can be granted to employees and independent contractors and restricted stock units can be granted to employees, independent contractors, and non-employee directors. As of December 31, 2017 , unrecognized compensation costs related to unvested restricted stock awards and units was $21.3 million and will be recognized over a weighted average period of 1.9 years. The table below summarizes restricted stock award and unit activity for the years ended December 31, 2017 , 2016 and 2015 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2015 Unvested restricted stock awards and units, beginning of period 1,335,682 $34.55 Granted 401,421 $51.45 Vested (671,417 ) $32.96 Forfeited (23,689 ) $43.36 Unvested restricted stock awards and units, end of period 1,041,997 $44.22 For the Year Ended December 31, 2016 Unvested restricted stock awards and units, beginning of period 1,041,997 $44.22 Granted 887,254 $27.80 Vested (811,136 ) $36.32 Forfeited (6,405 ) $34.46 Unvested restricted stock awards and units, end of period 1,111,710 $36.93 For the Year Ended December 31, 2017 Unvested restricted stock awards and units, beginning of period 1,111,710 $36.93 Granted 1,020,465 $25.63 Vested (635,965 ) $39.62 Forfeited (13,555 ) $29.11 Unvested restricted stock awards and units, end of period 1,482,655 $28.07 The aggregate fair value of restricted stock awards and units that vested during the years ended December 31, 2017 , 2016 and 2015 was $20.3 million , $26.3 million and $32.0 million , respectively. Stock Appreciation Rights (“SARs”). SARs can be granted to employees and independent contractors under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”) or the 2017 Incentive Plan. SARs granted under the 2017 Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. All outstanding SARs have been granted under the Cash SAR Plan and therefore will be settled solely in cash. The grant date fair value of SARs is calculated using the Black-Scholes-Merton option pricing model. The liability for SARs as of December 31, 2017 was $4.4 million , all of which was classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2016 , the liability for SARs was $11.5 million , of which $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $1.3 million as of December 31, 2017 , and will be recognized over a weighted average period of 1.1 years. The table below summarizes the activity for SARs for the years ended December 31, 2017 , 2016 and 2015 : Stock Appreciation Rights Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Aggregate Intrinsic Value of Exercises (In millions) For the Year Ended December 31, 2015 Outstanding, beginning of period 765,198 $22.49 Granted — — Exercised (64,745 ) $29.40 $1.5 Forfeited — — Outstanding, end of period 700,453 $21.86 Vested, end of period 626,661 $21.05 Vested and exercisable, end of period 626,661 $21.05 For the Year Ended December 31, 2016 Outstanding, beginning of period 700,453 $21.86 Granted 376,260 27.30 Exercised (354,075 ) $23.89 $5.2 Forfeited — — Outstanding, end of period 722,638 $23.69 Vested, end of period 350,840 $19.87 Vested and exercisable, end of period 350,840 $19.87 For the Year Ended December 31, 2017 Outstanding, beginning of period 722,638 $23.69 Granted 342,440 $26.94 Exercised (219,279 ) $17.28 $2.1 Forfeited — — Expired (131,561 ) $24.19 Outstanding, end of period 714,238 $27.12 3.7 $— Vested, end of period 185,899 $27.30 Vested and exercisable, end of period — $27.30 3.2 $— No SARs were granted during the year ended December 31, 2015. The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the years ended December 31, 2017 and 2016 : Years Ended December 31, 2017 2016 Expected term (in years) 4.24 3.93 Expected volatility 54.3 % 45.1 % Risk-free interest rate 1.8 % 1.3 % Dividend yield — % — % Performance Shares. The Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. The number of performance shares that will vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three year performance period, the last day of which is also the vesting date. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of December 31, 2017 , unrecognized compensation costs related to unvested performance shares was $2.1 million and will be recognized over a weighted average period of 1.7 years. The table below summarizes performance share activity for the years ended December 31, 2017 , 2016 and 2015 : Target Performance Shares (1) Weighted Average Grant Date Fair Value For the Year Ended December 31, 2015 Unvested performance shares, beginning of period 56,342 $68.15 Granted 56,517 $65.51 Vested — — Forfeited — — Unvested performance shares, end of period 112,859 $66.83 For the Year Ended December 31, 2016 Unvested performance shares, beginning of period 112,859 $66.83 Granted 41,651 $35.71 Vested — — Forfeited — — Unvested performance shares, end of period 154,510 $58.44 For the Year Ended December 31, 2017 Unvested performance shares, beginning of period 154,510 $58.44 Granted 46,787 $35.14 Vested (56,342 ) $68.15 Forfeited — — Unvested performance shares, end of period 144,955 $47.14 (1) The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company ’ s final TSR ranking for the approximate three year performance period. During the first quarter of 2017, the Company issued 92,200 shares of common stock for 56,342 target performance shares that vested during the first quarter of 2017 with a multiplier of 164% based on the Company’s final TSR ranking during the performance period. The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, 2017 2016 2015 Number of simulations 500,000 500,000 500,000 Expected term (in years) 2.98 3.01 2.89 Expected volatility 59.2 % 55.3 % 45.3 % Risk-free interest rate 1.5 % 1.2 % 0.9 % Dividend yield — % — % — % Stock-Based Compensation Expense, Net. Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash and performance shares is reflected as general and administrative expense, net of amounts capitalized to oil and gas properties in the consolidated statements of operations. The Company recognized the following stock-based compensation expense, net for the periods indicated: Years Ended December 31, 2017 2016 2015 (In thousands) Restricted stock awards and units $21,372 $28,196 $23,668 Stock appreciation rights (5,023 ) 9,675 (6,326 ) Performance shares 2,442 2,806 1,961 18,791 40,677 19,303 Less: amounts capitalized to oil and gas properties (4,482 ) (4,591 ) (4,574 ) Total stock-based compensation expense, net $14,309 $36,086 $14,729

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	11. Derivative Instruments Commodity Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, basis swaps, three-way collars and purchased and sold call options, which are described below. Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes. Basis Swaps: The Company receives a variable NYMEX settlement price, plus or minus a fixed differential price, and pays a variable published index price to the counterparties over specified periods for contracted volumes. Three-Way Collars: A three-way collar is a combination of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the market price is between the fixed floor price and the fixed sub-floor price or is above the fixed ceiling price, the Company receives the fixed floor price or pays the market price, respectively. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. The Company has incurred premiums on certain of these contracts in order to obtain a higher floor price and/or ceiling price. Sold Call Options : These contracts give the counterparties the right, but not the obligation, to buy contracted volumes from the Company over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the counterparties to pay premiums to the Company that represent the fair value of the call option as of the date of purchase. Purchased Call Options : These contracts give the Company the right, but not the obligation, to buy contracted volumes from the counterparties over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the counterparties pay the Company the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the Company to pay premiums to the counterparties that represent the fair value of the call option as of the date of purchase. All of the Company’s purchased call options were executed contemporaneously with sales of call options to increase the fixed price on a portion of the existing sold call options and therefore are presented on a net basis in the “Net Sold Call Options” table below. Premiums : In order to increase the fixed price on a portion of the Company’s existing sold call options, as mentioned above, the Company incurred premiums on its purchased call options. Additionally, the Company has incurred premiums on certain of its three-way collars in order to obtain a higher floor price and/or ceiling price. The payment of premiums associated with the Company’s purchased call options and certain of the three-way collars are deferred until the applicable contracts settle on a monthly basis. When the Company has entered into three-way collars which span multiple years, the Company has elected to defer payment of certain of the premiums until the final year’s contracts settle on a monthly basis. The following tables set forth a summary of the Company’s outstanding derivative positions at weighted average contract prices as of December 31, 2017 : Crude Oil Fixed Price Swaps Period Volumes (Bbls/d) NYMEX Price ($/Bbl) FY 2018 6,000 $49.55 Crude Oil Basis Swaps Period Volumes (Bbls/d) LLS-NYMEX Price Differential ($/Bbl) FY 2018 6,000 $2.91 Period Volumes (Bbls/d) Midland-NYMEX Price Differential ($/Bbl) FY 2018 6,000 ($0.10 ) Crude Oil Three-Way Collars NYMEX Prices Period Volumes (Bbls/d) Sub-Floor Price ($/Bbl) Floor Price ($/Bbl) Ceiling Price ($/Bbl) FY 2018 24,000 $39.38 $49.06 $60.14 FY 2019 12,000 $40.00 $48.40 $60.29 Crude Oil Net Sold Call Options Period Volumes (Bbls/d) NYMEX Ceiling Price ($/Bbl) FY 2018 3,388 $71.33 FY 2019 3,875 $73.66 FY 2020 4,575 $75.98 NGL Fixed Price Swaps OPIS Purity Ethane Mont Belvieu Non-TET OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET Period Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) FY 2018 2,200 $12.01 1,500 $34.23 200 $38.85 600 $38.98 600 $55.23 Natural Gas Sold Call Options Period Volumes (MMBtu/d) NYMEX Ceiling Price ($/MMBtu) FY 2018 33,000 $3.25 FY 2019 33,000 $3.25 FY 2020 33,000 $3.50 The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. Counterparties to the Company’s derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds the Company’s unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral. Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties and its counterparty’s parent company, as applicable. Contingent Consideration As part of the ExL Acquisition, the Company agreed to the Contingent ExL Consideration that will require payment of $50.0 million per year for each of the years of 2018 through 2021, with a cap of $125.0 million , if the EIA WTI average price is greater than $50.00 per barrel for the respective year. As of December 31, 2017 , the estimated fair value of the Contingent ExL Consideration was $85.6 million and was classified as non-current “Derivative liabilities” in the consolidated balance sheets. As part of the divestiture of the Company’s Utica assets, the Company agreed to the Contingent Utica Consideration in which the Company will receive $5.0 million per year for each of the years of 2018 through 2020, if the EIA WTI average price is greater than $50.00 , $53.00 , and $56.00 for the years of 2018, 2019, and 2020, respectively. The Company recorded the Contingent Utica Consideration at its divestiture date fair value of $6.1 million in the consolidated financial statements. As of December 31, 2017 , the estimated fair value of the Contingent Utica Consideration was $8.0 million and was classified as non-current “Other assets” in the consolidated balance sheets. As part of the divestiture of the Company’s Marcellus assets, the Company agreed to the Contingent Marcellus Consideration in which the Company will receive $3.0 million per year for each of the years of 2018 through 2020, with a cap of $7.5 million , if the CME HH average price is greater than $3.13 , $3.18 , and $3.30 for the years of 2018, 2019, and 2020, respectively. The Company recorded the Contingent Marcellus Consideration at its divestiture date fair value of $2.7 million in the consolidated financial statements. As of December 31, 2017 , the estimated fair value of the Contingent Marcellus Consideration was $2.2 million and was classified as non-current “Other assets” in the consolidated balance sheets. The following table summarizes the combined contingent consideration recorded in the consolidated financial statements: Consolidated Balance Sheets Consolidated Statements of Operations December 31, 2017 Year Ended December 31, 2017 Other Assets - Non-Current Derivative Liabilities - Non-Current (Gain) Loss on Derivatives, Net (In thousands) Contingent ExL Consideration $— ($85,625 ) $33,325 Contingent Utica Consideration 7,985 — (1,840 ) Contingent Marcellus Consideration 2,205 — 455 Contingent consideration $10,190 ($85,625 ) $31,940 Subsequent to December 31, 2017 , the Company closed on the sale of substantially all of its assets in the Niobrara Formation. As part of the divestiture, the Company agreed to the Contingent Niobrara Consideration. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details. Derivative Assets and Liabilities All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the consolidated balance sheets as of December 31, 2017 and 2016 are summarized below: December 31, 2017 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $4,869 ($4,869 ) $— Deferred premium obligations — — — Other current assets $4,869 ($4,869 ) $— Commodity derivative instruments 9,505 (9,505 ) — Deferred premium obligations — — — Contingent consideration 10,190 — 10,190 Other assets-non current $19,695 ($9,505 ) $10,190 Commodity derivative instruments ($52,671 ) $4,869 ($47,802 ) Deferred premium obligations (9,319 ) — (9,319 ) Derivative liabilities-current ($61,990 ) $4,869 ($57,121 ) Commodity derivative instruments (24,609 ) 9,505 (15,104 ) Deferred premium obligations (11,603 ) — (11,603 ) Contingent consideration (85,625 ) — (85,625 ) Derivative liabilities-non current ($121,837 ) $9,505 ($112,332 ) December 31, 2016 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $7,990 ($6,753 ) $1,237 Deferred premium obligations — — — Other current assets $7,990 ($6,753 ) $1,237 Commodity derivative instruments 3,882 (3,882 ) — Deferred premium obligations — — — Contingent consideration — — — Other assets-non current $3,882 ($3,882 ) $— Commodity derivative instruments ($27,346 ) $6,753 ($20,593 ) Deferred premium obligations (2,008 ) — (2,008 ) Derivative liabilities-current ($29,354 ) $6,753 ($22,601 ) Commodity derivative instruments (28,841 ) 3,882 (24,959 ) Deferred premium obligations (2,569 ) — (2,569 ) Contingent consideration — — — Derivative liabilities-non current ($31,410 ) $3,882 ($27,528 ) See “Note 12. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative instruments. (Gain) Loss on Derivatives, Net The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of the Company’s commodity derivative instruments and contingent consideration are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations in the consolidated statements of operations for the years ended December 31, 2017 , 2016 , and 2015 is summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) (Gain) Loss on Derivatives, Net Crude oil $22,839 $23,609 ($99,624 ) Natural gas liquids 1,322 — — Natural gas (15,399 ) 19,584 (4,063 ) Deferred premium obligations incurred 18,401 5,880 4,426 Contingent consideration 31,940 — — Total (Gain) Loss on Derivatives, Net $59,103 $49,073 ($99,261 ) Cash Received (Paid) for Derivative Settlements, Net Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as cash received (paid) for derivative settlements, net in the consolidated statements of cash flows. The effect of commodity derivative instruments and deferred premium obligations in the consolidated statements of cash flows for the years ended December 31, 2017 , 2016 , and 2015 is summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) Cash Received (Paid) for Derivative Settlements, Net Crude oil $9,883 $125,098 $176,511 Natural gas (54 ) — 17,785 Deferred premium obligations paid (2,056 ) (5,729 ) — Total Cash Received (Paid) for Derivative Settlements, Net $7,773 $119,369 $194,296

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	12. Fair Value Measurements Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016 : December 31, 2017 Level 1 Level 2 Level 3 (In thousands) Derivative instrument assets $— $— $10,190 Derivative instrument liabilities $— ($62,906 ) ($85,625 ) December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Derivative instrument assets $— $1,237 $— Derivative instrument liabilities $— ($45,552 ) $— The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. Commodity derivative instruments. The fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model which uses contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments including forward oil and gas price curves, discount rates and volatility factors and are therefore designated as Level 2 within the valuation hierarchy. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities. The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the fair value derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company nets the fair values of its derivative assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the years ended December 31, 2017 and 2016 . Contingent consideration. The fair values of the Contingent ExL Consideration, the Contingent Utica Consideration and the Contingent Marcellus Consideration were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods. The following tables present reconciliations of changes in the fair values of the financial assets and liabilities related to the Company’s contingent consideration, which were designated as Level 3 within the valuation hierarchy, for the year ended December 31, 2017 : Year Ended December 31, 2017 (In thousands) Fair value assets, beginning of period $— Recognition of acquisition date fair value 8,805 Gain (loss) on changes in fair value (1) 1,385 Transfers into (out of) Level 3 — Fair value assets, end of period $10,190 Year Ended December 31, 2017 (In thousands) Fair value liability, beginning of period $— Recognition of acquisition date fair value (52,300 ) Gain (loss) on changes in fair value (1) (33,325 ) Transfers into (out of) Level 3 — Fair value liability, end of period ($85,625 ) (1) Included in (gain) loss on derivatives, net in the consolidated statements of operations. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further details regarding the contingent consideration. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured as of the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore designated as Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the assets acquired and liabilities assumed as of the acquisition dates for the ExL Acquisition and Sanchez Acquisition. The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 7. Asset Retirement Obligations” for additional details regarding the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016. The fair value measurements of the Preferred Stock are measured as of the issuance date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company. See “Note 9. Preferred Stock and Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants. Fair Value of Other Financial Instruments The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt, which are designated as Level 1 under the fair value hierarchy. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of unamortized premiums and debt issuance costs, with the fair values measured using quoted secondary market trading prices. December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) 7.50% Senior Notes due 2020 (1) $446,087 $459,518 $593,447 $624,750 6.25% Senior Notes due 2023 641,792 674,375 640,546 672,750 8.25% Senior Notes due 2025 245,605 274,375 — — Other long-term debt due 2028 4,425 4,445 4,425 4,419 (1) The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017 .

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	13. Condensed Consolidating Financial Information The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities. CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,441,633 $105,533 $— ($3,424,288 ) $122,878 Total property and equipment, net 5,953 2,630,707 3,028 (3,878 ) 2,635,810 Investment in subsidiaries (999,793 ) — — 999,793 — Other assets 9,270 10,346 — — 19,616 Total Assets $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 Liabilities and Shareholders’ Equity Current liabilities $165,701 $3,631,401 $3,028 ($3,427,308 ) $372,822 Long-term liabilities 1,689,466 114,978 — 15,879 1,820,323 Preferred stock 214,262 — — — 214,262 Total shareholders’ equity 387,634 (999,793 ) — 983,056 370,897 Total Liabilities and Shareholders’ Equity $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,735,830 $63,513 $— ($2,726,355 ) $72,988 Total property and equipment, net 42,181 1,503,695 3,800 (3,916 ) 1,545,760 Investment in subsidiaries (1,282,292 ) — — 1,282,292 — Other assets 7,423 156 — — 7,579 Total Assets $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 Liabilities and Shareholders’ Equity Current liabilities $114,805 $2,822,729 $3,800 ($2,729,375 ) $211,959 Long-term liabilities 1,348,105 26,927 — 15,878 1,390,910 Preferred stock — — — — — Total shareholders’ equity 40,232 (1,282,292 ) — 1,265,518 23,458 Total Liabilities and Shareholders’ Equity $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $302 $745,586 $— $— $745,888 Total costs and expenses 195,728 459,057 — (37 ) 654,748 Income (loss) from continuing operations before income taxes (195,426 ) 286,529 — 37 91,140 Income tax expense — (4,030 ) — — (4,030 ) Equity in income of subsidiaries 282,499 — — (282,499 ) — Income from continuing operations $87,073 $282,499 $— ($282,462 ) $87,110 Income from discontinued operations, net of income taxes — — — — — Net income $87,073 $282,499 $— ($282,462 ) $87,110 Dividends on preferred stock (7,781 ) — — — (7,781 ) Accretion on preferred stock (862 ) — — — (862 ) Net income attributable to common shareholders $78,430 $282,499 $— ($282,462 ) $78,467 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $482 $443,112 $— $— $443,594 Total costs and expenses 208,054 910,522 — 492 1,119,068 Loss from continuing operations before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax benefit — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Loss from continuing operations ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Income from discontinued operations, net of income taxes — — — — — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Net loss attributable to common shareholders ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $1,708 $427,495 $— $— $429,203 Total costs and expenses 95,464 1,603,515 — 28,984 1,727,963 Loss from continuing operations before income taxes (93,756 ) (1,176,020 ) — (28,984 ) (1,298,760 ) Income tax benefit 10,125 127,010 — 3,740 140,875 Equity in loss of subsidiaries (1,049,010 ) — — 1,049,010 — Loss from continuing operations ($1,132,641 ) ($1,049,010 ) $— $1,023,766 ($1,157,885 ) Income from discontinued operations, net of income taxes 2,731 — — — 2,731 Net loss ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Net loss attributable to common shareholders ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($121,107 ) $544,088 $— $— $422,981 Net cash used in investing activities from continuing operations (615,364 ) (1,155,340 ) — 611,252 (1,159,452 ) Net cash provided by financing activities from continuing operations 741,817 611,252 — (611,252 ) 741,817 Net cash used in discontinued operations — — — — — Net increase in cash and cash equivalents 5,346 — — — 5,346 Cash and cash equivalents, beginning of year 4,194 — — — 4,194 Cash and cash equivalents, end of year $9,540 $— $— $— $9,540 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities from continuing operations (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities from continuing operations 308,340 268,283 740 (269,023 ) 308,340 Net cash used in discontinued operations — — — — — Net decrease in cash and cash equivalents (38,724 ) — — — (38,724 ) Cash and cash equivalents, beginning of year 42,918 — — — 42,918 Cash and cash equivalents, end of year $4,194 $— $— $— $4,194 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities from continuing operations $2,655 $376,080 $— $— $378,735 Net cash used in investing activities from continuing operations (447,296 ) (674,758 ) — 448,678 (673,376 ) Net cash provided by financing activities from continuing operations 480,767 298,678 — (448,678 ) 330,767 Net cash used in discontinued operations (4,046 ) — — — (4,046 ) Net increase in cash and cash equivalents 32,080 — — — 32,080 Cash and cash equivalents, beginning of year 10,838 — — — 10,838 Cash and cash equivalents, end of year $42,918 $— $— $— $42,918

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Disclosures	14. Supplemental Cash Flow Information Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Years Ended December 31, 2017 2016 2015 (In thousands) Supplemental cash flow disclosures: Cash paid for interest, net of amounts capitalized $77,213 $75,231 $64,692 Cash paid for income taxes — — — Non-cash investing and financing activities: Increase (decrease) in capital expenditure payables and accruals $102,272 ($21,492 ) ($86,878 ) Contingent consideration related to acquisitions of oil and gas properties 52,300 — — Contingent consideration related to divestitures of oil and gas properties (8,805 ) — — Liabilities assumed in connection with the Sanchez Acquisition — 4,880 — Stock-based compensation expense capitalized to oil and gas properties 4,482 4,591 4,574 Asset retirement obligations capitalized to oil and gas properties 3,726 1,927 4,853

Subsequent Events (Unaudited)

Subsequent Events (Unaudited)	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	15. Subsequent Events (Unaudited) Divestitures Niobrara. On January 19, 2018, the Company closed the sale of substantially all of its assets in the Niobrara Formation. The Company has received net cash proceeds of approximately $136.6 million , subject to post-closing adjustments, which includes a deposit received upon the execution of the purchase and sale agreement and amounts received at closing. Eagle Ford. On January 31, 2018, the Company closed the sale of a portion of its assets in the Eagle Ford Shale to EP Energy E&P Company, L.P. The Company has received net cash proceeds of approximately $246.2 million , subject to post-closing adjustments, which includes a deposit received upon the execution of the purchase and sale agreement and amounts received at the initial closing as well as a subsequent closing for leases that were not conveyed at the initial closing. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details regarding these divestitures. Redemptions of 7.50% Senior Notes due 2020 On January 19, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on February 18, 2018, $100.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On February 20, 2018, the Company paid an aggregate redemption price of $105.1 million , which included a redemption premium of $1.9 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. On January 31, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on March 2, 2018, $220.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On the redemption date, the Company expects to pay an aggregate redemption price of $231.8 million , which includes a redemption premium of $4.1 million as well as accrued and unpaid interest of $7.7 million from the last interest payment date up to, but not including, the redemption date. Redemption of Preferred Stock On January 19, 2018, the Company provided a notice to be delivered to the holders of its Preferred Stock under which it called for redemption of 50,000 of the shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, on January 24, 2018. The Company paid $50.5 million on January 24, 2018 upon redemption, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends. Senior Secured Revolving Credit Facility On January 31, 2018, as a result of the divestiture in the Eagle Ford Shale discussed above, the Company’s borrowing base under the Senior Secured Revolving Credit Facility was reduced from $900.0 million to $830.0 million , however, the elected commitment amount remained unchanged at $800.0 million . Hedging In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below: Natural Gas Fixed Price Swaps Period Volumes (MMBtu/d) NYMEX Price ($/MMBtu) March 2018 - December 2018 25,000 $3.01

Supplemental Disclosures About

Supplemental Disclosures About Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Disclosures About Oil And Gas Producing Activities	16. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited) Costs Incurred Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) Property acquisition costs Proved properties $303,307 $90,661 $— Unproved properties 525,061 113,535 63,446 Total property acquisition costs 828,368 204,196 63,446 Exploration costs 91,098 37,508 117,227 Development costs 569,982 374,134 389,396 Total costs incurred $1,489,448 $615,838 $570,069 Costs incurred exclude capitalized interest on unproved properties of $28.3 million , $17.0 million , and $32.1 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Included in exploration and development costs are non-cash additions related to the estimated future asset retirement obligations of the Company’s oil and gas properties of $3.5 million , $1.9 million and $4.9 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Non-cash additions related to the estimated future asset retirement obligations associated with the ExL Acquisition of $0.1 million and for the Sanchez Acquisition of $2.0 million are included in acquisition costs of proved properties for the year ended December 31, 2017 and 2016, respectively. The internal cost of employee compensation and benefits, including stock-based compensation, capitalized to proved or unproved oil and gas properties of $14.8 million , $10.5 million and $15.8 million for the years ended December 31, 2017 , 2016 and 2015 , respectively, are included in exploration, development and unproved property acquisition costs. Proved Oil and Gas Reserve Quantities Proved oil and gas reserves are generally those quantities of crude oil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserve quantities at December 31, 2017 , 2016 , and 2015 and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company, L.P. Such estimates have been prepared in accordance with guidelines established by the SEC. All of the Company’s proved reserves are attributable to properties within the United States. The Company’s proved reserves and changes in proved reserves are as follows: Crude Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total Proved Reserves (MBoe) Proved reserves: January 1, 2015 100,704 13,513 221,017 151,053 Extensions and discoveries 26,358 5,292 33,925 37,304 Revisions of previous estimates (9,059 ) 2,768 11,808 (4,323 ) Production (8,415 ) (1,352 ) (21,812 ) (13,402 ) December 31, 2015 109,588 20,221 244,938 170,632 Extensions and discoveries 40,074 8,612 59,318 58,572 Revisions of previous estimates (16,731 ) (3,230 ) 1,481 (19,713 ) Purchases of reserves in place 4,810 122 7,282 6,145 Production (9,423 ) (1,788 ) (25,574 ) (15,473 ) December 31, 2016 128,318 23,937 287,445 200,163 Extensions and discoveries 50,476 13,781 98,980 80,754 Revisions of previous estimates (19,838 ) (909 ) 27,774 (16,118 ) Purchases of reserves in place 21,634 8,642 94,962 46,103 Sales of reserves in place (650 ) (526 ) (170,219 ) (29,546 ) Production (12,566 ) (2,327 ) (28,472 ) (19,639 ) December 31, 2017 167,374 42,598 310,470 261,717 Proved developed reserves: December 31, 2014 35,238 5,294 149,697 65,482 December 31, 2015 42,311 7,933 154,725 76,032 December 31, 2016 51,062 9,387 187,054 91,625 December 31, 2017 69,632 17,447 131,355 108,972 Proved undeveloped reserves: December 31, 2014 65,466 8,219 71,320 85,571 December 31, 2015 67,277 12,288 90,213 94,600 December 31, 2016 77,256 14,550 100,391 108,538 December 31, 2017 97,742 25,151 179,115 152,745 Extensions and discoveries For the year ended December 31, 2017, the Company added 6,473 MBoe of proved developed reserves and 74,281 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 51% and 48% , respectively, of the total extensions and discoveries. For the year ended December 31, 2016, the Company added 6,525 MBoe of proved developed reserves and 52,047 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20% , respectively, of the total extensions and discoveries. For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries. Revisions of previous estimates For the year ended December 31, 2017, revisions of previous estimates reduced the Company’s proved reserves by 16,118 MBoe. Included in revisions of previous estimates were: • Positive revisions due to price of 2,684 MBoe. • Negative revisions due to performance of 4,500 MBoe primarily in the Eagle Ford due to a downward shift of the type curve for certain PUD locations partially offset by positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017. • Negative revisions in proved undeveloped reserves of 14,302 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the recent ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads. For the year ended December 31, 2016, revisions of previous estimates reduced the Company’s proved reserves by 19,713 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 6,705 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 3,228 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 3,477 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations due to loss of tail reserves; • Negative revisions due to performance of 6,083 MBoe primarily in Eagle Ford as the EURs for certain PUD locations were reduced as a result of tighter spacing and shorter lateral lengths partially offset by positive revisions in Marcellus; • Negative revisions in proved undeveloped reserves of 6,925 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the move to a more efficient development plan which includes drilling and completing larger pads and the recent Sanchez Acquisition. For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives; • Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus. Purchases of reserves in place For the year ended December 31, 2017, purchases of reserves in place included 26,009 MBoe of proved developed reserves and 20,094 MBoe of proved undeveloped reserves associated with the ExL Acquisition. For the year ended December 31, 2016, purchases of reserves in place included 4,978 MBoe of proved developed reserves and 1,167 MBoe of proved undeveloped reserves associated with the Sanchez Acquisition. There were no purchases of reserves in place for the year ended December 31, 2015. Sales of reserves in place For the year ended December 31, 2017, sales of reserves in place included 22,249 MBoe of proved developed reserves and 7,297 MBoe of proved undeveloped reserves associated with the Marcellus Shale and Utica Shale divestitures. There were no sales of reserves in place for the years ended December 31, 2016 and 2015. Standardized Measure The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2017 2016 2015 (In thousands) Future cash inflows $10,109,752 $5,903,629 $5,878,348 Future production costs (3,202,201 ) (2,241,928 ) (2,124,059 ) Future development costs (1,699,909 ) (1,264,493 ) (1,178,773 ) Future income taxes (1) (445,056 ) — — Future net cash flows 4,762,586 2,397,208 2,575,516 Less 10% annual discount to reflect timing of cash flows (2,297,544 ) (1,093,779 ) (1,210,292 ) Standard measure of discounted future net cash flows $2,465,042 $1,303,429 $1,365,224 (1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016 and 2015. Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The average realized prices used for 2017 , 2016 and 2015 were $49.87 , $39.60 , and $47.24 per Bbl, respectively, for crude oil, $19.78 , $11.66 and $12.00 per Bbl, respectively, for NGLs, and $2.96 , $1.89 and $1.87 per Mcf, respectively, for natural gas. Future operating and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. Future income taxes, which include the effects of the Tax Cuts and Jobs Act, are based on current statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve estimates. Changes in Standardized Measure Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) Standardized measure at beginning of year $1,303,429 $1,365,224 $2,555,082 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production $710,773 ($346,763 ) ($2,547,213 ) Net change in estimated future development costs (51,854 ) 74,407 342,238 Net change due to revisions in quantity estimates (42,214 ) (150,245 ) (157,271 ) Accretion of discount 130,343 136,522 326,074 Changes in production rates (timing) and other (116,056 ) (111,137 ) (139,533 ) Total revisions to reserves proved in prior years 630,992 (397,216 ) (2,175,705 ) Net change due to extensions and discoveries, net of estimated future development and production costs 597,502 313,201 252,155 Net change due to purchases of reserves in place 452,932 43,426 — Net change due to divestitures of reserves in place (106,608 ) — — Sales of crude oil, NGLs and natural gas produced, net of production costs (566,258 ) (320,272 ) (312,213 ) Previously estimated development costs incurred 326,383 299,066 340,247 Net change in income taxes (173,330 ) — 705,658 Net change in standardized measure of discounted future net cash flows 1,161,613 (61,795 ) (1,189,858 ) Standardized measure at end of year $2,465,042 $1,303,429 $1,365,224

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	17. Quarterly Financial Data (Unaudited) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2017 and 2016 : Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter (2) Fourth Quarter (3) (In thousands, except per share data) Total revenues $151,355 $166,483 $181,279 $246,771 Operating profit (1) $57,953 $63,147 $69,364 $113,205 (Gain) loss on derivatives, net ($25,316 ) ($26,065 ) $24,377 $86,107 Net income (loss) $40,021 $56,306 $7,823 ($17,040 ) Net income (loss) attributable to common shareholders $40,021 $56,306 $5,574 ($23,434 ) Net income (loss) attributable to common shareholders per common share (3) Basic $0.61 $0.86 $0.07 ($0.29 ) Diluted $0.61 $0.85 $0.07 ($0.29 ) Year Ended December 31, 2016 First Quarter (4) Second Quarter (4) Third Quarter (4) Fourth Quarter (In thousands, except per share data) Total revenues $81,262 $107,324 $111,177 $143,831 Operating profit (loss) (1) ($7,491 ) $27,167 $31,634 $55,000 Net loss ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss attributable to common shareholders ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss attributable to common shareholders per common share (3) Basic ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Diluted ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) (1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A. (2) Third quarter of 2017 included the following: a. $2.2 million of Preferred Stock dividends which reduced net income attributable to common shareholders. (3) Fourth quarter of 2017 included the following: a. $4.2 million loss on extinguishment of debt as a result of the redemption of $150.0 million aggregate principal amount of 7.50% Senior Notes. b. $5.5 million of Preferred Stock dividends which increased net loss attributable to common shareholders. (4) The sum of quarterly net income (loss) attributable to common shareholders per common share does not agree with the total year net income (loss) attributable to common shareholders per common share as each computation is based on the weighted average of common shares outstanding during the period. (5) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million , $197.1 million , and $105.1 million , respectively.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties.
Reclassifications	Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued. Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of derivative assets and liabilities, fair values of contingent consideration, preferred stock fair value upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $62.6 million and $34.3 million as of December 31, 2017 and 2016 , respectively.
Accounts Receivable	Accounts Receivable As of December 31, 2017 payables due to related parties were less than $0.1 million and as of December 31, 2016 , receivables due from related parties were $0.9 million . The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. As of December 31, 2017 and 2016 , the Company’s allowance for doubtful accounts was $0.4 million and $0.8 million , respectively.
Concentration of Credit Risk	Concentration of Credit Risk The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners.
Major Customers	Major Customers Shell Trading (US) Company accounted for approximately 69% , 56% , and 65% of the Company’s total revenues in 2017 , 2016 , and 2015 , respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 7% , 15% and 9% of the Company’s total revenues in 2017 , 2016 and 2015 , respectively.
Oil and Gas Properties	Oil and Gas Properties Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity and totaled $14.8 million , $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015 , respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred. Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Boe of proved oil and gas properties was $13.09 , $13.50 and $22.05 for the years ended December 31, 2017, 2016 and 2015 , respectively. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds are assessed on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs along with associated capitalized interest are reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The Company capitalized interest costs to unproved properties totaling $28.3 million , $17.0 million and $32.1 million for the years ended December 31, 2017, 2016 and 2015 , respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10% , (b) the costs of unproved properties not being amortized, and (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment. The Company did not recognize impairments of proved oil and gas properties for the year ended December 31, 2017. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million , due primarily to declines in the 12-Month Average Realized Price of crude oil. Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2017 , 2016 and 2015 , the Company did not have any sales of oil and gas properties that significantly altered such relationship. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties.” Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs associated with the revolving credit facility are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. Debt issuance costs associated with the revolving credit facility are classified in “Other assets” in the consolidated balance sheets while the debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets.
Financial Instruments	Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.”
Asset Retirement Obligations	Asset Retirement Obligations The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities from continuing operations in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.”
Commitments and Contingencies	Commitments and Contingencies Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies.”
Revenue Recognition	Revenue Recognition Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2017 and 2016 , the Company did not have any material production imbalances.
Derivative Instruments	Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 11. Derivative Instruments” for further discussion of the Company’s commodity derivative instruments. The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed certain thresholds during certain specified periods in the future. These contingent consideration liabilities and assets are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheet, with subsequent changes in fair value recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further discussion of the contingent consideration.
Preferred Stock	Preferred Stock and Warrants The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets. When preferred stock is issued in conjunction with warrants, the warrants are evaluated separately as a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the warrants for equity classification and have determined the warrants qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The warrants do not require further adjustments from their relative fair value at the issuance date. Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows.
Warrants	See “Note 9. Preferred Stock and Warrants” for further details of the Company’s outstanding preferred stock and warrants.
Stock-Based Compensation	Stock-Based Compensation The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See “Note 10. Shareholders’ Equity and Stock Based Compensation” for further details of the awards discussed below. Restricted Stock Awards and Units . Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. Stock Appreciation Rights. For SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months and have an exercise price in excess of the market price at the end of the reporting period, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. If SARs expire unexercised, the cumulative compensation costs associated with the unexercised SARs will be zero. Performance Share Awards. For performance share awards, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved.
Income Taxes	Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized.
Earnings Per Share	Income (Loss) Attributable to Common Shareholders Per Common Share Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance share awards in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. Supplemental net income (loss) attributable to common shareholders per common share information is provided below: Years Ended December 31, 2017 2016 2015 (In thousands, except per share amounts) Net Income (Loss) Attributable to Common Shareholders $78,467 ($675,474 ) ($1,155,154 ) Basic weighted average common shares outstanding 73,421 59,932 51,457 Effect of dilutive instruments 572 — — Diluted weighted average common shares outstanding 73,993 59,932 51,457 Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.07 ($11.27 ) ($22.45 ) Diluted $1.06 ($11.27 ) ($22.45 ) When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented: Years Ended December 31, 2017 2016 2015 (In thousands) Dilutive 572 — — Anti-dilutive 52 669 649
Recently Adopted Accounting Pronouncements	Recently Adopted Accounting Pronouncement Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption. Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million . This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero . Effective January 1, 2017, all windfall tax benefits and tax shortfalls are recorded as income tax expense or benefit in the consolidated statements of operations, whereas prior to adoption, windfall tax benefits were recorded as an increase to additional paid-in capital. In addition, windfall tax benefits, along with tax shortfalls, are now required to be classified as an operating cash flow as opposed to a financing cash flow. Further, the Company has elected to account for forfeitures of share-based payment awards as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements Revenue From Contracts With Customers. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new 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 will adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company has performed an analysis of existing contracts and does not expect adoption to have a material impact on its consolidated financial statements, however, certain immaterial natural gas processing fees, which have historically been netted in revenue, will be recorded to lease operating expense. In addition, the Company has evaluated the expected changes to relevant business practices, accounting policies and control activities and does not expect to have a material change as a result of the adoption of ASU 2014-09. Business Combinations. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will adopt ASU 2017-01 effective January 1, 2018 on a prospective basis. Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The Company will adopt ASU 2016-15 effective January 1, 2018 using the full retrospective method, meaning the standard is applied to all periods presented. The Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows and related disclosures. Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts, including drilling rig contracts, office leases, certain field equipment, vehicles, produced water disposal commitments, pipeline gathering, transportation and gas processing agreements and current accounting policies and disclosures that will change as a result of adopting ASU 2016-02. Appropriate systems, controls, and processes to support the recognition and disclosure requirements of the new standard are also being evaluated. The Company currently expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. The Company plans to adopt the guidance effective January 1, 2019.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Supplemental net income (loss) attributable to common shareholders per common share information is provided below: Years Ended December 31, 2017 2016 2015 (In thousands, except per share amounts) Net Income (Loss) Attributable to Common Shareholders $78,467 ($675,474 ) ($1,155,154 ) Basic weighted average common shares outstanding 73,421 59,932 51,457 Effect of dilutive instruments 572 — — Diluted weighted average common shares outstanding 73,993 59,932 51,457 Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.07 ($11.27 ) ($22.45 ) Diluted $1.06 ($11.27 ) ($22.45 ) When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented: Years Ended December 31, 2017 2016 2015 (In thousands) Dilutive 572 — — Anti-dilutive 52 669 649
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented: Years Ended December 31, 2017 2016 2015 (In thousands) Dilutive 572 — — Anti-dilutive 52 669 649

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information [Table Text Block]	Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016 , assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition. Years Ended December 31, 2017 2016 (In thousands, except per share amounts) Total revenues $781,378 $454,913 Net Income (Loss) Attributable to Common Shareholders $91,931 ($688,180 ) Net Income (Loss) Attributable to Common Shareholders Per Common Share Basic $1.25 ($9.11 ) Diluted $1.24 ($9.11 ) Weighted Average Common Shares Outstanding Basic 73,421 75,532 Diluted 73,993 75,532
ExL Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $106 Oil and gas properties Proved properties 294,754 Unproved properties 443,194 Total oil and gas properties $737,948 Total assets acquired $738,054 Liabilities Revenues and royalties payable $5,785 Asset retirement obligations 153 Contingent ExL Consideration 52,300 Total liabilities assumed $58,238 Net Assets Acquired $679,816 The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $106 Oil and gas properties Proved properties 294,754 Unproved properties 443,194 Total oil and gas properties $737,948 Total assets acquired $738,054 Liabilities Revenues and royalties payable $5,785 Asset retirement obligations 153 Contingent ExL Consideration 52,300 Total liabilities assumed $58,238 Net Assets Acquired $679,816
Sanchez Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (In thousands) Assets Other current assets $477 Oil and gas properties Proved properties 99,938 Unproved properties 74,536 Total oil and gas properties 174,474 Total assets acquired $174,951 Liabilities Revenues and royalties payable $1,442 Other current liabilities 323 Asset retirement obligations 2,054 Other liabilities 1,078 Total liabilities assumed $4,897 Net Assets Acquired $170,054

Property And Equipment, Net (Ta

Property And Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	As of December 31, 2017 and 2016 , total property and equipment, net consisted of the following: December 31, 2017 2016 Oil and gas properties, full cost method (In thousands) Proved properties $5,615,153 $4,687,416 Accumulated DD&A and impairments (3,649,806 ) (3,392,749 ) Proved properties, net 1,965,347 1,294,667 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 612,589 211,067 Capitalized interest 47,698 29,894 Total unproved properties, not being amortized 660,287 240,961 Other property and equipment 25,625 23,127 Accumulated depreciation (15,449 ) (12,995 ) Other property and equipment, net 10,176 10,132 Total property and equipment, net $2,635,810 $1,545,760

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule Of Components Of Income Tax (Expense) Benefit	The components of income tax (expense) benefit from continuing operations were as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Current income tax (expense) benefit U.S. Federal $— $— $— State (395 ) — — Total current income tax (expense) benefit (395 ) — — Deferred income tax (expense) benefit U.S. Federal — — 131,502 State (3,635 ) — 9,373 Total deferred income tax (expense) benefit (3,635 ) — 140,875 Total income tax (expense) benefit from continuing operations ($4,030 ) $— $140,875
Schedule Of Effective Income Tax Rate Reconciliation	The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Income (loss) from continuing operations before income taxes $91,140 ($675,474 ) ($1,298,760 ) Income tax (expense) benefit at the statutory rate (31,899 ) 236,416 454,566 State income tax (expense) benefit, net of U.S. Federal income taxes (4,030 ) 3,894 9,373 Tax shortfalls from stock-based compensation expense (3,089 ) — — Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense — — 1,671 Provisional impact of Tax Cuts and Jobs Act (211,724 ) — — Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act 211,724 — — Change in valuation allowance from current year activity 35,376 (240,864 ) (323,586 ) Other (388 ) 554 (1,149 ) Income tax (expense) benefit ($4,030 ) $— $140,875
Schedule Of Deferred Tax Assets And Liabilities	As of December 31, 2017 and 2016 , deferred tax assets and liabilities are comprised of the following: December 31, 2017 2016 (In thousands) Deferred income tax assets Net operating loss carryforward - U.S. Federal and State $242,915 $221,063 Oil and gas properties 50,177 309,848 Asset retirement obligations 4,996 7,434 Stock-based compensation — 5,238 Derivative liabilities 35,585 17,545 Other 1,496 3,739 Deferred income tax assets 335,169 564,867 Deferred tax asset valuation allowance (333,029 ) (564,434 ) Net deferred income tax assets 2,140 433 Deferred income tax liabilities Oil and gas properties (3,635 ) — Derivative assets (2,140 ) (433 ) Net deferred income tax asset (liability) ($3,635 ) $—

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule Of Debt	Long-term debt consisted of the following as of December 31, 2017 and 2016 : December 31, 2017 2016 (In thousands) Senior Secured Revolving Credit Facility due 2022 $291,300 $87,000 7.50% Senior Notes due 2020 450,000 600,000 Unamortized premium for 7.50% Senior Notes 579 1,020 Unamortized debt issuance costs for 7.50% Senior Notes (4,492 ) (7,573 ) 6.25% Senior Notes due 2023 650,000 650,000 Unamortized debt issuance costs for 6.25% Senior Notes (8,208 ) (9,454 ) 8.25% Senior Notes due 2025 250,000 — Unamortized debt issuance costs for 8.25% Senior Notes (4,395 ) — Other long-term debt due 2028 4,425 4,425 Long-term debt $1,629,209 $1,325,418
Interest and Commitment Fee Rates	Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00% , or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations. Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments Applicable Margin for Base Rate Loans Applicable Margin for Eurodollar Loans Commitment Fee Less than 25% 1.00% 2.00% 0.375% Greater than or equal to 25% but less than 50% 1.25% 2.25% 0.375% Greater than or equal to 50% but less than 75% 1.50% 2.50% 0.500% Greater than or equal to 75% but less than 90% 1.75% 2.75% 0.500% Greater than or equal to 90% 2.00% 3.00% 0.500%

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Roll Forward Of Asset Retirement Obligations	The following table sets forth asset retirement obligations for the years ended December 31, 2017 and 2016 : Years Ended December 31, 2017 2016 (In thousands) Beginning of year asset retirement obligations $21,240 $16,511 Liabilities incurred 3,920 2,137 Increase due to acquisition of oil and gas properties 153 2,037 Liabilities settled (343 ) (599 ) Reduction due to divestitures of oil and gas properties (2,671 ) — Accretion expense 1,799 1,364 Revisions to estimated cash flows (306 ) (210 ) End of year asset retirement obligations 23,792 21,240 Current asset retirement obligations (included in other current liabilities) (295 ) (392 ) Non-current asset retirement obligations $23,497 $20,848

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Total Minimum Commitments From Long-Term Non-Cancelable Operating Leases, Drilling Rig, Seismic And Pipeline Volume Commitments	total minimum commitments associated with long-term, non-cancelable operating and capital leases, drilling rig contracts and gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered as of December 31, 2017 . The total minimum commitments related to the drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. 2018 2019 2020 2021 2022 2023 and Thereafter Total (In thousands) Operating leases $5,038 $4,895 $4,637 $4,450 $1,854 $— $20,874 Capital leases 1,823 1,800 1,050 — — — 4,673 Drilling rig contracts 23,885 8,881 — — — — 32,766 Delivery commitments 3,657 3,676 2,757 2,438 10 26 12,564 Total $34,403 $19,252 $8,444 $6,888 $1,864 $26 $70,877

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2017
Preferred Stock [Abstract]
Schedule of Preferred Stock Dividends Paid in Common Stock	The Company may elect to pay all or a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending: Period Percentage On or after December 15, 2017 and on or prior to September 15, 2018 100 % On or after December 15, 2018 and on or prior to September 15, 2019 75 % On or after December 15, 2019 and on or prior to September 15, 2020 50 %
Schedule of Preferred Stock Redemption Premiums	After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends. Period Percentage After August 10, 2020 but on or prior to August 10, 2021 104.4375 % After August 10, 2021 but on or prior to August 10, 2022 102.21875 % After August 10, 2022 100 %
Preferred Stock	The table below summarizes Preferred Stock activity for the year ended December 31, 2017 : December 31, 2017 For the Year Ended December 31, 2017 Preferred Stock, beginning of period $— Relative fair value of Preferred Stock at issuance 213,400 Accretion of discount on Preferred Stock 862 Preferred Stock, end of period $214,262
Warrants, Valuation Assumptions	The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: Issuance Date Fair Value Assumptions Exercise price $16.08 Expected term (in years) 10.0 Expected volatility 62.9 % Risk-free interest rate 2.2 % Dividend yield — %

Shareholders' Equity And Stoc33

Shareholders' Equity And Stock Incentive Plan (Tables)	12 Months Ended
	Dec. 31, 2017
Shareholders' Equity And Stock Incentive Plan [Abstract]
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	The table below summarizes restricted stock award and unit activity for the years ended December 31, 2017 , 2016 and 2015 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2015 Unvested restricted stock awards and units, beginning of period 1,335,682 $34.55 Granted 401,421 $51.45 Vested (671,417 ) $32.96 Forfeited (23,689 ) $43.36 Unvested restricted stock awards and units, end of period 1,041,997 $44.22 For the Year Ended December 31, 2016 Unvested restricted stock awards and units, beginning of period 1,041,997 $44.22 Granted 887,254 $27.80 Vested (811,136 ) $36.32 Forfeited (6,405 ) $34.46 Unvested restricted stock awards and units, end of period 1,111,710 $36.93 For the Year Ended December 31, 2017 Unvested restricted stock awards and units, beginning of period 1,111,710 $36.93 Granted 1,020,465 $25.63 Vested (635,965 ) $39.62 Forfeited (13,555 ) $29.11 Unvested restricted stock awards and units, end of period 1,482,655 $28.07
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity	The table below summarizes the activity for SARs for the years ended December 31, 2017 , 2016 and 2015 : Stock Appreciation Rights Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Aggregate Intrinsic Value of Exercises (In millions) For the Year Ended December 31, 2015 Outstanding, beginning of period 765,198 $22.49 Granted — — Exercised (64,745 ) $29.40 $1.5 Forfeited — — Outstanding, end of period 700,453 $21.86 Vested, end of period 626,661 $21.05 Vested and exercisable, end of period 626,661 $21.05 For the Year Ended December 31, 2016 Outstanding, beginning of period 700,453 $21.86 Granted 376,260 27.30 Exercised (354,075 ) $23.89 $5.2 Forfeited — — Outstanding, end of period 722,638 $23.69 Vested, end of period 350,840 $19.87 Vested and exercisable, end of period 350,840 $19.87 For the Year Ended December 31, 2017 Outstanding, beginning of period 722,638 $23.69 Granted 342,440 $26.94 Exercised (219,279 ) $17.28 $2.1 Forfeited — — Expired (131,561 ) $24.19 Outstanding, end of period 714,238 $27.12 3.7 $— Vested, end of period 185,899 $27.30 Vested and exercisable, end of period — $27.30 3.2 $—
Schedule of Share-based Payment Award, Non-Options, Valuation Assumptions	The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the years ended December 31, 2017 and 2016 : Years Ended December 31, 2017 2016 Expected term (in years) 4.24 3.93 Expected volatility 54.3 % 45.1 % Risk-free interest rate 1.8 % 1.3 % Dividend yield — % — %
Schedule of Share-based Compensation, Performance Shares Award Activity	The table below summarizes performance share activity for the years ended December 31, 2017 , 2016 and 2015 : Target Performance Shares (1) Weighted Average Grant Date Fair Value For the Year Ended December 31, 2015 Unvested performance shares, beginning of period 56,342 $68.15 Granted 56,517 $65.51 Vested — — Forfeited — — Unvested performance shares, end of period 112,859 $66.83 For the Year Ended December 31, 2016 Unvested performance shares, beginning of period 112,859 $66.83 Granted 41,651 $35.71 Vested — — Forfeited — — Unvested performance shares, end of period 154,510 $58.44 For the Year Ended December 31, 2017 Unvested performance shares, beginning of period 154,510 $58.44 Granted 46,787 $35.14 Vested (56,342 ) $68.15 Forfeited — — Unvested performance shares, end of period 144,955 $47.14 (1) The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company ’ s final TSR ranking for the approximate three year performance period.
Schedule of Share-based Payment Award, Performance Share Award, Valuation Assumptions	The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the years ended December 31, 2017 , 2016 and 2015 : Years Ended December 31, 2017 2016 2015 Number of simulations 500,000 500,000 500,000 Expected term (in years) 2.98 3.01 2.89 Expected volatility 59.2 % 55.3 % 45.3 % Risk-free interest rate 1.5 % 1.2 % 0.9 % Dividend yield — % — % — %
Summary Of Stock Options Activity
Schedule of Compensation Cost, Allocation of Share-based Compensation Costs by Plan	The Company recognized the following stock-based compensation expense, net for the periods indicated: Years Ended December 31, 2017 2016 2015 (In thousands) Restricted stock awards and units $21,372 $28,196 $23,668 Stock appreciation rights (5,023 ) 9,675 (6,326 ) Performance shares 2,442 2,806 1,961 18,791 40,677 19,303 Less: amounts capitalized to oil and gas properties (4,482 ) (4,591 ) (4,574 ) Total stock-based compensation expense, net $14,309 $36,086 $14,729

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative [Line Items]
Schedule of Contingent Consideration	The following table summarizes the combined contingent consideration recorded in the consolidated financial statements: Consolidated Balance Sheets Consolidated Statements of Operations December 31, 2017 Year Ended December 31, 2017 Other Assets - Non-Current Derivative Liabilities - Non-Current (Gain) Loss on Derivatives, Net (In thousands) Contingent ExL Consideration $— ($85,625 ) $33,325 Contingent Utica Consideration 7,985 — (1,840 ) Contingent Marcellus Consideration 2,205 — 455 Contingent consideration $10,190 ($85,625 ) $31,940
Schedule of Derivative Instrument Fair Value Assets and Liabilities	The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the consolidated balance sheets as of December 31, 2017 and 2016 are summarized below: December 31, 2017 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $4,869 ($4,869 ) $— Deferred premium obligations — — — Other current assets $4,869 ($4,869 ) $— Commodity derivative instruments 9,505 (9,505 ) — Deferred premium obligations — — — Contingent consideration 10,190 — 10,190 Other assets-non current $19,695 ($9,505 ) $10,190 Commodity derivative instruments ($52,671 ) $4,869 ($47,802 ) Deferred premium obligations (9,319 ) — (9,319 ) Derivative liabilities-current ($61,990 ) $4,869 ($57,121 ) Commodity derivative instruments (24,609 ) 9,505 (15,104 ) Deferred premium obligations (11,603 ) — (11,603 ) Contingent consideration (85,625 ) — (85,625 ) Derivative liabilities-non current ($121,837 ) $9,505 ($112,332 ) December 31, 2016 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Commodity derivative instruments $7,990 ($6,753 ) $1,237 Deferred premium obligations — — — Other current assets $7,990 ($6,753 ) $1,237 Commodity derivative instruments 3,882 (3,882 ) — Deferred premium obligations — — — Contingent consideration — — — Other assets-non current $3,882 ($3,882 ) $— Commodity derivative instruments ($27,346 ) $6,753 ($20,593 ) Deferred premium obligations (2,008 ) — (2,008 ) Derivative liabilities-current ($29,354 ) $6,753 ($22,601 ) Commodity derivative instruments (28,841 ) 3,882 (24,959 ) Deferred premium obligations (2,569 ) — (2,569 ) Contingent consideration — — — Derivative liabilities-non current ($31,410 ) $3,882 ($27,528 )
Derivative Instruments, (Gain) Loss	The effect of derivative instruments and deferred premium obligations in the consolidated statements of operations for the years ended December 31, 2017 , 2016 , and 2015 is summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) (Gain) Loss on Derivatives, Net Crude oil $22,839 $23,609 ($99,624 ) Natural gas liquids 1,322 — — Natural gas (15,399 ) 19,584 (4,063 ) Deferred premium obligations incurred 18,401 5,880 4,426 Contingent consideration 31,940 — — Total (Gain) Loss on Derivatives, Net $59,103 $49,073 ($99,261 )
Schedule of Cash Received for Derivatives	The effect of commodity derivative instruments and deferred premium obligations in the consolidated statements of cash flows for the years ended December 31, 2017 , 2016 , and 2015 is summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) Cash Received (Paid) for Derivative Settlements, Net Crude oil $9,883 $125,098 $176,511 Natural gas (54 ) — 17,785 Deferred premium obligations paid (2,056 ) (5,729 ) — Total Cash Received (Paid) for Derivative Settlements, Net $7,773 $119,369 $194,296
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Fixed Price Swaps Period Volumes (Bbls/d) NYMEX Price ($/Bbl) FY 2018 6,000 $49.55
Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Basis Swaps Period Volumes (Bbls/d) LLS-NYMEX Price Differential ($/Bbl) FY 2018 6,000 $2.91 Period Volumes (Bbls/d) Midland-NYMEX Price Differential ($/Bbl) FY 2018 6,000 ($0.10 )
Crude Oil [Member] | Three-way Collars [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Three-Way Collars NYMEX Prices Period Volumes (Bbls/d) Sub-Floor Price ($/Bbl) Floor Price ($/Bbl) Ceiling Price ($/Bbl) FY 2018 24,000 $39.38 $49.06 $60.14 FY 2019 12,000 $40.00 $48.40 $60.29
Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Net Sold Call Options Period Volumes (Bbls/d) NYMEX Ceiling Price ($/Bbl) FY 2018 3,388 $71.33 FY 2019 3,875 $73.66 FY 2020 4,575 $75.98
Natural Gas Liquids [Member] | Swap [Member]
Derivative [Line Items]
Schedule of Derivative Positions	NGL Fixed Price Swaps OPIS Purity Ethane Mont Belvieu Non-TET OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET Period Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) Volumes (Bbls/d) Price ($/Bbl) FY 2018 2,200 $12.01 1,500 $34.23 200 $38.85 600 $38.98 600 $55.23
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Schedule of Derivative Positions	In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below: Natural Gas Fixed Price Swaps Period Volumes (MMBtu/d) NYMEX Price ($/MMBtu) March 2018 - December 2018 25,000 $3.01
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Natural Gas Sold Call Options Period Volumes (MMBtu/d) NYMEX Ceiling Price ($/MMBtu) FY 2018 33,000 $3.25 FY 2019 33,000 $3.25 FY 2020 33,000 $3.50

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Assets And Liabilities Measured At Fair Value On A Recurring Basis	The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016 : December 31, 2017 Level 1 Level 2 Level 3 (In thousands) Derivative instrument assets $— $— $10,190 Derivative instrument liabilities $— ($62,906 ) ($85,625 ) December 31, 2016 Level 1 Level 2 Level 3 (In thousands) Derivative instrument assets $— $1,237 $— Derivative instrument liabilities $— ($45,552 ) $—
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	Year Ended December 31, 2017 (In thousands) Fair value assets, beginning of period $— Recognition of acquisition date fair value 8,805 Gain (loss) on changes in fair value (1) 1,385 Transfers into (out of) Level 3 — Fair value assets, end of period $10,190
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	Year Ended December 31, 2017 (In thousands) Fair value liability, beginning of period $— Recognition of acquisition date fair value (52,300 ) Gain (loss) on changes in fair value (1) (33,325 ) Transfers into (out of) Level 3 — Fair value liability, end of period ($85,625 )
Schedule of Fair Value of Debt Instruments	The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of unamortized premiums and debt issuance costs, with the fair values measured using quoted secondary market trading prices. December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) 7.50% Senior Notes due 2020 (1) $446,087 $459,518 $593,447 $624,750 6.25% Senior Notes due 2023 641,792 674,375 640,546 672,750 8.25% Senior Notes due 2025 245,605 274,375 — — Other long-term debt due 2028 4,425 4,445 4,425 4,419 (1) The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017 .

Condensed Consolidating Finan36

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	13. Condensed Consolidating Financial Information The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities. CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,441,633 $105,533 $— ($3,424,288 ) $122,878 Total property and equipment, net 5,953 2,630,707 3,028 (3,878 ) 2,635,810 Investment in subsidiaries (999,793 ) — — 999,793 — Other assets 9,270 10,346 — — 19,616 Total Assets $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 Liabilities and Shareholders’ Equity Current liabilities $165,701 $3,631,401 $3,028 ($3,427,308 ) $372,822 Long-term liabilities 1,689,466 114,978 — 15,879 1,820,323 Preferred stock 214,262 — — — 214,262 Total shareholders’ equity 387,634 (999,793 ) — 983,056 370,897 Total Liabilities and Shareholders’ Equity $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,735,830 $63,513 $— ($2,726,355 ) $72,988 Total property and equipment, net 42,181 1,503,695 3,800 (3,916 ) 1,545,760 Investment in subsidiaries (1,282,292 ) — — 1,282,292 — Other assets 7,423 156 — — 7,579 Total Assets $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 Liabilities and Shareholders’ Equity Current liabilities $114,805 $2,822,729 $3,800 ($2,729,375 ) $211,959 Long-term liabilities 1,348,105 26,927 — 15,878 1,390,910 Preferred stock — — — — — Total shareholders’ equity 40,232 (1,282,292 ) — 1,265,518 23,458 Total Liabilities and Shareholders’ Equity $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $302 $745,586 $— $— $745,888 Total costs and expenses 195,728 459,057 — (37 ) 654,748 Income (loss) from continuing operations before income taxes (195,426 ) 286,529 — 37 91,140 Income tax expense — (4,030 ) — — (4,030 ) Equity in income of subsidiaries 282,499 — — (282,499 ) — Income from continuing operations $87,073 $282,499 $— ($282,462 ) $87,110 Income from discontinued operations, net of income taxes — — — — — Net income $87,073 $282,499 $— ($282,462 ) $87,110 Dividends on preferred stock (7,781 ) — — — (7,781 ) Accretion on preferred stock (862 ) — — — (862 ) Net income attributable to common shareholders $78,430 $282,499 $— ($282,462 ) $78,467 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $482 $443,112 $— $— $443,594 Total costs and expenses 208,054 910,522 — 492 1,119,068 Loss from continuing operations before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax benefit — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Loss from continuing operations ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Income from discontinued operations, net of income taxes — — — — — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Net loss attributable to common shareholders ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $1,708 $427,495 $— $— $429,203 Total costs and expenses 95,464 1,603,515 — 28,984 1,727,963 Loss from continuing operations before income taxes (93,756 ) (1,176,020 ) — (28,984 ) (1,298,760 ) Income tax benefit 10,125 127,010 — 3,740 140,875 Equity in loss of subsidiaries (1,049,010 ) — — 1,049,010 — Loss from continuing operations ($1,132,641 ) ($1,049,010 ) $— $1,023,766 ($1,157,885 ) Income from discontinued operations, net of income taxes 2,731 — — — 2,731 Net loss ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Net loss attributable to common shareholders ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($121,107 ) $544,088 $— $— $422,981 Net cash used in investing activities from continuing operations (615,364 ) (1,155,340 ) — 611,252 (1,159,452 ) Net cash provided by financing activities from continuing operations 741,817 611,252 — (611,252 ) 741,817 Net cash used in discontinued operations — — — — — Net increase in cash and cash equivalents 5,346 — — — 5,346 Cash and cash equivalents, beginning of year 4,194 — — — 4,194 Cash and cash equivalents, end of year $9,540 $— $— $— $9,540 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities from continuing operations (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities from continuing operations 308,340 268,283 740 (269,023 ) 308,340 Net cash used in discontinued operations — — — — — Net decrease in cash and cash equivalents (38,724 ) — — — (38,724 ) Cash and cash equivalents, beginning of year 42,918 — — — 42,918 Cash and cash equivalents, end of year $4,194 $— $— $— $4,194 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities from continuing operations $2,655 $376,080 $— $— $378,735 Net cash used in investing activities from continuing operations (447,296 ) (674,758 ) — 448,678 (673,376 ) Net cash provided by financing activities from continuing operations 480,767 298,678 — (448,678 ) 330,767 Net cash used in discontinued operations (4,046 ) — — — (4,046 ) Net increase in cash and cash equivalents 32,080 — — — 32,080 Cash and cash equivalents, beginning of year 10,838 — — — 10,838 Cash and cash equivalents, end of year $42,918 $— $— $— $42,918
Schedule Of Condensed Consolidating Balance Sheets	CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $3,441,633 $105,533 $— ($3,424,288 ) $122,878 Total property and equipment, net 5,953 2,630,707 3,028 (3,878 ) 2,635,810 Investment in subsidiaries (999,793 ) — — 999,793 — Other assets 9,270 10,346 — — 19,616 Total Assets $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 Liabilities and Shareholders’ Equity Current liabilities $165,701 $3,631,401 $3,028 ($3,427,308 ) $372,822 Long-term liabilities 1,689,466 114,978 — 15,879 1,820,323 Preferred stock 214,262 — — — 214,262 Total shareholders’ equity 387,634 (999,793 ) — 983,056 370,897 Total Liabilities and Shareholders’ Equity $2,457,063 $2,746,586 $3,028 ($2,428,373 ) $2,778,304 December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,735,830 $63,513 $— ($2,726,355 ) $72,988 Total property and equipment, net 42,181 1,503,695 3,800 (3,916 ) 1,545,760 Investment in subsidiaries (1,282,292 ) — — 1,282,292 — Other assets 7,423 156 — — 7,579 Total Assets $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327 Liabilities and Shareholders’ Equity Current liabilities $114,805 $2,822,729 $3,800 ($2,729,375 ) $211,959 Long-term liabilities 1,348,105 26,927 — 15,878 1,390,910 Preferred stock — — — — — Total shareholders’ equity 40,232 (1,282,292 ) — 1,265,518 23,458 Total Liabilities and Shareholders’ Equity $1,503,142 $1,567,364 $3,800 ($1,447,979 ) $1,626,327
Schedule Of Condensed Consolidating Statements Of Operations	CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $302 $745,586 $— $— $745,888 Total costs and expenses 195,728 459,057 — (37 ) 654,748 Income (loss) from continuing operations before income taxes (195,426 ) 286,529 — 37 91,140 Income tax expense — (4,030 ) — — (4,030 ) Equity in income of subsidiaries 282,499 — — (282,499 ) — Income from continuing operations $87,073 $282,499 $— ($282,462 ) $87,110 Income from discontinued operations, net of income taxes — — — — — Net income $87,073 $282,499 $— ($282,462 ) $87,110 Dividends on preferred stock (7,781 ) — — — (7,781 ) Accretion on preferred stock (862 ) — — — (862 ) Net income attributable to common shareholders $78,430 $282,499 $— ($282,462 ) $78,467 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $482 $443,112 $— $— $443,594 Total costs and expenses 208,054 910,522 — 492 1,119,068 Loss from continuing operations before income taxes (207,572 ) (467,410 ) — (492 ) (675,474 ) Income tax benefit — — — — — Equity in loss of subsidiaries (467,410 ) — — 467,410 — Loss from continuing operations ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Income from discontinued operations, net of income taxes — — — — — Net loss ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Net loss attributable to common shareholders ($674,982 ) ($467,410 ) $— $466,918 ($675,474 ) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $1,708 $427,495 $— $— $429,203 Total costs and expenses 95,464 1,603,515 — 28,984 1,727,963 Loss from continuing operations before income taxes (93,756 ) (1,176,020 ) — (28,984 ) (1,298,760 ) Income tax benefit 10,125 127,010 — 3,740 140,875 Equity in loss of subsidiaries (1,049,010 ) — — 1,049,010 — Loss from continuing operations ($1,132,641 ) ($1,049,010 ) $— $1,023,766 ($1,157,885 ) Income from discontinued operations, net of income taxes 2,731 — — — 2,731 Net loss ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 ) Dividends on preferred stock — — — — — Accretion on preferred stock — — — — — Net loss attributable to common shareholders ($1,129,910 ) ($1,049,010 ) $— $1,023,766 ($1,155,154 )
Schedule Of Condensed Consolidating Statements Of Cash Flows	CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($121,107 ) $544,088 $— $— $422,981 Net cash used in investing activities from continuing operations (615,364 ) (1,155,340 ) — 611,252 (1,159,452 ) Net cash provided by financing activities from continuing operations 741,817 611,252 — (611,252 ) 741,817 Net cash used in discontinued operations — — — — — Net increase in cash and cash equivalents 5,346 — — — 5,346 Cash and cash equivalents, beginning of year 4,194 — — — 4,194 Cash and cash equivalents, end of year $9,540 $— $— $— $9,540 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($34,773 ) $307,541 $— $— $272,768 Net cash used in investing activities from continuing operations (312,291 ) (575,824 ) (740 ) 269,023 (619,832 ) Net cash provided by financing activities from continuing operations 308,340 268,283 740 (269,023 ) 308,340 Net cash used in discontinued operations — — — — — Net decrease in cash and cash equivalents (38,724 ) — — — (38,724 ) Cash and cash equivalents, beginning of year 42,918 — — — 42,918 Cash and cash equivalents, end of year $4,194 $— $— $— $4,194 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities from continuing operations $2,655 $376,080 $— $— $378,735 Net cash used in investing activities from continuing operations (447,296 ) (674,758 ) — 448,678 (673,376 ) Net cash provided by financing activities from continuing operations 480,767 298,678 — (448,678 ) 330,767 Net cash used in discontinued operations (4,046 ) — — — (4,046 ) Net increase in cash and cash equivalents 32,080 — — — 32,080 Cash and cash equivalents, beginning of year 10,838 — — — 10,838 Cash and cash equivalents, end of year $42,918 $— $— $— $42,918

Supplemental Cash Flow Inform37

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Years Ended December 31, 2017 2016 2015 (In thousands) Supplemental cash flow disclosures: Cash paid for interest, net of amounts capitalized $77,213 $75,231 $64,692 Cash paid for income taxes — — — Non-cash investing and financing activities: Increase (decrease) in capital expenditure payables and accruals $102,272 ($21,492 ) ($86,878 ) Contingent consideration related to acquisitions of oil and gas properties 52,300 — — Contingent consideration related to divestitures of oil and gas properties (8,805 ) — — Liabilities assumed in connection with the Sanchez Acquisition — 4,880 — Stock-based compensation expense capitalized to oil and gas properties 4,482 4,591 4,574 Asset retirement obligations capitalized to oil and gas properties 3,726 1,927 4,853

Subsequent Events (Unaudited) (

Subsequent Events (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Schedule of Derivative Positions	In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below: Natural Gas Fixed Price Swaps Period Volumes (MMBtu/d) NYMEX Price ($/MMBtu) March 2018 - December 2018 25,000 $3.01

Supplemental Disclosures Abou39

Supplemental Disclosures About Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities	Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) Property acquisition costs Proved properties $303,307 $90,661 $— Unproved properties 525,061 113,535 63,446 Total property acquisition costs 828,368 204,196 63,446 Exploration costs 91,098 37,508 117,227 Development costs 569,982 374,134 389,396 Total costs incurred $1,489,448 $615,838 $570,069
Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas Reserves	The Company’s proved reserves and changes in proved reserves are as follows: Crude Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total Proved Reserves (MBoe) Proved reserves: January 1, 2015 100,704 13,513 221,017 151,053 Extensions and discoveries 26,358 5,292 33,925 37,304 Revisions of previous estimates (9,059 ) 2,768 11,808 (4,323 ) Production (8,415 ) (1,352 ) (21,812 ) (13,402 ) December 31, 2015 109,588 20,221 244,938 170,632 Extensions and discoveries 40,074 8,612 59,318 58,572 Revisions of previous estimates (16,731 ) (3,230 ) 1,481 (19,713 ) Purchases of reserves in place 4,810 122 7,282 6,145 Production (9,423 ) (1,788 ) (25,574 ) (15,473 ) December 31, 2016 128,318 23,937 287,445 200,163 Extensions and discoveries 50,476 13,781 98,980 80,754 Revisions of previous estimates (19,838 ) (909 ) 27,774 (16,118 ) Purchases of reserves in place 21,634 8,642 94,962 46,103 Sales of reserves in place (650 ) (526 ) (170,219 ) (29,546 ) Production (12,566 ) (2,327 ) (28,472 ) (19,639 ) December 31, 2017 167,374 42,598 310,470 261,717 Proved developed reserves: December 31, 2014 35,238 5,294 149,697 65,482 December 31, 2015 42,311 7,933 154,725 76,032 December 31, 2016 51,062 9,387 187,054 91,625 December 31, 2017 69,632 17,447 131,355 108,972 Proved undeveloped reserves: December 31, 2014 65,466 8,219 71,320 85,571 December 31, 2015 67,277 12,288 90,213 94,600 December 31, 2016 77,256 14,550 100,391 108,538 December 31, 2017 97,742 25,151 179,115 152,745 Extensions and discoveries For the year ended December 31, 2017, the Company added 6,473 MBoe of proved developed reserves and 74,281 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 51% and 48% , respectively, of the total extensions and discoveries. For the year ended December 31, 2016, the Company added 6,525 MBoe of proved developed reserves and 52,047 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20% , respectively, of the total extensions and discoveries. For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries. Revisions of previous estimates For the year ended December 31, 2017, revisions of previous estimates reduced the Company’s proved reserves by 16,118 MBoe. Included in revisions of previous estimates were: • Positive revisions due to price of 2,684 MBoe. • Negative revisions due to performance of 4,500 MBoe primarily in the Eagle Ford due to a downward shift of the type curve for certain PUD locations partially offset by positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017. • Negative revisions in proved undeveloped reserves of 14,302 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the recent ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads. For the year ended December 31, 2016, revisions of previous estimates reduced the Company’s proved reserves by 19,713 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 6,705 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 3,228 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 3,477 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations due to loss of tail reserves; • Negative revisions due to performance of 6,083 MBoe primarily in Eagle Ford as the EURs for certain PUD locations were reduced as a result of tighter spacing and shorter lateral lengths partially offset by positive revisions in Marcellus; • Negative revisions in proved undeveloped reserves of 6,925 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the move to a more efficient development plan which includes drilling and completing larger pads and the recent Sanchez Acquisition. For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were: • Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives; • Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus. Purchases of reserves in place For the year ended December 31, 2017, purchases of reserves in place included 26,009 MBoe of proved developed reserves and 20,094 MBoe of proved undeveloped reserves associated with the ExL Acquisition. For the year ended December 31, 2016, purchases of reserves in place included 4,978 MBoe of proved developed reserves and 1,167 MBoe of proved undeveloped reserves associated with the Sanchez Acquisition. There were no purchases of reserves in place for the year ended December 31, 2015. Sales of reserves in place For the year ended December 31, 2017, sales of reserves in place included 22,249 MBoe of proved developed reserves and 7,297 MBoe of proved undeveloped reserves associated with the Marcellus Shale and Utica Shale divestitures. There were no sales of reserves in place for the years ended December 31, 2016 and 2015.
Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2017 2016 2015 (In thousands) Future cash inflows $10,109,752 $5,903,629 $5,878,348 Future production costs (3,202,201 ) (2,241,928 ) (2,124,059 ) Future development costs (1,699,909 ) (1,264,493 ) (1,178,773 ) Future income taxes (1) (445,056 ) — — Future net cash flows 4,762,586 2,397,208 2,575,516 Less 10% annual discount to reflect timing of cash flows (2,297,544 ) (1,093,779 ) (1,210,292 ) Standard measure of discounted future net cash flows $2,465,042 $1,303,429 $1,365,224 (1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016 and 2015.
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below: Years Ended December 31, 2017 2016 2015 (In thousands) Standardized measure at beginning of year $1,303,429 $1,365,224 $2,555,082 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production $710,773 ($346,763 ) ($2,547,213 ) Net change in estimated future development costs (51,854 ) 74,407 342,238 Net change due to revisions in quantity estimates (42,214 ) (150,245 ) (157,271 ) Accretion of discount 130,343 136,522 326,074 Changes in production rates (timing) and other (116,056 ) (111,137 ) (139,533 ) Total revisions to reserves proved in prior years 630,992 (397,216 ) (2,175,705 ) Net change due to extensions and discoveries, net of estimated future development and production costs 597,502 313,201 252,155 Net change due to purchases of reserves in place 452,932 43,426 — Net change due to divestitures of reserves in place (106,608 ) — — Sales of crude oil, NGLs and natural gas produced, net of production costs (566,258 ) (320,272 ) (312,213 ) Previously estimated development costs incurred 326,383 299,066 340,247 Net change in income taxes (173,330 ) — 705,658 Net change in standardized measure of discounted future net cash flows 1,161,613 (61,795 ) (1,189,858 ) Standardized measure at end of year $2,465,042 $1,303,429 $1,365,224

Selected Quarterly Financial 40

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2017 and 2016 : Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter (2) Fourth Quarter (3) (In thousands, except per share data) Total revenues $151,355 $166,483 $181,279 $246,771 Operating profit (1) $57,953 $63,147 $69,364 $113,205 (Gain) loss on derivatives, net ($25,316 ) ($26,065 ) $24,377 $86,107 Net income (loss) $40,021 $56,306 $7,823 ($17,040 ) Net income (loss) attributable to common shareholders $40,021 $56,306 $5,574 ($23,434 ) Net income (loss) attributable to common shareholders per common share (3) Basic $0.61 $0.86 $0.07 ($0.29 ) Diluted $0.61 $0.85 $0.07 ($0.29 ) Year Ended December 31, 2016 First Quarter (4) Second Quarter (4) Third Quarter (4) Fourth Quarter (In thousands, except per share data) Total revenues $81,262 $107,324 $111,177 $143,831 Operating profit (loss) (1) ($7,491 ) $27,167 $31,634 $55,000 Net loss ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss attributable to common shareholders ($311,395 ) ($262,126 ) ($101,174 ) ($779 ) Net loss attributable to common shareholders per common share (3) Basic ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) Diluted ($5.34 ) ($4.46 ) ($1.72 ) ($0.01 ) (1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A. (2) Third quarter of 2017 included the following: a. $2.2 million of Preferred Stock dividends which reduced net income attributable to common shareholders. (3) Fourth quarter of 2017 included the following: a. $4.2 million loss on extinguishment of debt as a result of the redemption of $150.0 million aggregate principal amount of 7.50% Senior Notes. b. $5.5 million of Preferred Stock dividends which increased net loss attributable to common shareholders. (4) The sum of quarterly net income (loss) attributable to common shareholders per common share does not agree with the total year net income (loss) attributable to common shareholders per common share as each computation is based on the weighted average of common shares outstanding during the period. (5) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million , $197.1 million , and $105.1 million , respectively.

Summary of Significant Accoun41

Summary of Significant Accounting Policies (Narrative) (Details) shares in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)$ / Boeshares	Dec. 31, 2016USD ($)$ / Boeshares	Dec. 31, 2015USD ($)$ / Boeshares	Jan. 01, 2017USD ($)
Summary Of Significant Accounting Policies [Line Items]
Due to Related Parties				$ 100,000
Other Accounts Payable and Accrued Liabilities				62,600,000	$ 34,300,000
Allowance for doubtful accounts receivable				400,000	800,000
Due from Related Parties, Current				100,000	900,000
Internal costs capitalized, oil and gas producing activities				$ 14,800,000	$ 10,500,000	$ 15,800,000
Average DD&A Per Boe (in USD per BOE) | $ / Boe				13.09	13.50	22.05
Capitalized interest				$ 28,300,000	$ 17,000,000	$ 32,100,000
Reserves discount factor				10.00%
Impairment of proved oil and gas properties	$ 105,100,000	$ 197,100,000	$ 274,400,000	$ 0	576,540,000	$ 1,224,367,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount				(247,100,000)
Deferred Tax Assets, Valuation Allowance				333,029,000	$ 564,434,000		$ 580,100,000
Deferred Tax Assets, Net				$ 0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares				52	669	649
Tax Adjustments, Settlements, and Unusual Provisions				$ 15,700,000
Tax Adjustments, Settlements, and Unusual Provisions, Retained Earnings Effect				$ 0
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life, minimum, years				3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life, minimum, years				10 years
Restricted Stock Awards And Units [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				1 year
Restricted Stock Awards And Units [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years
Stock Appreciation Rights (SARs) [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				2 years
Expiration period, in years				4 years
Stock Appreciation Rights (SARs) [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years
Expiration period, in years				7 years
Performance Shares [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years
Performance Shares [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Range of Awards to Vest Based on Market Condition				0.00%
Performance Shares [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Range of Awards to Vest Based on Market Condition				200.00%
Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Customer percentage of total revenue				69.00%	56.00%	65.00%
Customer Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Customer percentage of total revenue				7.00%	15.00%	9.00%
Contractor [Member] | Restricted Stock Awards And Units [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years

Summary of Significant Accoun42

Summary of Significant Accounting Policies (Schedule of Earnings Per Share Reconciliation) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Attributable to Common Shareholders	$ (23,434)	$ 5,574	$ 56,306	$ 40,021	$ (779)	$ (101,174)	$ (262,126)	$ (311,395)	$ 78,467	$ (675,474)	$ (1,155,154)
Weighted Average Number of Shares Outstanding, Basic									73,421	59,932	51,457
Weighted Average Number Diluted Shares Outstanding Adjustment									572	0	0
Effect of dilutive instruments
Weighted Average Number of Shares Outstanding, Diluted									73,993	59,932	51,457
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Net Income (Loss) Attributable to Common Shareholders, Per Basic Share	$ (0.29)	$ 0.07	$ 0.86	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.07	$ (11.27)	$ (22.45)
Net Income (Loss) Attributable to Common Shareholders, Per Diluted Share	$ (0.29)	$ 0.07	$ 0.85	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.06	$ (11.27)	$ (22.45)

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Schedule of Antidilutive Shares Excluded from Earnings Per Share) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Number Diluted Shares Outstanding Adjustment	572	0	0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	52	669	649

Acquisitions and Divestitures44

Acquisitions and Divestitures (Narrative) (Details)

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

15 Months Ended

Dec. 31, 2016USD ($)

Oct. 31, 2016USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2017USD ($)$ / bbls$ / MMBTU

Sep. 30, 2017USD ($)$ / bbls

Jun. 30, 2017USD ($)$ / bbls

Mar. 31, 2017USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2017USD ($)

Dec. 11, 2017USD ($)

Nov. 20, 2017USD ($)

Oct. 05, 2017USD ($)

Aug. 31, 2017USD ($)

Aug. 10, 2017USD ($)

Jun. 28, 2017USD ($)

Business Acquisition [Line Items]

Payments to Acquire Oil and Gas Property

$ 695,774,000

$ 153,521,000

$ 1,817,000

Business Combination, Contingent Consideration, Liability, Noncurrent

$ 85,625,000

85,625,000

$ 85,625,000

Net proceeds from divestitures of oil and gas properties

197,564,000

15,564,000

$ 8,047,000

Business Combination, Contingent Consideration, Liability

$ 52,300,000

ExL Acquisition [Member]

Business Acquisition [Line Items]

Agreed Upon Purchase Price of Oil and Gas Property and Equipment

$ 648,000,000

Payments to Acquire Oil and Gas Property

$ 75,000,000

$ 679,800,000

Percentage of Working Interest Subsequent to Acquisition

70.00%

70.00%

70.00%

Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls

50

Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High

$ 125,000,000

Business Combination, Contingent Consideration, Liability, Noncurrent

$ 85,625,000

$ 85,625,000

$ 85,625,000

$ 52,300,000

Revenue of Acquiree since Acquisition Date, Actual

53,500,000

Earnings (Loss) of Acquiree since Acquisition Date, Actual

44,300,000

Sanchez Acquisition [Member]

Business Acquisition [Line Items]

Agreed Upon Purchase Price of Oil and Gas Property and Equipment

$ 181,000,000

Payments to Acquire Oil and Gas Property

$ 143,500,000

$ 10,000,000

$ 9,800,000

$ 7,000,000

$ 170,300,000

Revenue of Acquiree since Acquisition Date, Actual

37,800,000

Earnings (Loss) of Acquiree since Acquisition Date, Actual

16,500,000

Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Agreed Upon Sale Price of Oil and Gas Property and Equipment

$ 62,000,000

Net proceeds from divestitures of oil and gas properties

63,100,000

Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture

5,000,000

Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High

$ 7,500,000

Agreed Upon Sale Price of Oil and Gas Property and Equipment

$ 84,000,000

Net proceeds from divestitures of oil and gas properties

73,900,000

Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture

3,000,000

Niobrara Divestiture [Member]

Business Acquisition [Line Items]

Agreed Upon Sale Price of Oil and Gas Property and Equipment

$ 140,000,000

Niobrara Divestiture [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 136,600,000

Eagle Ford Shale Divestiture [Member]

Business Acquisition [Line Items]

Agreed Upon Sale Price of Oil and Gas Property and Equipment

$ 245,000,000

Eagle Ford Shale Divestiture [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 246,200,000

Minimum [Member] | ExL Acquisition [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition

0

Minimum [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture

$ 0

Minimum [Member] | Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture

0

Minimum [Member] | Niobrara Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture

$ 0

Maximum [Member] | ExL Acquisition [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition

$ 50,000,000

2018 [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls

50

2018 [Member] | Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU

3.13

2019 [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls

53

2019 [Member] | Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU

3.18

2020 [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls

56

2020 [Member] | Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU

3.30

2020 [Member] | Niobrara Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls

60

Two Thousand Eighteen and Two Thousand Nineteen [Member] | Niobrara Divestiture [Member]

Business Acquisition [Line Items]

Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls

55

Delaware Basin [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 15,300,000

Deposit Received Prior To Closing [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 6,200,000

Deposit Received Prior To Closing [Member] | Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 6,300,000

Deposit Received Prior To Closing [Member] | Niobrara Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 14,000,000

Deposit Received Prior To Closing [Member] | Eagle Ford Shale Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

24,500,000

Cash Received At Closing [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

54,400,000

Cash Received At Closing [Member] | Marcellus Shale Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

67,600,000

Cash Received At Closing [Member] | Niobrara Divestiture [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 122,600,000

Cash Received At Closing [Member] | Eagle Ford Shale Divestiture [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

211,700,000

Cash Received Post Closing [Member] | Utica Shale Divestiture [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

2,500,000

Cash Received Post Closing [Member] | Eagle Ford Shale Divestiture [Member] | Subsequent Event [Member]

Business Acquisition [Line Items]

Net proceeds from divestitures of oil and gas properties

$ 10,000,000

Cash Paid At Closing [Member] | ExL Acquisition [Member]

Business Acquisition [Line Items]

Payments to Acquire Oil and Gas Property

$ 601,000,000

Cash Paid Post Closing [Member] | ExL Acquisition [Member]

Business Acquisition [Line Items]

Payments to Acquire Oil and Gas Property

$ 3,800,000

Acquisitions and Divestitures45

Acquisitions and Divestitures (Schedule of Consideration Paid for Assets Acquired and Liabilities Assumed) (Table) (Details) - USD ($) $ in Thousands	Aug. 10, 2017	Dec. 14, 2016
Acquisitions - Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract]
Business Combination, Current Assets	$ 106	$ 477
Business Combination, Oil and Gas Properties, Net	294,754	99,938
Business Combination, Recognized Assets Acquired and Liabilities Assumed, Unproved Oil and Gas Properties	443,194	74,536
Business Combination, Recognized Assets Acquired and Liabilities Assumed, Oil and Gas Properties	737,948	174,474
Business Combination, Total Assets	738,054	174,951
Business Combination, Current Liabilities	5,785	1,442
Business Combination, Other Liabilities		323
Business Combination, Noncurrent Liabilities	153	2,054
Business Combination, Contingent Consideration, Liability	52,300
Business Combination, Other Noncurrent Liabilities		1,078
Business Combination, Liabilities	58,238	4,897
Business Combination, Net	$ 679,816	$ 170,054

Acquisitions and Divestitures46

Acquisitions and Divestitures (Schedule of Results of Operations) (Table) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Acquisitions - Results of Operations [Abstract]
Business Acquisition, Pro Forma Revenue	$ 781,378	$ 454,913
Business Acquisition, Pro Forma Net Income (Loss)	$ 91,931	$ (688,180)
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 1.25	$ (9.11)
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 1.24	$ (9.11)
Weighted Average Basic Shares Outstanding, Pro Forma	73,421	75,532
Pro Forma Weighted Average Shares Outstanding, Diluted	73,993	75,532

Property And Equipment, Net (Na

Property And Equipment, Net (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Unproved properties, not being amortized				$ 660,287	$ 240,961
Capitalized costs of unproved properties				523,100	106,800	$ 24,000
Impairment of proved oil and gas properties	$ 105,100	$ 197,100	$ 274,400	$ 0	$ 576,540	$ 1,224,367

Property And Equipment, Net (Sc

Property And Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Proved properties, net	$ 5,615,153	$ 4,687,416
Accumulated DD&A and impairments	3,649,806	3,392,749
Proved properties, net	1,965,347	1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	612,589	211,067
Capitalized interest	47,698	29,894
Total unproved properties, not being amortized	660,287	240,961
Other property and equipment	25,625	23,127
Accumulated depreciation	(15,449)	(12,995)
Other property and equipment, net	10,176	10,132
Total property and equipment, net	$ 2,635,810	$ 1,545,760

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 01, 2017
Income Taxes [Line Items]
U.S. federal statutory corporate pretax rate			35.00%
Deferred State and Local Income Tax Expense (Benefit)			$ 3,635,000	$ 0	$ (9,373,000)
Income Tax Rate Reconciliation, US Federal Rate Reduction			211,724,000	0	0
Valuation Allowance, Effect Of Tax Cuts And Jobs Act			211,724,000
Deferred Tax Assets, Net			0
Tax Adjustments, Settlements, and Unusual Provisions			15,700,000
Tax Adjustments, Settlements, and Unusual Provisions, Retained Earnings Effect			0
Deferred Tax Assets, Valuation Allowance			333,029,000	564,434,000		$ 580,100,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount			(247,100,000)
Partial Release Of Valuation Allowance			35,400,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local			$ 12,700,000
Ownership percentage change			5.00%
Change in beneficial ownership, percentage			50.00%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount			$ (35,376,000)	240,864,000	323,586,000
Income Tax Expense (Benefit)			4,030,000	$ 0	$ (140,875,000)
United States Of America [Member]
Income Taxes [Line Items]
Operating loss carry forwards subject to expiration			1,096,200,000
Subsequent Event [Member]
Income Taxes [Line Items]
U.S. federal statutory corporate pretax rate		21.00%
Limitation Of Utilization Of NOL Carryforwards	80.00%
Texas [Member]
Income Taxes [Line Items]
Deferred State and Local Income Tax Expense (Benefit)			$ 3,600,000

Income Taxes (Schedule Of Compo

Income Taxes (Schedule Of Components Of Income Tax (Expense) Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current income tax (expense) benefit
U.S. Federal	$ 0	$ 0	$ 0
State	(395)	0	0
Total current income tax (expense) benefit	(395)	0	0
Deferred income tax (expense) benefit
U.S. Federal	0	0	131,502
State	(3,635)	0	9,373
Total deferred income tax (expense) benefit	(3,635)	0	140,875
Income tax (expense) benefit	$ (4,030)	$ 0	$ 140,875

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income (loss) from continuing operations before income taxes	$ 91,140	$ (675,474)	$ (1,298,760)
Income tax (expense) benefit at the statutory rate	31,899	(236,416)	(454,566)
State income tax (expense) benefit, net of U.S. Federal income taxes	(4,030)	3,894	9,373
Tax shortfalls from stock-based compensation expense	3,089	0	0
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	0	0	1,671
Income tax (expense) benefit from U.S. Federal rate reduction	(211,724)	0	0
Change in valuation allowance from U.S. Federal rate reduction	(211,724)	0	0
Change in valuation allowance from current year activity	35,376	(240,864)	(323,586)
Other	(388)	554	(1,149)
Income tax (expense) benefit	$ (4,030)	$ 0	$ 140,875

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Jan. 01, 2017	Dec. 31, 2016
Deferred income tax assets
Net operating loss carryforward - U.S. Federal and State	$ 242,915		$ 221,063
Oil and gas properties	50,177		309,848
Asset retirement obligations	4,996		7,434
Stock-based compensation	0		5,238
Derivative liabilities	35,585		17,545
Other	1,496		3,739
Deferred income tax assets	335,169		564,867
Deferred tax asset valuation allowance	(333,029)	$ (580,100)	(564,434)
Net deferred income tax assets	2,140		433
Deferred income tax liabilities
Oil and gas properties	(3,635)		0
Derivative assets	(2,140)		(433)
Net deferred income tax asset (liability)	$ (3,635)		$ 0

Debt (Narrative) (Details)

Debt (Narrative) (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)Rate	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Nov. 03, 2017USD ($)	Sep. 30, 2017USD ($)	Jul. 14, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Apr. 28, 2015
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	$ (4,170,000)	$ (4,170,000)	$ 0	$ (38,137,000)
Change of control repurchase price percentage	101.00%	101.00%
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility current borrowing base	$ 900,000,000	$ 900,000,000					$ 837,500,000	$ 900,000,000	$ 600,000,000
Line of Credit Facility, Elected Borrowing Capacity	800,000,000	800,000,000						800,000,000
Restricted Payments Basket					$ 75,000,000	$ 50,000,000
Line of credit facility amount outstanding	$ 291,300,000	$ 291,300,000	87,000,000
Debt, Weighted Average Interest Rate	3.73%	3.73%
Letters of credit outstanding amount	$ 415,000	$ 415,000
Line of credit facility, maximum borrowing capacity								$ 2,000,000,000	$ 1,000,000,000
Ratio of total debt to EBITDA		2.59
Pre-Tax SEC PV10 Reserve Value Percentage | Rate		90.00%
Federal funds rate plus percentage	0.50%	0.50%
Adjusted LIBO rate plus percentage	1.00%	1.00%
Reduction Of Borrowing Capacity Due To Issuance Of Senior Notes							25.00%
Current Ratio	1.98	1.98
Senior Secured Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current Ratio	1	1
Senior Secured Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA		4
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount							$ 250,000,000
Debt instrument interest rate							8.25%
Long-term Debt, Gross	$ 250,000,000	$ 250,000,000	0
Proceeds from Issuance of Debt	$ 245,400,000
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%	7.50%
Long-term Debt, Gross	$ 450,000,000	$ 450,000,000	600,000,000
Debt Instrument, Repurchased Face Amount	$ 150,000,000	150,000,000
Redemption Premium		2,800,000
Debt Instrument, Redemption, Cash Consideration		156,000,000
Accrued interest paid associated with redemption of debt		3,200,000
Gains (Losses) on Extinguishment of Debt		(4,170,000)
Write off of Deferred Debt Issuance Cost		$ 1,300,000
7.50% Senior Notes [Member] | On and after September 15, 2016 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount	100.00%	100.00%
7.50% Senior Notes [Member] | On and after September 15, 2016 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount	101.875%	101.875%
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument interest rate										6.25%
Long-term Debt, Gross	$ 650,000,000	$ 650,000,000	650,000,000
6.25% Senior Notes [Member] | Prior to April 15, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
6.25% Senior Notes [Member] | On and after April 15, 2018 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
6.25% Senior Notes [Member] | On and after April 15, 2018 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	104.688%
Other Long Term Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,425,000	$ 4,425,000	$ 4,425,000
Prior to July 15, 2020 [Member] | 8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount							100.00%
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount							100.00%
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount							106.188%

Debt (Schedule Of Debt) (Detail

Debt (Schedule Of Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 1,629,209	$ 1,325,418
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility amount outstanding	291,300	87,000
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	250,000	0
Unamortized Debt Issuance Expense	4,395	0
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	450,000	600,000
Debt Instrument, Unamortized Premium	579	1,020
Unamortized Debt Issuance Expense	4,492	7,573
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	650,000	650,000
Unamortized Debt Issuance Expense	8,208	9,454
Other Long Term Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,425	$ 4,425

Debt (Interest and Commitment F

Debt (Interest and Commitment Fee Rates) (Details)	12 Months Ended
	Dec. 31, 2017
Less than 25 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.00%
Margin for eurodollar loans	2.00%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Greater than or equal to 25 percent but less than 50 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.25%
Margin for eurodollar loans	2.25%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Greater than or equal to 50 percent but less than 75 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.50%
Margin for eurodollar loans	2.50%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Greater than or equal to 75 percent but less than 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.75%
Margin for eurodollar loans	2.75%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Greater than or equal to 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	2.00%
Margin for eurodollar loans	3.00%
Line of Credit Facility, Commitment Fee Percentage	0.50%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of year asset retirement obligations	$ 21,240	$ 16,511
Liabilities incurred	3,920	2,137
Liabilities settled	(343)	(599)
Reduction due to sales of oil and gas properties	2,671	0
Accretion expense	1,799	1,364
Revisions to estimated cash flows	(306)	(210)
End of year asset retirement obligations	23,792	21,240
Current asset retirement obligations (included in other current liabilities)	(295)	(392)
Non-current asset retirement obligations	23,497	20,848
ExL Acquisition [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred	$ 153
Eagle Ford Shale Transaction [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred		$ 2,037

Commitments and Contingencies57

Commitments and Contingencies (Narrative) (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 28, 2017
Other Commitments [Line Items]
Other Commitment, Due 5 years and thereafter			$ 12,564,000
Rent expense			$ 1,700,000	$ 2,000,000	$ 2,200,000
Subsequent Event [Member] | Drilling Rig Contracts [Member]
Other Commitments [Line Items]
Contractual Obligation, Due in first and second year	$ 22,200,000
Subsequent Event [Member] | Delivery Commitments [Member]
Other Commitments [Line Items]
Other Commitment, Due 5 years and thereafter	$ 111,600,000
Subsequent Event [Member] | Minimum [Member] | Drilling Rig Contracts [Member]
Other Commitments [Line Items]
Commitments, Term in Years	1
Subsequent Event [Member] | Minimum [Member] | Delivery Commitments [Member]
Other Commitments [Line Items]
Commitments, Term in Years	5
Subsequent Event [Member] | Maximum [Member] | Drilling Rig Contracts [Member]
Other Commitments [Line Items]
Commitments, Term in Years	2
Subsequent Event [Member] | Maximum [Member] | Delivery Commitments [Member]
Other Commitments [Line Items]
Commitments, Term in Years	6
ExL Acquisition [Member]
Other Commitments [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High						$ 125,000,000
ExL Acquisition [Member] | Minimum [Member]
Other Commitments [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition		$ 0
ExL Acquisition [Member] | Maximum [Member]
Other Commitments [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition		$ 50,000,000

Commitments and Contingencies58

Commitments and Contingencies (Schedule of Contractual Obligations) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Operating leases
Less than 1 year	$ 5,038
Due in second year	4,895
Due in third year	4,637
Due in fourth year	4,450
Due in fifth year	1,854
More than 5 years	0
Total	20,874
Capital leases
Less than 1 year	1,823
Due in second year	1,800
Due in third year	1,050
Due in fourth year	0
Due in fifth year	0
More than 5 years	0
Total	4,673
Drilling rig contracts
Less than 1 year	23,885
Due in second year	8,881
Due in third year	0
Due in fourth year	0
Due in fifth year	0
More than 5 years	0
Total	32,766
Delivery commitments
Less than 1 year	3,657
Due in second year	3,676
Due in third year	2,757
Due in fourth year	2,438
Due in fifth year	10
More than 5 years	26
Total	12,564
Total
Less than 1 year	34,403
Due in second year	19,252
Due in third year	8,444
Due in fourth year	6,888
Due in fifth year	1,864
More than 5 years	26
Total	$ 70,877

Preferred Stock (Narrative) (De

Preferred Stock (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 24, 2018
Preferred Stock Disclosure [Line Items]
Temporary Equity, Par Value		$ 250,000
Temporary Equity, Shares Issued		250,000	0
Preferred Stock, Dividend Rate, Percentage		8.875%
Preferred Stock, Par or Stated Value Per Share		$ 0.01	$ 0
Issuance of warrants to purchase common stock		2,750,000	0
Class of Warrant or Right Term		10 years
Class of Warrant or Right, Exercise Price of Warrants or Rights		$ 16.08
Cash Purchase Price Per Share of Preferred Stock		$ 970
Payment of Commitment Fees for Preferred Stock		$ (5,000)
Sale of preferred stock, net of offering costs		$ 236,404	$ 0	$ 0
Maximum Preferred Stock Shares Redeemable Within the First Year		50,000
Temporary Equity, Liquidation Preference Per Share		$ 1,000
Preferred Stock, Redemption Premium, Percentage		104.4375%
Preferred Stock, Percent of Ownership to be Able to Vote		50.00%
Preferred Stock, Prohibited Distributions		$ 15,000
Proceeds from Issuance of Preferred Stock and Preference Stock		213,400
Proceeds from Issuance of Warrants		23,003
Dividends on preferred stock		(7,781)	0	0
Accretion on preferred stock		$ (862)	$ 0	$ 0
On or before the seventh anniversary of the Preferred Stock Issuance Date [Domain]
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		12.00%
After August 10, 2024 [Domain]
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		12.00%
Libor Rate to Calculate Preferred Stock Dividend Rate		10.00%
Subsequent Event [Member]
Preferred Stock Disclosure [Line Items]
Temporary Equity, Liquidation Preference Per Share					$ 1,000
Preferred Stock Shares Redeemed					50,000
Payments for Repurchase of Redeemable Preferred Stock	$ 50,500

Preferred Stock (Schedule of Di

Preferred Stock (Schedule of Dividends Paid in Common Stock) (Details)	Dec. 31, 2017Rate
Preferred Stock Dividend Paid in Common Stock First Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	100.00%
Preferred Stock Dividend Paid in Common Stock Second Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	75.00%
Preferred Stock Dividend Paid in Common Stock Third Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	50.00%

Preferred Stock (Schedule of Pr

Preferred Stock (Schedule of Preferred Stock Redemption Premiums) (Details)	12 Months Ended
	Dec. 31, 2017
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	104.4375%
Preferred Stock Redemption Fourth Year [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	104.4375%
Preferred Stock Redemption Fifth Year [Member] [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	102.21875%
Preferred Stock Redemption Sixth Year [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	100.00%

Preferred Stock (Warrants Valua

Preferred Stock (Warrants Valuation Assumptions) (Details)	12 Months Ended
	Dec. 31, 2017$ / shares
Temporary Equity Disclosure [Abstract]
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 16.08
Fair Value Assumptions, Expected Term	10 years
Fair Value Assumptions, Expected Volatility Rate	62.90%
Fair Value Assumptions, Risk Free Interest Rate	2.20%
Fair Value Assumptions, Expected Dividend Rate	0.00%

Preferred Stock (Schedule of 63

Preferred Stock (Schedule of Preferred Stock Activity) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Preferred Stock Activity [Abstract]
Proceeds from Issuance of Preferred Stock and Preference Stock	$ 213,400,000
Accretion on preferred stock	(862,000)	$ 0	$ 0
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	$ 214,262,000	$ 0

Shareholders' Equity And Stoc64

Shareholders' Equity And Stock Incentive Plan (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2017	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 03, 2017	Oct. 28, 2016	Oct. 21, 2015	Mar. 20, 2015	Dec. 31, 2014	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares authorized (in shares)				180,000,000	90,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested				$ 20,300	$ 26,300	$ 32,000
Sale of common stock, net of offering costs, shares		6,300,000	5,200,000	15,600,000	6,000,000
Sale of Stock, Price Per Share							$ 14.28	$ 37.32	$ 37.80	$ 44.75
Sale of common stock, net of offering costs		$ 238,800	$ 231,316	$ 222,378	$ 223,739	$ 470,158
Class of Warrant or Right, Outstanding												118,200
Issuance of warrants to purchase common stock				2,750,000	0
Investment warrants, exercise price						$ 22.09
Conversion of Stock, Shares Issued						71,913
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant				2,675,000
Ratio Of Stock Based Compensation Shares to Common Shares				1.35
Shares Granted, Options					0
Proceeds from stock options exercised				$ 0	$ 0	$ 46
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio Of Stock Based Compensation Shares to Common Shares				1
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost not yet recognized				$ 21,300
Compensation cost not yet recognized, period for recognition				1 year 10 months 24 days
Grants in Period, Performance Shares				1,020,465	887,254	401,421
Grant Date Fair Value, Performance Shares		$ 44.22		$ 28.07	$ 36.93	$ 44.22					$ 34.55
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period				635,965	811,136	671,417
Cash Settled Stock Appreciation Rights Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
SARs, Granted				342,440	376,260	0
Liability for cash stock appreciation rights				$ 4,400	$ 11,500
Liability for cash stock appreciation rights, classified as other accrued liabilities					10,000
Liability for cash stock appreciation rights remainder, classified as other long term liabilities					1,500
Cash paid at exercises, Stock Appreciation Rights				2,100	$ 5,200	$ 1,500
Compensation cost not yet recognized				$ 1,300
Compensation cost not yet recognized, period for recognition				1 year 1 month 5 days
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost not yet recognized				$ 2,100
Compensation cost not yet recognized, period for recognition				1 year 8 months 12 days
Grants in Period, Performance Shares				46,787	41,651	56,517
Grant Date Fair Value, Performance Shares		$ 66.83		$ 47.14	$ 58.44	$ 66.83					$ 68.15
Vesting period, in years				3 years
Performance Shares Vested Per TSR Ranking	92,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	56,342			56,342	0	0
Vesting Percentage Of Target Performance Shares Granted	164.00%
Minimum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period, in years				1 year
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Awards to Vest Based on Market Condition				0.00%
Maximum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period, in years				3 years
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Awards to Vest Based on Market Condition				200.00%
2017 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant				1,750,908

Shareholders' Equity And Stoc65

Shareholders' Equity And Stock Incentive Plan (Summary Of Restricted Stock Award And Unit Activity) (Details) - Restricted Stock Awards And Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Awards and Units
Unvested Shares/Units, Beginning of Period	1,111,710	1,041,997	1,335,682
Granted Shares/Units	1,020,465	887,254	401,421
Vested Shares/Units	(635,965)	(811,136)	(671,417)
Forfeited Shares/Units	(13,555)	(6,405)	(23,689)
Unvested Shares/Units, End of Period	1,482,655	1,111,710	1,041,997
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 36.93	$ 44.22	$ 34.55
Granted, Grant-date Fair Value (USD per share)	25.63	27.80	51.45
Vested, Grant-date Fair Value (USD per share)	39.62	36.32	32.96
Forfeited, Grant-date Fair Value (USD per share)	29.11	34.46	43.36
Grant-date Fair Value, End of Period (USD per share)	$ 28.07	$ 36.93	$ 44.22

Shareholders' Equity And Stoc66

Shareholders' Equity And Stock Incentive Plan (Summary of SARs Activity) (Details) - Cash Settled Stock Appreciation Rights Plan [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
SARs, Outstanding, beginning of period	722,638	700,453	765,198
SARs, Granted	342,440	376,260	0
SARs, Exercised	(219,279)	(354,075)	(64,745)
SARs, Forfeitures	0	0	0
SARs, Expired	131,561
SARs, Outstanding, end of period	714,238	722,638	700,453
SARS, Vested, end of period	185,899	350,840	626,661
SARs, Exercisable, end of period	0	350,840	626,661
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Weighted Average Exercise Price [Roll Forward]
Weighted Average Exercise Prices, Outstanding, Beginning of Period	$ 23.69	$ 21.86	$ 22.49
Weighted Average Exercise Prices, Granted	26.94	27.30	0
Weighted Average Exercise Prices, Exercised	17.28	23.89	29.40
Weighted Average Exercise Prices, Forfeitures	0	0	0
Weighted Average Exercise Prices, Expired (USD per share)	24.19
Weighted Average Exercise Prices, Outstanding, End of Period	27.12	23.69	21.86
Weighted Average Exercise Prices, Vested, End of Period	27.30	19.87	21.05
Weighted Average Exercise Prices, Exercisable, End of Period	$ 27.30	$ 19.87	$ 21.05
Cash paid at exercises, Stock Appreciation Rights	$ 2.1	$ 5.2	$ 1.5
Weighted Average Remaining Life, Outstanding, End of Period	3 years 8 months 12 days
Weighted Average Remaining Life, Exercisable, End of Period	3 years 2 months 12 days
Aggregate Intrinsic Value, Outstanding, End of Period	$ 0
Aggregate Intrinsic Value, Exercisable, End of Period	$ 0

Shareholders' Equity And Stoc67

Shareholders' Equity And Stock Incentive Plan (Summary of Stock Appreciation Rights Fair Value Assumptions) (Details) - Cash Settled Stock Appreciation Rights Plan [Member]	12 Months Ended
	Dec. 31, 2017Rate	Dec. 31, 2016Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility	54.30%	45.10%
Dividend yield	0.00%	0.00%
Risk-free interest rate	1.80%	1.30%
Expected Term	4 years 2 months 26 days	3 years 11 months 5 days

Shareholders' Equity And Stoc68

Shareholders' Equity And Stock Incentive Plan (Summary of Performance Share Award Activity) (Details) - Performance Shares [Member] - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Target Performance Shares (1)
Unvested Shares/Units, Beginning of Period	154,510	154,510	112,859	56,342
Granted Shares/Units		46,787	41,651	56,517
Vested Shares/Units	(56,342)	(56,342)	0	0
Forfeited Shares/Units		0	0	0
Unvested Shares/Units, End of Period		144,955	154,510	112,859
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 58.44	$ 58.44	$ 66.83	$ 68.15
Granted, Grant-date Fair Value (USD per share)		35.14	35.71	65.51
Vested, Grant-date Fair Value (USD per share)		68.15	0	0
Forfeited, Grant-date Fair Value (USD per share)		0	0	0
Grant-date Fair Value, End of Period (USD per share)		$ 47.14	$ 58.44	$ 66.83

Shareholders' Equity And Stoc69

Shareholders' Equity And Stock Incentive Plan (Summary of Performance Share Awards Fair Value Assumptions) (Details) - Performance Shares [Member]	12 Months Ended
	Dec. 31, 2017Rate	Dec. 31, 2016Rate	Dec. 31, 2015Rate
Number of simulations	500,000	500,000	500,000
Expected Term	2 years 11 months 23 days	3 years 3 days	2 years 10 months 21 days
Expected volatility	59.20%	55.30%	45.30%
Risk-free interest rate	1.50%	1.20%	0.90%
Dividend yield	0.00%	0.00%	0.00%

Shareholders' Equity And Stoc70

Shareholders' Equity And Stock Incentive Plan (Stock-Based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	$ 18,791	$ 40,677	$ 19,303
Less: amounts capitalized	(4,482)	(4,591)	(4,574)
Total stock-based compensation expense	14,309	36,086	14,729
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	21,372	28,196	23,668
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	(5,023)	9,675	(6,326)
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	$ 2,442	$ 2,806	$ 1,961

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) $ in Thousands	3 Months Ended
	Dec. 31, 2017USD ($)$ / MMBTU	Sep. 30, 2017$ / bbls	Jun. 30, 2017USD ($)$ / bbls	Nov. 21, 2017USD ($)	Nov. 15, 2017USD ($)	Oct. 05, 2017USD ($)	Aug. 10, 2017USD ($)	Jun. 28, 2017USD ($)	Dec. 31, 2016USD ($)
Derivative [Line Items]
Business Combination, Contingent Consideration, Liability, Noncurrent	$ 85,625
Business Combination, Contingent Consideration, Asset, Noncurrent	10,190								$ 0
ExL Acquisition [Member]
Derivative [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High								$ 125,000
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls			50
Business Combination, Contingent Consideration, Liability, Noncurrent	85,625						$ 52,300
Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	5,000
Business Combination, Contingent Consideration, Asset, Noncurrent	7,985				$ 6,100
Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High						$ 7,500
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	3,000
Business Combination, Contingent Consideration, Asset, Noncurrent	$ 2,205			$ 2,700
Maximum [Member] | ExL Acquisition [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition			$ 50,000
2018 [Member] | Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls		50
2018 [Member] | Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU	3.13
2019 [Member] | Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls		53
2019 [Member] | Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU	3.18
2020 [Member] | Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls		56
2020 [Member] | Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU	3.30

Derivative Instruments (Schedul

Derivative Instruments (Schedule of Crude Oil Derivative Positions) (Details) - Crude Oil [Member]	Dec. 31, 2017bbl / d$ / bbls
Fixed Price Swaps [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	6,000
Weighted Average Fixed Price	(49.55)
Three-way Collars [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	24,000
Derivative Average Sub Floor Price	39.38
Weighted Average Floor Price ($/Bbl)	49.06
Weighted Average Ceiling Price ($/Bbl)	60.14
Three-way Collars [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	12,000
Derivative Average Sub Floor Price	40
Weighted Average Floor Price ($/Bbl)	48.40
Weighted Average Ceiling Price ($/Bbl)	60.29
Sold Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	3,388
Weighted Average Ceiling Price ($/Bbl)	71.33
Sold Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	3,875
Weighted Average Ceiling Price ($/Bbl)	73.66
Sold Call Options [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	4,575
Weighted Average Ceiling Price ($/Bbl)	75.98
LLS-NYMEX Price Differential [Member] | Basis Swap [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	6,000
Weighted Average Fixed Price	(2.91)
Midland-NYMEX Price Differential [Member] | Basis Swap [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	6,000
Weighted Average Fixed Price	(0.10)

Derivative Instruments (Sched73

Derivative Instruments (Schedule of NGL Derivative Positions) (Details) - 2018 [Member] - Natural Gas Liquids [Member] - Swap [Member]	Dec. 31, 2017bbl / d$ / bbls
OPIS Purity Ethane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	2,200
Weighted Average Fixed Price | $ / bbls	12.01
OPIS Propane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	1,500
Weighted Average Fixed Price | $ / bbls	34.23
OPIS Normal Butane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	200
Weighted Average Fixed Price | $ / bbls	38.85
OPIS Isobutane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	600
Weighted Average Fixed Price | $ / bbls	38.98
OPIS Natural Gasoline Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	600
Weighted Average Fixed Price | $ / bbls	55.23

Derivative Instruments (Sched74

Derivative Instruments (Schedule of Natural Gas Derivative Positions) (Details) - Natural Gas [Member] - Call Option [Member]	Dec. 31, 2017MMBTU / d$ / MMBTU
2018 [Member]
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
2019 [Member]
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
2020 [Member]
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.50

Derivative Instruments (Sched75

Derivative Instruments (Schedule of Contingent Consideration) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 21, 2017	Nov. 15, 2017	Aug. 10, 2017
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	$ 10,190	$ 0
Business Combination, Contingent Consideration, Liability, Noncurrent	(85,625)
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	31,940	$ 0	$ 0
ExL Acquisition [Member]
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Liability, Noncurrent	(85,625)					$ (52,300)
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	33,325
Marcellus Shale Divestiture [Member]
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	2,205			$ 2,700
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	455
Utica Shale Divestiture [Member]
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	7,985				$ 6,100
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	$ (1,840)

Derivative Instruments (Sched76

Derivative Instruments (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	$ 10,190	$ 0
Derivative Liability, Current	57,121	22,601
Derivative Liability, Noncurrent	112,332	27,528
Other Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,869	7,990
Derivative Asset, Fair Value, Gross Liability	(4,869)	(6,753)
Derivative Assets (Liabilities), at Fair Value, Net	0	1,237
Derivative Asset, Current	0
Derivative Asset, Deferred Premiums, Gross Asset	0	0
Derivative Asset, Deferred Premiums, Gross Liability	0	0
Derivative Deferred Premium, Net	0	0
Derivative Asset, Gross Asset	4,869	7,990
Derivative Asset, Gross Liability	(4,869)	6,753
Other Noncurrent Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	9,505	3,882
Derivative Asset, Fair Value, Gross Liability	(9,505)	(3,882)
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Derivative Asset	10,190
Derivative Asset, Deferred Premiums, Gross Asset	0	0
Derivative Asset, Deferred Premiums, Gross Liability	0	0
Derivative Deferred Premium, Net	0	0
Business Combination, Contingent Consideration, Asset, Noncurrent	10,190
Derivative Asset, Gross Asset	19,695	3,882
Derivative Asset, Gross Liability	(9,505)	3,882
Other Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(47,802)	(20,593)
Derivative Liability, Fair Value, Gross Liability	(52,671)	(27,346)
Derivative Liability, Fair Value, Gross Asset	4,869	6,753
Derivative Deferred Premium, Net	(9,319)	(2,008)
Derivative Liability, Deferred Premiums, Gross Liability	9,319	2,008
Derivative Liability, Deferred Premiums, Gross Asset	0	0
Derivative Liability, Gross Liability	(61,990)	29,354
Derivative Liability, Gross Asset	4,869	6,753
Derivative Liability, Current	(57,121)
Other Noncurrent Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(15,104)	(24,959)
Derivative Liability, Fair Value, Gross Liability	(24,609)	(28,841)
Derivative Liability, Fair Value, Gross Asset	9,505	3,882
Derivative Deferred Premium, Net	(11,603)	(2,569)
Derivative Liability, Deferred Premiums, Gross Liability	11,603	2,569
Derivative Liability, Deferred Premiums, Gross Asset	0	0
Derivative Liability, Gross Liability	(121,837)	31,410
Derivative Liability, Gross Asset	9,505	3,882
Derivative Liability, Contingent Payment, Gross Liability	(85,625)	0
Derivative Liability, Contingent Payment, Gross Asset	0	0
Derivative Liability, Contingent Payment, Net	(85,625)	0
Derivative Liability, Noncurrent	(112,332)
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	1,237
Derivative Liability	$ 62,906	45,552
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Current		1,237
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Noncurrent		0
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current		(22,601)
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Noncurrent		$ (27,528)

Derivative Instruments (Sched77

Derivative Instruments (Schedule of (Gain) Loss on Derivative Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net	$ 86,107	$ 24,377	$ (26,065)	$ (25,316)	$ 59,103	$ 49,073	$ (99,261)
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net					31,940	0	0
Crude Oil [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					22,839	23,609	(99,624)
Natural Gas Liquids [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					1,322	0	0
Natural Gas [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					(15,399)	19,584	(4,063)
Deferred Premiums On Derivative Instruments [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					$ 18,401	$ 5,880	$ 4,426

Derivative Instruments (Sched78

Derivative Instruments (Schedule of Cash Received for Derivative Settlements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	$ 7,773	$ 119,369	$ 194,296
Natural Gas [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	(54)	0	17,785
Crude Oil [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	9,883	125,098	176,511
Deferred Premiums On Derivative Instruments [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	$ (2,056)	$ (5,729)	$ 0

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount	$ 0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount		$ 0
Fair value amount of transfers in or out of Levels 1 or 2		0
Fair Value, Assets, Level 3 Transfers		$ 0
Fair Value, Equity, Level 1 to Level 2 Transfers, Amount	$ 0

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 0	$ 0
Derivative Liability	0	0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	1,237
Derivative Liability	(62,906)	(45,552)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	10,190	0
Derivative Liability	$ (85,625)	$ 0

Fair Value Measurements (Sche81

Fair Value Measurements (Schedule of Fair Value Assets, Unobservable Inputs Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 10,190	$ 0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances	8,805
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	1,385
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	$ 0

Fair Value Measurements (Sche82

Fair Value Measurements (Schedule of Fair Value Liabilities, Unobservable Inputs Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (85,625)	$ 0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Issuances	(52,300)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	(33,325)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	$ 0

Fair Value Measurements (Sche83

Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	$ 450,000	$ 600,000
8.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	250,000	0
Other Long Term Debt [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	4,425	4,425
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	446,087	593,447
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 6.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	641,792	640,546
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 8.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	245,605	0
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Other Long Term Debt [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	4,425	4,425
Estimate of Fair Value Measurement [Member] | 7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	459,518	624,750
Estimate of Fair Value Measurement [Member] | 6.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	674,375	672,750
Estimate of Fair Value Measurement [Member] | 8.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	274,375	0
Estimate of Fair Value Measurement [Member] | Other Long Term Debt [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	$ 4,445	$ 4,419

Condensed Consolidating Finan84

Condensed Consolidating Financial Information (Narrative) (Details)	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Voting interest of the subsidiary owned by the registrant	100.00%

Condensed Consolidating Finan85

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Total current assets	$ 122,878,000	$ 72,988,000
Total property and equipment, net	2,635,810,000	1,545,760,000
Investment in subsidiaries	0	0
Other assets	19,616,000	7,579,000
Total Assets	2,778,304,000	1,626,327,000
Current Liabilities	372,822,000	211,959,000
Long-term liabilities	1,820,323,000	1,390,910,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262,000	0
Total shareholders’ equity	370,897,000	23,458,000	$ 444,054,000	$ 1,103,441,000
Total Liabilities and Shareholders’ Equity	2,778,304,000	1,626,327,000
Reportable Legal Entities [Member] | Parent Company [Member]
Total current assets	3,441,633,000	2,735,830,000
Total property and equipment, net	5,953,000	42,181,000
Investment in subsidiaries	(999,793,000)	(1,282,292,000)
Other assets	9,270,000	7,423,000
Total Assets	2,457,063,000	1,503,142,000
Current Liabilities	165,701,000	114,805,000
Long-term liabilities	1,689,466,000	1,348,105,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262,000	0
Total shareholders’ equity	387,634,000	40,232,000
Total Liabilities and Shareholders’ Equity	2,457,063,000	1,503,142,000
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Total current assets	105,533,000	63,513,000
Total property and equipment, net	2,630,707,000	1,503,695,000
Investment in subsidiaries	0	0
Other assets	10,346,000	156,000
Total Assets	2,746,586,000	1,567,364,000
Current Liabilities	3,631,401,000	2,822,729,000
Long-term liabilities	114,978,000	26,927,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	0	0
Total shareholders’ equity	(999,793,000)	(1,282,292,000)
Total Liabilities and Shareholders’ Equity	2,746,586,000	1,567,364,000
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Total current assets	0	0
Total property and equipment, net	3,028,000	3,800,000
Investment in subsidiaries	0	0
Other assets	0	0
Total Assets	3,028,000	3,800,000
Current Liabilities	3,028,000	3,800,000
Long-term liabilities	0	0
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	0	0
Total shareholders’ equity	0	0
Total Liabilities and Shareholders’ Equity	3,028,000	3,800,000
Consolidation, Eliminations [Member]
Total current assets	(3,424,288,000)	(2,726,355,000)
Total property and equipment, net	(3,878,000)	(3,916,000)
Investment in subsidiaries	999,793,000	1,282,292,000
Other assets	0	0
Total Assets	(2,428,373,000)	(1,447,979,000)
Current Liabilities	(3,427,308,000)	(2,729,375,000)
Long-term liabilities	15,879,000	15,878,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	0	0
Total shareholders’ equity	983,056,000	1,265,518,000
Total Liabilities and Shareholders’ Equity	$ (2,428,373,000)	$ (1,447,979,000)

Condensed Consolidating Finan86

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total revenues	$ 246,771	$ 181,279	$ 166,483	$ 151,355	$ 143,831	$ 111,177	$ 107,324	$ 81,262	$ 745,888	$ 443,594	$ 429,203
Total costs and expenses									654,748	1,119,068	1,727,963
Income (loss) from continuing operations before income taxes									91,140	(675,474)	(1,298,760)
Operating income (loss)	113,205	69,364	63,147	57,953	55,000	31,634	27,167	(7,491)
Income tax expense									(4,030)	0	140,875
Equity in income of subsidiaries									0	0	0
Income (Loss) From Continuing Operations									87,110	(675,474)	(1,157,885)
Income from discontinued operations, net of income taxes									0	0	2,731
Net income from discontinued operations, net of income taxes									0	0	2,731
Net Income (Loss)	(17,040)	7,823	56,306	40,021	(779)	(101,174)	(262,126)	(311,395)	87,110	(675,474)	(1,155,154)
Dividends on preferred stock	(5,500)	(2,200)							(7,781)	0	0
Accretion on preferred stock									(862)	0	0
Net Income (Loss) Attributable to Common Shareholders	$ (23,434)	$ 5,574	$ 56,306	$ 40,021	$ (779)	$ (101,174)	$ (262,126)	$ (311,395)	78,467	(675,474)	(1,155,154)
Reportable Legal Entities [Member] | Parent Company [Member]
Total revenues									302	482	1,708
Costs and Expenses									195,728	208,054
Total costs and expenses											95,464
Income (loss) from continuing operations before income taxes									(195,426)	(207,572)	(93,756)
Income tax expense									0	0	10,125
Equity in income of subsidiaries									(282,499)	467,410	(1,049,010)
Income (Loss) From Continuing Operations											(1,132,641)
Net income from discontinued operations, net of income taxes									0	0	2,731
Net Income (Loss)									87,073	(674,982)	(1,129,910)
Dividends on preferred stock									7,781	0	0
Accretion on preferred stock									(862)	0	0
Net Income (Loss) Attributable to Common Shareholders									78,430	(674,982)	(1,129,910)
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Total revenues									745,586	443,112	427,495
Costs and Expenses									459,057	910,522
Total costs and expenses											1,603,515
Income (loss) from continuing operations before income taxes									286,529	(467,410)	(1,176,020)
Income tax expense									(4,030)	0	127,010
Equity in income of subsidiaries									0	0	0
Income (Loss) From Continuing Operations											(1,049,010)
Net income from discontinued operations, net of income taxes									0	0	0
Net Income (Loss)									282,499	(467,410)	(1,049,010)
Dividends on preferred stock									0	0	0
Accretion on preferred stock									0	0	0
Net Income (Loss) Attributable to Common Shareholders									282,499	(467,410)	(1,049,010)
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Total revenues									0	0	0
Costs and Expenses									0	0
Total costs and expenses											0
Income (loss) from continuing operations before income taxes									0	0	0
Income tax expense									0	0	0
Equity in income of subsidiaries									0	0	0
Income (Loss) From Continuing Operations											0
Net income from discontinued operations, net of income taxes									0	0	0
Net Income (Loss)									0	0	0
Dividends on preferred stock									0	0	0
Accretion on preferred stock									0	0	0
Net Income (Loss) Attributable to Common Shareholders									0	0	0
Consolidation, Eliminations [Member]
Total revenues									0	0	0
Costs and Expenses									(37)	492
Total costs and expenses											28,984
Income (loss) from continuing operations before income taxes									37	(492)	(28,984)
Income tax expense									0	0	3,740
Equity in income of subsidiaries									282,499	(467,410)	1,049,010
Income (Loss) From Continuing Operations											1,023,766
Net income from discontinued operations, net of income taxes									0	0	0
Net Income (Loss)									(282,462)	466,918	1,023,766
Dividends on preferred stock									0	0	0
Accretion on preferred stock									0	0	0
Net Income (Loss) Attributable to Common Shareholders									$ (282,462)	$ 466,918	$ 1,023,766

Condensed Consolidating Finan87

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Cash Provided by (Used in) Operating Activities	$ 422,981	$ 272,768	$ 377,367
Net cash provided by (used in) operating activities from continuing operations	422,981	272,768	378,735
Net Cash Provided by (Used in) Investing Activities	(1,159,452)	(619,832)	(676,054)
Net cash used in investing activities from continuing operations	(1,159,452)	(619,832)	(673,376)
Net Cash Provided by (Used in) Financing Activities	741,817	308,340	330,767
Net cash provided by financing activities from continuing operations	741,817	308,340	330,767
Net cash used in discontinued operations	0	0	(4,046)
Net increase in cash and cash equivalents	5,346	(38,724)	32,080
Cash and cash equivalents, beginning of year	4,194	42,918	10,838
Cash and cash equivalents, end of year	9,540	4,194	42,918
Cash and cash equivalents	9,540	4,194	42,918	$ 10,838
Reportable Legal Entities [Member] | Parent Company [Member]
Net Cash Provided by (Used in) Operating Activities	(121,107)	(34,773)
Net cash provided by (used in) operating activities from continuing operations			2,655
Net Cash Provided by (Used in) Investing Activities	(615,364)	(312,291)
Net cash used in investing activities from continuing operations			(447,296)
Net Cash Provided by (Used in) Financing Activities	741,817	308,340
Net cash provided by financing activities from continuing operations			480,767
Net cash used in discontinued operations	0	0	(4,046)
Net increase in cash and cash equivalents	5,346	(38,724)	32,080
Cash and cash equivalents, beginning of year	4,194	42,918	10,838
Cash and cash equivalents, end of year	9,540	4,194	42,918
Cash and cash equivalents		4,194	42,918
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	544,088	307,541
Net cash provided by (used in) operating activities from continuing operations			376,080
Net Cash Provided by (Used in) Investing Activities	(1,155,340)	(575,824)
Net cash used in investing activities from continuing operations			(674,758)
Net Cash Provided by (Used in) Financing Activities	611,252	268,283
Net cash provided by financing activities from continuing operations			298,678
Net cash used in discontinued operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	0	0	0
Cash and cash equivalents		0	0
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	0	0
Net cash provided by (used in) operating activities from continuing operations			0
Net Cash Provided by (Used in) Investing Activities	0	(740)
Net cash used in investing activities from continuing operations			0
Net Cash Provided by (Used in) Financing Activities	0	740
Net cash provided by financing activities from continuing operations			0
Net cash used in discontinued operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	0	0	0
Cash and cash equivalents		0	0
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities	0	0
Net cash provided by (used in) operating activities from continuing operations			0
Net Cash Provided by (Used in) Investing Activities	611,252	269,023
Net cash used in investing activities from continuing operations			448,678
Net Cash Provided by (Used in) Financing Activities	(611,252)	(269,023)
Net cash provided by financing activities from continuing operations			(448,678)
Net cash used in discontinued operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	$ 0	0	0
Cash and cash equivalents		$ 0	$ 0

Supplemental Cash Flow Inform88

Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 10, 2017	Dec. 14, 2016
Supplemental Cash Flow Information [Line Items]
Cash paid for interest, net of amounts capitalized	$ 77,213	$ 75,231	$ 64,692
Cash paid for income taxes	0	0	0
Change in capital expenditure payables and accruals	102,272	(21,492)	(86,878)
Contingent Consideration, Liability, Acquisition Date Fair Value	52,300	0	0
Contingent Consideration, Asset, Divestiture Date Fair Value	(8,805)	0	0
Business Combination, Liabilities				$ 58,238	$ 4,897
Share-based Compensation, Capitalized Amount	4,482	4,591	4,574
Asset retirement obligation additions	3,726	1,927	4,853
Sanchez Acquisition [Member]
Supplemental Cash Flow Information [Line Items]
Business Combination, Liabilities	$ 0	$ 4,880	$ 0

Subsequent Events (Unaudited)89

Subsequent Events (Unaudited) (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 20, 2018	Jan. 31, 2018	Jan. 24, 2018	Jul. 14, 2017	Jun. 30, 2017	Mar. 31, 2017
Subsequent Event [Line Items]
Net proceeds from divestitures of oil and gas properties			$ 197,564	$ 15,564	$ 8,047
Temporary Equity, Liquidation Preference Per Share			$ 1,000
Subsequent Event
Subsequent Event [Line Items]
Preferred Stock Shares Redeemed								50,000
Preferred Stock, Percentage Redeemed								20.00%
Payments for Repurchase of Redeemable Preferred Stock	$ 50,500
Temporary Equity, Liquidation Preference Per Share								$ 1,000
Niobrara Divestiture [Member] | Subsequent Event
Subsequent Event [Line Items]
Net proceeds from divestitures of oil and gas properties		$ 136,600
Eagle Ford Shale Divestiture [Member] | Subsequent Event
Subsequent Event [Line Items]
Net proceeds from divestitures of oil and gas properties		$ 246,200
7.50% Senior Notes [Member]
Subsequent Event [Line Items]
Debt instrument interest rate			7.50%
Debt Instrument, Repurchased Face Amount			$ 150,000
Debt Instrument, Redemption, Cash Consideration			156,000
Redemption Premium			2,800
Accrued interest paid associated with redemption of debt			3,200
Senior Secured Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity			900,000						$ 837,500	$ 900,000	$ 600,000
Line of Credit Facility, Elected Borrowing Capacity			$ 800,000							$ 800,000
Senior Secured Revolving Credit Facility [Member] | Subsequent Event
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity							$ 830,000
February 2018 7.50% Senior Note Redemption [Member] | Subsequent Event
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount						$ 100,000
Debt Instrument, Redemption, Cash Consideration	105,100
Redemption Premium	1,900
Accrued interest paid associated with redemption of debt	3,200
March 2018 7.50% Senior Note Redemption [Member] | Subsequent Event
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount						$ 220,000
Debt Instrument, Redemption, Cash Consideration	231,800
Redemption Premium	4,100
Accrued interest paid associated with redemption of debt	$ 7,700

Subsequent Events (Unaudited)90

Subsequent Events (Unaudited) (Schedule of Natural Gas Derivative Instruments) (Details) - Subsequent Event [Member] - Natural Gas [Member] - Fixed Price Swaps [Member] - March - December 2018 [Member]	Jan. 30, 2018MMBTU / d$ / MMBTU
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	25,000
Weighted Average Fixed Price | $ / MMBTU	3.01

Supplemental Disclosures Abou91

Supplemental Disclosures About Oil And Gas Producing Activities (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017$ / bbls$ / MMcf	Dec. 31, 2016$ / bbls$ / MMcf	Dec. 31, 2015$ / bbls$ / MMcf
Crude Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates	49.87	39.60	47.24
Natural Gas Liquids (Bbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates	19.78	11.66	12
Natural Gas (Mcf) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates | $ / MMcf	2.96	1.89	1.87

Supplemental Disclosures Abou92

Supplemental Disclosures About Oil and Gas Producing Activities (Narrative 2) (Details) MBoe in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MBoe	Dec. 31, 2016USD ($)MBoe	Dec. 31, 2015USD ($)MBoe
Supplemental Oil And Gas Reserve Information [Line Items]
Capitalized interest | $	$ 28,300	$ 17,000	$ 32,100
Asset retirement obligation additions | $	3,726	1,927	4,853
Internal costs capitalized, oil and gas producing activities | $	$ 14,800	$ 10,500	$ 15,800
Reserves discount factor	10.00%
Proved Developed Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries, Boe	6,473	6,525	5,237
Purchases of reserves in place, Boe	26,009	4,978
Sale of Mineral in Place, Boe	(22,249)
Proved Undeveloped Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries, Boe	74,281	52,047	32,067
Purchases of reserves in place, Boe	20,094	1,167
Sale of Mineral in Place, Boe	(7,297)
Barrel of Oil Equivalent (Boe) [Domain]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries, Boe	80,754	58,572	37,304
Revisions of previous estimates, Boe	(16,118)	(19,713)	(4,323)
Purchases of reserves in place, Boe	46,103	6,145
Sale of Mineral in Place, Boe	(29,546)
Price Reserve Revisions [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe	2,684	(6,705)	(15,846)
Removed Reserves Of Uneconomic Wells [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe		(3,228)	(6,208)
Revisions Due To Reduced Tail Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe		(3,477)	(9,638)
Performance Reserve Revisions [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe	(4,500)	(6,083)	11,523
Development Plan Revisions [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe	(14,302)	(6,925)
Eagle Ford Shale [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Percentage of reserve additions	51.00%	79.00%	89.00%
Delaware Basin [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Percentage of reserve additions	48.00%	20.00%
Property Acquisition Costs [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Asset retirement obligation additions | $	$ 100	$ 2,037
Exploration and Development Costs [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Asset retirement obligation additions | $	$ 3,527	$ 1,927

Supplemental Disclosures Abou93

Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$ 303,307	$ 90,661	$ 0
Unproved properties	525,061	113,535	63,446
Total property acquisition costs	828,368	204,196	63,446
Exploration costs	91,098	37,508	117,227
Development costs	569,982	374,134	389,396
Total costs incurred	$ 1,489,448	$ 615,838	$ 570,069

Supplemental Disclosures Abou94

Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas Reserves) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MBoeMMcfMBbls	Dec. 31, 2016USD ($)MBoeMMcfMBbls	Dec. 31, 2015USD ($)MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls
Reserve Quantities [Line Items]
Asset retirement obligation additions | $	$ 3,726	$ 1,927	$ 4,853
Crude Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	128,318	109,588	100,704
Extensions and discoveries	50,476	40,074	26,358
Revisions of previous estimates	(19,838)	(16,731)	(9,059)
Purchases of reserves in place	21,634	4,810
Sales of Minerals in Place	(650)
Production	(12,566)	(9,423)	(8,415)
Proved developed and undeveloped reserves end of year	167,374	128,318	109,588
Proved developed reserves (volume)	69,632	51,062	42,311	35,238
Proved undeveloped reserve (volume)	97,742	77,256	67,277	65,466
Natural Gas Liquids (Bbls) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	23,937	20,221	13,513
Extensions and discoveries	13,781	8,612	5,292
Revisions of previous estimates	(909)	(3,230)	2,768
Purchases of reserves in place	8,642	122
Sales of Minerals in Place	(526)
Production	(2,327)	(1,788)	(1,352)
Proved developed and undeveloped reserves end of year	42,598	23,937	20,221
Proved developed reserves (volume)	17,447	9,387	7,933	5,294
Proved undeveloped reserve (volume)	25,151	14,550	12,288	8,219
Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year | MMcf	287,445	244,938	221,017
Extensions and discoveries | MMcf	98,980	59,318	33,925
Revisions of previous estimates | MMcf	27,774	1,481	11,808
Purchases of reserves in place | MMcf	94,962	7,282
Sales of Minerals in Place | MMcf	(170,219)
Production | MMcf	(28,472)	(25,574)	(21,812)
Proved developed and undeveloped reserves end of year | MMcf	310,470	287,445	244,938
Proved developed reserves (volume) | MMcf	131,355	187,054	154,725	149,697
Proved undeveloped reserve (volume) | MMcf	179,115	100,391	90,213	71,320
Barrel of Oil Equivalent (Boe) [Domain]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year, Boe | MBoe	200,163	170,632	151,053
Extensions and discoveries, Boe | MBoe	80,754	58,572	37,304
Revisions of previous estimates, Boe | MBoe	(16,118)	(19,713)	(4,323)
Purchases of reserves in place, Boe | MBoe	46,103	6,145
Sale of Mineral in Place, Boe | MBoe	(29,546)
Production, Boe | MBoe	(19,639)	(15,473)	(13,402)
Proved developed and undeveloped reserves end of year, Boe | MBoe	261,717	200,163	170,632
Proved developed reserves (energy) | MBoe	108,972	91,625	76,032	65,482
Proved undeveloped reserves (energy) | MBoe	152,745	108,538	94,600	85,571
Price Reserve Revisions [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Revisions of previous estimates, Boe | MBoe	2,684	(6,705)	(15,846)
Removed Reserves Of Uneconomic Wells [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Revisions of previous estimates, Boe | MBoe		(3,228)	(6,208)

Supplemental Disclosures Abou95

Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 10,109,752	$ 5,903,629	$ 5,878,348
Future production costs	(3,202,201)	(2,241,928)	(2,124,059)
Future development costs	(1,699,909)	(1,264,493)	(1,178,773)
Future income taxes (1)	(445,056)	0	0
Future net cash flows	4,762,586	2,397,208	2,575,516
Less 10% annual discount to reflect timing of cash flows	(2,297,544)	(1,093,779)	(1,210,292)
Standard measure of discounted future net cash flows	$ 2,465,042	$ 1,303,429	$ 1,365,224	$ 2,555,082

Supplemental Disclosures Abou96

Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure — beginning of period	$ 1,303,429	$ 1,365,224	$ 2,555,082
Net change in sales prices and production costs related to future production	710,773	(346,763)	(2,547,213)
Net change in estimated future development costs	(51,854)	74,407	342,238
Net change due to revisions in quantity estimates	(42,214)	(150,245)	(157,271)
Accretion of discount	130,343	136,522	326,074
Changes in production rates (timing) and other	(116,056)	(111,137)	(139,533)
Total revisions to reserves proved in prior years	630,992	(397,216)	(2,175,705)
Net change due to extensions and discoveries, net of estimated future development and production costs	597,502	313,201	252,155
Net change due to purchases of reserves in place	452,932	43,426	0
Net change due to divestitures of reserves in place	(106,608)	0	0
Sales of crude oil, NGLs and natural gas produced, net of production costs	(566,258)	(320,272)	(312,213)
Previously estimated development costs incurred	326,383	299,066	340,247
Net change in income taxes	(173,330)	0	705,658
Net change in standardized measure of discounted future net cash flows	1,161,613	(61,795)	(1,189,858)
Standardized measure — end of period	$ 2,465,042	$ 1,303,429	$ 1,365,224

Selected Quarterly Financial 97

Selected Quarterly Financial Data (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information [Line Items]
Gain (Loss) On Contingent Consideration	$ (23,900)	$ (8,000)
Dividends on preferred stock	5,500	$ 2,200				$ 7,781	$ 0	$ 0
Loss on extinguishment of debt	4,170					4,170	0	38,137
Impairment of proved oil and gas properties			$ 105,100	$ 197,100	$ 274,400	0	$ 576,540	$ 1,224,367
7.50% Senior Notes [Member]
Quarterly Financial Information [Line Items]
Loss on extinguishment of debt						4,170
Debt Instrument, Repurchased Face Amount	$ 150,000					$ 150,000
Debt instrument interest rate	7.50%					7.50%

Selected Quarterly Financial 98

Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 246,771	$ 181,279	$ 166,483	$ 151,355	$ 143,831	$ 111,177	$ 107,324	$ 81,262	$ 745,888	$ 443,594	$ 429,203
Operating profit (loss)	113,205	69,364	63,147	57,953	55,000	31,634	27,167	(7,491)
(Gain) loss on derivatives, net	86,107	24,377	(26,065)	(25,316)					59,103	49,073	(99,261)
Net income (loss)	(17,040)	7,823	56,306	40,021	(779)	(101,174)	(262,126)	(311,395)	87,110	(675,474)	(1,155,154)
Net Income (Loss) Attributable to Common Shareholders	$ (23,434)	$ 5,574	$ 56,306	$ 40,021	$ (779)	$ (101,174)	$ (262,126)	$ (311,395)	$ 78,467	$ (675,474)	$ (1,155,154)
Net Income (Loss) Attributable to Common Shareholders, Per Basic Share	$ (0.29)	$ 0.07	$ 0.86	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.07	$ (11.27)	$ (22.45)
Net Income (Loss) Attributable to Common Shareholders, Per Diluted Share	$ (0.29)	$ 0.07	$ 0.85	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.06	$ (11.27)	$ (22.45)