Carrizo Oil & Gas (CRZO) 10-K 22 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 19, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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		58,337,680
Entity Public Float			$ 2.4
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 42,918	$ 10,838
Accounts receivable, net	54,721	92,946
Derivative assets	131,100	171,101
Other current assets	3,443	3,736
Total current assets	232,182	278,621
Oil and gas properties, full cost method
Proved properties, net	1,369,151	2,086,727
Unproved properties, not being amortized	335,452	535,197
Other property and equipment, net	12,258	7,329
Total property and equipment, net	1,716,861	2,629,253
Deferred income taxes	46,758	0
Derivative assets	1,115	43,684
Debt issuance costs	24,873	25,403
Other assets	5,116	4,515
Total Assets	2,026,905	2,981,476
Current liabilities
Accounts payable	74,065	106,819
Revenues and royalties payable	67,808	66,954
Accrued capital expenditures	39,225	106,149
Accrued interest	21,981	21,149
Current liabilities of discontinued operations	2,666	4,405
Deferred income taxes	46,758	61,258
Other Liabilities, Current	32,981	57,570
Total current liabilities	285,484	424,304
Long-term debt	1,255,676	1,351,346
Liabilities of discontinued operations	1,088	8,394
Deferred income taxes	0	77,349
Asset retirement obligations	16,183	12,187
Derivative liabilities	12,648	17
Other liabilities	11,772	4,438
Liabilities	$ 1,582,851	$ 1,878,035
Commitments and contingencies
Shareholders’ equity
Common stock, $0.01 par value, 90,000,000 shares authorized; 58,332,993 issued and outstanding as of December 31, 2015 and 46,127,924 issued and outstanding as of December 31, 2014	$ 583	$ 461
Additional paid-in capital	1,411,081	915,436
Retained earnings (Accumulated deficit)	(967,610)	187,544
Total shareholders’ equity	444,054	1,103,441
Total Liabilities and Shareholders’ Equity	$ 2,026,905	$ 2,981,476

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	90,000,000	90,000,000
Common stock, shares issued (in shares)	58,332,993	46,127,924
Common stock, shares outstanding (in shares)	58,332,993	46,127,294

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Oil and Condensate Revenue	$ 376,094	$ 610,483	$ 421,311
Natural Gas Liquids Revenue	15,608	25,050	15,530
Natural Gas Production Revenue	37,501	74,654	83,341
Total revenues	429,203	710,187	520,182
Costs and Expenses
Lease operating	90,052	74,157	46,828
Production taxes	17,683	29,544	19,811
Ad valorem taxes	9,255	8,450	8,701
Depreciation, depletion and amortization	300,035	317,383	214,291
General and administrative	67,224	77,029	77,492
(Gain) loss on derivatives, net	(99,261)	(201,907)	18,417
Interest expense, net	69,195	53,171	54,689
Impairment of oil and gas properties	1,224,367	0	0
Loss on extinguishment of debt	38,137	0	0
Loss on sale of oil and gas properties	0	0	45,377
Other (income) expense, net	11,276	2,150	(185)
Total costs and expenses	1,727,963	359,977	485,421
OTHER INCOME AND EXPENSES
Income (Loss) From Continuing Operations Before Income Taxes	(1,298,760)	350,210	34,761
Income tax (expense) benefit	140,875	(127,927)	(12,903)
Income (Loss) From Continuing Operations	(1,157,885)	222,283	21,858
Income From Discontinued Operations, Net of Income Taxes	2,731	4,060	21,825
Net Income (Loss)	$ (1,155,154)	$ 226,343	$ 43,683
Net Income (Loss) Per Common Share - Basic
Income (Loss) from Continuing Operations (in dollars per share)	$ (22.50)	$ 4.90	$ 0.54
Net income from discontinued operations (in dollars per share)	0.05	0.09	0.53
Net income (loss) per share basic (in dollars per share)	(22.45)	4.99	1.07
Net Income (Loss) Per Common Share - Diluted
Net income (loss) from continuing operations, diluted (in dollars per share)	(22.50)	4.81	0.53
Net income from discontinued operations (in dollars per share)	0.05	0.09	0.53
Net income per share, diluted (in dollars per share)	$ (22.45)	$ 4.90	$ 1.06
Weighted Average Common Shares Outstanding
Basic (in shares)	51,457	45,372	40,781
Diluted (in shares)	51,457	46,194	41,355

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]
BALANCE at Dec. 31, 2012	$ 585,016	$ 402	$ 667,096	$ (82,482)
BALANCE, shares at Dec. 31, 2012		40,164,517
Stock options exercised for cash	$ 1,253	$ 2	1,251
Stock options exercised for cash, shares	206,501	206,501
Stock-based compensation	$ 19,531		19,531
Restricted stock issuances and vestings, net of forfeitures	(533)	$ 6	(539)
Common stock activity, net of forfeitures, shares		552,831
Common stock offerings, net of offering costs	189,686	$ 45	189,641
Common stock offerings, net of offering costs, shares		4,500,000
Other	2,968	$ 0	2,968
Other, shares		44,826
Net income (loss)	43,683			43,683
BALANCE at Dec. 31, 2013	841,604	$ 455	879,948	(38,799)
BALANCE, shares at Dec. 31, 2013		45,468,675
Stock options exercised for cash	$ 437	$ 1	436
Stock options exercised for cash, shares	33,086	33,086
Stock-based compensation	$ 30,280		30,280
Restricted stock issuances and vestings, net of forfeitures	(91)	$ 5	(96)
Common stock activity, net of forfeitures, shares		625,301
Other	4,868	$ 0	4,868
Other, shares		862
Net income (loss)	226,343			226,343
BALANCE at Dec. 31, 2014	$ 1,103,441	$ 461	915,436	187,544
BALANCE, shares at Dec. 31, 2014		46,127,924
Class of Warrant or Right, Outstanding	118,200
Stock options exercised for cash	$ 46	$ 0	46
Stock options exercised for cash, shares	2,433	2,433
Stock-based compensation	$ 25,707		25,707
Restricted stock issuances and vestings, net of forfeitures	(144)	$ 6	(150)
Common stock activity, net of forfeitures, shares		630,723
Common stock offerings, net of offering costs	470,158	$ 115	470,043
Common stock offerings, net of offering costs, shares		11,500,000
Other	0	$ 1	(1)
Other, shares		71,913
Net income (loss)	(1,155,154)			(1,155,154)
BALANCE at Dec. 31, 2015	$ 444,054	$ 583	$ 1,411,081	$ (967,610)
BALANCE, shares at Dec. 31, 2015		58,332,993

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows From Operating Activities
Net income (loss)	$ (1,155,154)	$ 226,343	$ 43,683
(Income) loss from discontinued operations, net of income taxes	(2,731)	(4,060)	(21,825)
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities from continuing operations
Depreciation, depletion and amortization	300,035	317,383	214,291
Impairment of oil and gas properties	1,224,367	0	0
(Gain) loss on derivatives, net	(99,261)	(201,907)	18,417
Cash received (paid) for derivative settlements, net	194,296	(13,529)	12,491
Loss on extinguishment of debt	38,137	0	0
Loss on sale of oil and gas properties	0	0	45,377
Stock-based compensation, net	14,729	25,878	29,373
Deferred income taxes	(140,875)	127,927	10,934
Non-cash interest expense, net	4,289	4,272	3,932
Other, net	5,709	2,379	3,704
Changes in operating assets and liabilities-
Accounts receivable	29,781	(1,334)	11,557
Accounts payable	(12,617)	27,238	13,595
Accrued liabilities	(17,517)	(3,096)	(12,588)
Other, net	(4,453)	(5,219)	(5,467)
Net cash provided by operating activities from continuing operations	378,735	502,275	367,474
Net cash used in operating activities from discontinued operations	(1,368)	(656)	(623)
Net cash provided by operating activities	377,367	501,619	366,851
Cash Flows From Investing Activities
Capital expenditures - oil and gas properties	(674,612)	(860,604)	(786,976)
Capital expenditures - other property and equipment	(1,340)	(750)	(968)
Payments to Acquire Oil and Gas Property	(1,817)	(92,961)	0
Proceeds from sales of oil and gas properties, net	8,047	12,576	238,470
Other, net	(3,654)	1,063	39,589
Net cash used in investing activities from continuing operations	(673,376)	(940,676)	(509,885)
Net cash provided by (used in) investing activities from discontinued operations	(2,678)	(7,834)	124,533
Net cash used in investing activities	(676,054)	(948,510)	(385,352)
Cash Flows From Financing Activities
Issuance of senior notes	650,000	301,500	0
Tender and redemption of senior notes	(626,681)	0	(69,325)
Payment of deferred purchase payment	(150,000)	0	0
Borrowings under credit agreement	1,126,860	986,041	582,000
Repayments of borrowings under credit agreement	(1,126,860)	(986,041)	(582,000)
Payments of debt issuance costs	(12,420)	(6,510)	(3,257)
Sale of common stock, net of offering costs	470,158	0	189,686
Excess tax benefits from stock-based compensation	0	4,863	1,969
Proceeds from stock options exercised	46	437	1,253
Other, net	(336)	0	0
Net cash provided by financing activities from continuing operations	330,767	300,290	120,326
Net cash provided by financing activities from discontinued operations	0	0	3,000
Net cash provided by financing activities	330,767	300,290	123,326
Net Increase (Decrease) in Cash and Cash Equivalents	32,080	(146,601)	104,825
Cash and Cash Equivalents, Beginning of Year	10,838	157,439	52,614
Cash and Cash Equivalents, End of Year	$ 42,918	$ 10,838	$ 157,439

Nature Of Operations

Nature Of Operations	12 Months Ended
	Dec. 31, 2015
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 oil and gas primarily 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, the Delaware Basin in West Texas, the Utica Shale in Ohio, the Niobrara Formation in Colorado and the Marcellus Shale in Pennsylvania.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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. Discontinued Operations On February 22, 2013, the Company closed on the sale of Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all of its interest in the Huntington Field discovery, including a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) for an agreed-upon price of $184.0 million , including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding under Carrizo UK’s senior secured multicurrency credit facility as of the closing date. The liabilities, results of operations and cash flows associated with Carrizo UK have been classified as discontinued operations in the consolidated financial statements. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to discontinued operations is included in “Note 3. Discontinued Operations”, “Note 15. Condensed Consolidating Financial Information” and “Note 18. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited).” 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 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, drilling requirements and royalty obligations. 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, stock-based compensation, collectability of receivables, and in evaluating disputed claims, interpreting contractual arrangements (including royalty obligations and notional interest calculations) 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, counterparty creditworthiness, 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 Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the consolidated balance sheets and totaled $49.1 million and $70.5 million as of December 31, 2015 and 2014 , respectively. Accounts Receivable 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, 2015 and 2014 , the Company’s allowance for doubtful accounts was $1.0 million and zero , 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 customers 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 does not require collateral from its customers and joint interest owners. The Company generally has the right to withhold future revenue distributions to recover any non-payment of joint interest billings. The Company’s derivative instruments in a net asset position also subject the Company to a concentration of credit risk. See “Note 13. Derivative Instruments.” Major Customers Shell Trading (US) Company accounted for approximately 65% , 44% , and 47% of the Company’s oil and gas revenues in 2015 , 2014 , and 2013 , respectively. Flint Hills Resources, LP accounted for approximately 26% and 23% of the Company’s oil and gas revenues in 2014 and 2013 , 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 and totaled $15.8 million , $18.8 million and $15.0 million for the years ended December 31, 2015, 2014 and 2013 , 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 capitalized 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 $22.05 , $26.20 and $21.38 for the years ended December 31, 2015, 2014 and 2013 , respectively. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost of exploratory wells in progress, and related capitalized interest. Exploratory wells in progress and 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 added to the oil and gas property costs subject to amortization. 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 and completion capital expenditure plans. The Company expects to complete its evaluation of the majority of its unevaluated leaseholds within the next five years and exploratory wells in progress within the next year. Geological and geophysical costs not associated with specific prospects are recorded to oil and gas property costs subject to amortization immediately. The Company capitalized interest costs associated with its unproved properties totaling $32.1 million , $34.5 million and $29.9 million for the years ended December 31, 2015, 2014 and 2013 , respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties using a weighted average interest rate based on outstanding borrowings. Capitalized costs, less accumulated amortization and 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. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prices are held constant indefinitely and are not changed 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 because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. During 2015, the Company recorded after-tax impairments in the carrying value of proved oil and gas properties of $795.8 million ( $1,224.4 million pre-tax) due primarily to declines in the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period. There were no impairments of proved oil and gas properties for the years ending December 31, 2014 and 2013. See “Note 5. Property and Equipment, Net” for further details of the impairment. Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of capitalized 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 2015 and 2014 the Company did not have any sales of oil and gas properties that significantly altered such relationship. On February 22, 2013, the Company closed the sale of Carrizo UK, which included all of the Company’s proved reserves in its U.K. cost center. As a result, in the first quarter of 2013, the Company recognized a $37.3 million pre-tax gain in “Net income from discontinued operations, net of income taxes” in the consolidated statements of operations. Further, on October 31, 2013, the Company closed the sale of its remaining oil and gas properties in the Barnett. The proved reserves attributable to the Barnett sale represented 40% of the Company’s proved reserves as of October 31, 2013, which significantly altered the relationship between capitalized costs and proved reserves of oil and gas attributable to the Company’s U.S. cost center. As a result, the Company recognized a pre-tax loss on the sale of $45.4 million in “Loss on sale of oil and gas properties” in the consolidated statements of operations in the fourth quarter of 2013. 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. Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities 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 derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The carrying amounts of long-term debt under the Company’s revolving credit facility approximate fair value as borrowings bear interest at variable rates of interest. 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 any unamortized premium or discount and the notes bear interest at fixed rates of interest. See “Note 7. Long-Term Debt” and “Note 14. 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 when the production equipment and facilities are installed with an associated increase in 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. 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 8. 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 9. Commitments and Contingencies.” Revenue Recognition Oil and 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 an asset or 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, 2015 and 2014 , 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 substantial, but varying, portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. All derivative instruments are recorded on the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its 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 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 derivative instruments, including volumes, types of instruments and counterparties. These policies require that 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 13. Derivative Instruments” for further discussion of the Company’s derivative instruments. 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. 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. Stock Appreciation Rights. For SARs, stock-based compensation expense is based on the fair value liability (using the Black-Scholes-Merton option pricing model) remeasured at each reporting period, recognized over the vesting period (generally three years) using the graded vesting method. Each award includes a performance condition that must be met in order for that award to vest. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. 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 prepared by an independent third party) and recognized over the vesting period (generally three years) using the straight-line method. Each award includes a performance condition that must be met in order for that award to vest. 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 an industry peer group generally over a 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. See “Note 10. Shareholders’ Equity and Stock Incentive Plans.” Assumptions. The Black-Scholes-Merton option pricing model and the Monte Carlo valuation model require the Company to make the following assumptions: • The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant. • The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future. • The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date. For the Monte Carlo valuation model, daily, historical volatility for the industry peer group for the same time period as the Company is also used. • For the Black-Scholes-Merton option pricing model, the expected term is based on historical exercises for various groups of employees and independent contractors, while the Monte Carlo valuation model uses an expected term based on the performance period for the award. 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 routinely assesses the realizability of its deferred tax assets by taxing jurisdiction and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the benefit from deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance. As of December 31, 2015 , the Company recorded a valuation allowance against the net deferred tax asset of $324.7 million , reducing the net deferred tax asset to zero . See “Note 6. Income Taxes” for further discussion of the 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. Recent Accounting Pronouncements In November, 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes. Update 2015 (“Update 2015-17”). Updated 2015-17 eliminates the current requirement to present deferred tax assets and liabilities as current and noncurrent on the consolidated balance sheets. Instead all deferred tax assets and liabilities will be presented as noncurrent. For public entities, Update 2015-17 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 31, 2016 and may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented with early adoption permitted. The adoption of Update 2015-17 is not expected to have a significant impact on the Company's consolidated financial statements, other than balance sheet reclassifications. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“Update 2015-03”). The objective of Update 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. Under Update 2015-15, debt issuance costs associated with line-of-credit agreements may be deferred and presented as an asset in the balance sheet, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. For public entities, Update 2015-03 and Update 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and applied retrospectively with early adoption permitted. The adoption of Update 2015-03 and Update 2015-15 will not have an impact on the Company’s consolidated financial statements, other than balance sheet reclassifications. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry specific guidance in Subtopic 932-605, Extractive Activities- Oil and Gas- Revenue Recognition. Update 2014-09 requires entities to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. In April 2015, the FASB proposed to delay the effective date one year. This proposal was approved in July 2015 and as such, Update 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period for public entities. The Company is currently evaluating the impact of the adoption of Update 2014-09 on its consolidated financial statements.

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	3. Discontinued Operations On February 22, 2013 , the Company closed on the sale of Carrizo UK, and all of its interest in the Huntington Field discovery, including a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy for an agreed-upon price of $184.0 million , including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding under Carrizo UK’s senior secured multicurrency credit facility as of the closing date. The liabilities, results of operations and cash flows associated with Carrizo UK have been classified as discontinued operations in the consolidated financial statements. The liabilities of discontinued operations of $3.8 million and $12.8 million as of December 31, 2015 and 2014 , respectively, relate to an accrual for estimated future obligations related to the sale. See “Note 2. Summary of Significant Accounting Policies—Use of Estimates” for further discussion of estimates and assumptions that may affect the reported amounts of liabilities related to the sale of Carrizo UK. The following table summarizes the amounts included in income from discontinued operations, net of income taxes presented in the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (In thousands) Revenues $— $— $— Costs and expenses General and administrative 1,426 656 916 Accretion related to asset retirement obligations — — 36 Gain on sale of discontinued operations — — (37,294 ) Increase (decrease) in estimated future obligations (6,424 ) (7,638 ) 44 Loss on derivatives, net — 34 109 Other income, net — — (438 ) Income From Discontinued Operations Before Income Taxes 4,998 6,948 36,627 Income tax expense (2,267 ) (2,888 ) (14,802 ) Income From Discontinued Operations, Net of Income Taxes $2,731 $4,060 $21,825 Carrizo UK is a disregarded entity for U.S. federal income tax purposes. Accordingly, the income tax expense reflected above includes the Company’s U.S. deferred income tax expense associated with the income from discontinued operations before income taxes. The related U.S. deferred tax liabilities have been classified as deferred income taxes of continuing operations in the consolidated balance sheets.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Acquisitions and Divestitures [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	4. Acquisition and Divestiture 2014 Acquisition On October 24, 2014, the Company completed the acquisition of interests in oil and gas properties (the “Properties”) from Eagle Ford Minerals, LLC (“EFM”) primarily in LaSalle, Atascosa and McMullen counties, Texas in the Eagle Ford (the “Eagle Ford Shale Acquisition”). The Eagle Ford Shale Acquisition had an effective date of October 1, 2014, with an agreed upon purchase price of $250.0 million , of which the Company paid a total of $241.8 million , net of post-closing and working capital adjustments, which consisted of approximately $93.0 million at closing and $148.8 million on February 13, 2015. Prior to the Eagle Ford Shale Acquisition, the Company and EFM were joint working interest owners in the Properties, for which the Company acted as the operator and owned an approximate 75% working interest in all of such Properties. After giving effect to the Eagle Ford Shale Acquisition, the Company holds an approximate 100% working interest in the Properties. The deferred purchase payment was discounted by $2.6 million to an acquisition date fair value of $147.4 million . For the further discussion of the accounting for the deferred purchase payment, see “Note 7. Long-Term Debt.” The Eagle Ford Shale Acquisition was accounted for under the acquisition method of accounting whereby the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values. Purchase price adjustments of $3.2 million relate to the revenues, operating expenses and capital expenditures for the period from the October 1, 2014 effective date to the October 24, 2014 closing date. The following presents the purchase price and the allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date: October 24, 2014 (In thousands) Assets Other current assets $485 Proved and unproved oil and gas properties 244,124 Total assets acquired $244,609 Liabilities Asset retirement obligations $423 Total liabilities assumed $423 Net Assets Acquired $244,186 Included in the consolidated statements of operations for the year ended December 31, 2014 are revenues of $13.1 million and income from continuing operations of $11.0 million from the Properties, representing activity 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, 2014, and December 31, 2013, assuming the Eagle Ford Shale Acquisition had been completed as of January 1, 2013, including adjustments to reflect the 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 Eagle Ford Shale Acquisition. Years Ended December 31, 2014 2013 (In thousands, except per share data) (Unaudited) Total revenues $761,199 $575,721 Income From Continuing Operations $264,714 $36,356 Income From Continuing Operations Per Common Share Basic $5.83 $0.89 Diluted $5.73 $0.88 Weighted Average Common Shares Outstanding Basic 45,372 40,781 Diluted 46,194 41,355 2013 Divestiture During the fourth quarter of 2013, the Company sold its remaining oil and gas properties in the Barnett to EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P., and EV Properties, L.P., (collectively, “EnerVest”). Net proceeds received from the sale were approximately $191.8 million , which represents an agreed upon purchase price of approximately $218.0 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received by the Company for sales of hydrocarbons from such properties between the effective date of July 1, 2013 and the closing date of October 31, 2013. The proved reserves attributable to the properties sold to EnerVest represented 40% of the Company’s proved reserves as of October 31, 2013 and the sale resulted in a significant alteration of the relationship between capitalized costs and proved reserves attributable to the Company’s U.S. cost center. As a result, the Company recognized a pre-tax loss on the sale of $45.4 million as a component of operating income in the fourth quarter of 2013 rather than recognizing the proceeds as a reduction of proved oil and gas properties.

Property And Equipment, Net

Property And Equipment, Net	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property And Equipment, Net	5. Property and Equipment, Net As of December 31, 2015 and 2014 , total property and equipment, net consisted of the following: December 31, 2015 2014 (In thousands) Proved properties $3,976,511 $3,174,268 Accumulated depreciation, depletion and amortization and impairment (2,607,360 ) (1,087,541 ) Proved properties, net 1,369,151 2,086,727 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 280,263 401,954 Exploratory wells in progress 9,432 71,402 Capitalized interest 45,757 61,841 Total unproved properties, not being amortized 335,452 535,197 Other property and equipment 22,677 16,017 Accumulated depreciation (10,419 ) (8,688 ) Other property and equipment, net 12,258 7,329 Total property and equipment, net $1,716,861 $2,629,253 Costs not subject to amortization totaling $335.5 million at December 31, 2015 were incurred in the following periods: $33.6 million in 2015 , $258.4 million in 2014 and $43.5 million in 2013 . Full Cost Ceiling Test Impairments In the third and fourth quarter of 2015, the Company recorded after-tax impairments in the carrying value of proved oil and gas properties of $795.8 million ( $1,224.4 million pre-tax) due primarily to declines in the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period prior to December 31, 2015. There were no impairments of proved oil and gas properties for the years ending December 31, 2014 and 2013. The Company expects to record an impairment in the carrying value of proved oil and gas properties in the first quarter of 2016 due to the continued decrease in crude oil prices. The Company estimates the oil price to be used in the calculation of the full cost ceiling test to be $45.85 based on the first calendar day of each month oil prices available for the 11 months ended February 1, 2016 and using a NYMEX strip price for the twelfth month. This is a 9% decrease from the oil price used in the calculation of the full cost ceiling test for the year ended December 31, 2015 of $50.28 /Bbl. Further impairments in subsequent quarters may occur if the trailing 12-month commodity prices continue to be lower than the comparable trailing 12-month commodity prices discussed above.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	6. Income Taxes The components of income tax expense (benefit) from continuing operations were as follows: Years Ended December 31, 2015 2014 2013 (In thousands) Current income tax (expense) benefit U.S. Federal $— $— $411 State — — (141 ) Total current income tax benefit — — 270 Deferred income tax (expense) benefit U.S. Federal 131,502 (122,342 ) (12,404 ) State 9,373 (5,585 ) (769 ) Total deferred income tax (expense) benefit 140,875 (127,927 ) (13,173 ) Total income tax (expense) benefit from continuing operations $140,875 ($127,927 ) ($12,903 ) 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, 2015 2014 2013 (In thousands) Income (loss) from continuing operations before income taxes ($1,298,760 ) $350,210 $34,761 Income tax (expense) benefit at the statutory rate 454,566 (122,574 ) (12,166 ) State income tax (expense) benefit, net of U.S. Federal income taxes and increase in valuation allowance 9,373 (5,585 ) (859 ) Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense 1,671 — — Deferred tax asset valuation allowance (323,586 ) — — Other (1,149 ) 232 122 Total income tax (expense) benefit from continuing operations $140,875 ($127,927 ) ($12,903 ) 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, 2015 and 2014 , deferred tax assets and liabilities are comprised of the following: December 31, 2015 2014 (In thousands) Deferred income tax assets Net operating loss carryforward - U.S. Federal and State $119,783 $56,876 Oil and gas properties 232,786 — Asset retirement obligations 5,779 4,379 Stock-based compensation 4,741 7,867 Fair value of derivative instruments 4,433 70 Other 3,435 2,989 Deferred income tax assets 370,957 72,181 Deferred tax asset valuation allowance (324,681 ) (1,095 ) Net deferred income tax assets 46,276 71,086 Deferred income tax liabilities Oil and gas properties — (134,518 ) Fair value of derivative instruments (46,276 ) (75,175 ) (46,276 ) (209,693 ) Net deferred income tax liability $— ($138,607 ) Deferred income tax assets and liabilities are classified as current or noncurrent based on the classification of the related asset or liability in the consolidated balance sheet except for deferred tax assets related to net operating loss carryforwards which is classified as current or noncurrent based on the periods the carryforwards are expected to be utilized. By taxing jurisdiction, all current deferred tax assets and liabilities are offset and presented as a net current deferred tax asset or liability and all noncurrent deferred tax assets and liabilities are offset and presented as a net noncurrent deferred tax asset or liability. At December 31, 2015 and 2014 , the net deferred income tax asset (liability) is classified as follows: December 31, 2015 2014 (In thousands) Net current deferred income tax liability ($46,758 ) ($61,258 ) Net noncurrent deferred income tax asset (liability) 46,758 (77,349 ) Net deferred income tax liability $— ($138,607 ) Deferred tax asset valuation allowance. 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 each period 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. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. 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, 2015, driven primarily by the full cost ceiling impairments recognized during the third quarter and fourth quarter of 2015, which limits the ability to consider other subjective evidence such as the Company’s anticipated future growth. The Company concluded in the third quarter 2015 it was more likely than not that the deferred tax assets would not be realized and recorded a valuation allowance totaling $187.6 million against the net deferred tax asset of as of September 30, 2015. The valuation allowance was further increased to $324.7 million against the net deferred tax assets as of December 31, 2015 reducing the net deferred tax assets to zero . 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 determine 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 that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if the Company recognizes taxable income. As long as the Company concludes that the valuation allowance against its net deferred tax assets is necessary, the Company likely will not have any additional deferred income tax expense or benefit. Net Operating Loss Carryforwards and Other Net Operating Loss Carryforwards. As of December 31, 2015 , the Company had U.S. federal net operating loss carryforwards of approximately $366.8 million . If not utilized in earlier periods, the U.S. federal net operating loss will expire between 2026 and 2035 . 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 (a) the fair market value of the equity of the Company multiplied by (b) 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. As of December 31, 2015, the Company believes an ownership change occurred in February 2005, which imposed an annual limitation of $12.6 million of the Company’s taxable income that can be offset by the pre-change carryforwards. Because the Company’s aggregate pre-change carryforward is $9.8 million , the Company does not believe it has a Section 382 limitation on the ability to utilize its U.S. loss carryforwards as of December 31, 2015. 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. The Company receives a tax deduction during the period stock options and SARs are exercised, generally for the excess of the exercise date stock price over the exercise price of the option or SAR. The Company also receives a tax deduction during the period restricted stock awards and units vest, generally equal to the fair value of the awards or units on the vesting date. Because these stock-based compensation tax deductions did not reduce current taxes payable as a result of U.S. loss carryforwards, the benefit of these tax deductions has not been reflected in the U.S. loss carryforward deferred tax asset. Stock-based compensation tax deductions included in the U.S. loss carryforwards of $366.8 million but not reflected in the associated deferred tax asset were $44.7 million as of December 31, 2015 . The Company expects to recognize the $15.7 million deferred tax asset associated with these stock-based compensation tax deductions under the tax law ordering approach which looks to the provision within the tax law for determining the sequence in which the U.S. loss carryforwards and other tax attributes are utilized. When the stock-based compensation tax deduction related U.S. loss carryforward deferred tax asset is realized, the tax benefit of reducing current taxes payable will be credited directly to additional paid-in capital. Other. The Company files income tax returns in the U.S. Federal jurisdiction, in various states and previously filed in one foreign jurisdiction, each with varying statutes of limitations. The 1999 through 2015 tax years generally remain subject to examination by federal and state tax authorities. The foreign jurisdiction generally remains subject to examination by the relevant taxing authority for the 2014 and 2015 tax years through 2016 and 2017, respectively. The Company received notice in January 2015 from the Large Business and International Division of the Internal Revenue Service (the “Service”) that the Company’s 2012 Federal Tax Return was selected for examination. The examination commenced in February 2015, and the Service concluded the examination of the Company's 2012 Federal Tax Return records in November 2015. The exam concluded with no material adjustments made to the Company's 2012 Federal Tax Return and no open items pending further action between the Company and the Service. As of December 31, 2015 , 2014 and 2013, the Company had no material uncertain tax positions.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	7. Long-Term Debt Long-term debt consisted of the following as of December 31, 2015 and 2014 : December 31, 2015 2014 (In thousands) Deferred purchase payment $— $150,000 Unamortized discount for deferred purchase payment — (1,100 ) Senior Secured Revolving Credit Facility due 2018 — — 8.625% Senior Notes due 2018 — 600,000 Unamortized discount for 8.625% Senior Notes — (3,444 ) 7.50% Senior Notes due 2020 600,000 600,000 Unamortized premium for 7.50% Senior Notes 1,251 1,465 6.25% Senior Notes due 2023 650,000 — Other long-term debt due 2028 4,425 4,425 Long-term debt $1,255,676 $1,351,346 Deferred Purchase Payment On October 24, 2014, the Company closed the Eagle Ford Shale Acquisition for an agreed upon purchase price of $250.0 million , net of post-closing and working capital adjustments. The deferred purchase payment of $150.0 million , net of post-closing and working capital adjustments was made in February 2015. The Company had the intent and ability to refinance this deferred purchase payment on a long-term basis with available capacity under its revolving credit facility, and accordingly, the deferred purchase payment was classified as long-term debt as of December 31, 2014. See “Note 4. Acquisition and Divestiture” for further discussion. Senior Secured Revolving Credit Facility The Company has a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2015 , had a borrowing base of $685.0 million , with no borrowings outstanding. As of December 31, 2015 , the Company also had $0.6 million in letters of credit outstanding, which would reduce the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest-only payments until July 2, 2018, 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, in each case which 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 governing the revolving credit facility. Based on currently available bank pricing assumptions and current pricing differentials, drilling and completion plans, and reserve and cost assumptions, the Spring 2016 redetermination is expected to result in a reduction of the borrowing base. On May 5, 2015, the Company entered into the sixth amendment to the senior secured revolving credit agreement to, among other things, (i) establish an approved borrowing base of $685.0 million until the next redetermination thereof, (ii) establish a swing line commitment under the revolving credit facility not to exceed $15.0 million and (iii) include seven additional banks to its banking syndicate, bringing the total number of banks to 19 as of the date of such amendment. On October 30, 2015, the Company entered into the seventh amendment to the senior secured revolving credit agreement to, among other things, (i) reaffirm the borrowing base at its current level of $685.0 million until the next redetermination thereof and (ii) amend the financial covenant requiring the maintenance of a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00, such that the permissible ratio is increased to 4.75 to 1.00 through December 31, 2016, reducing to 4.375 to 1.00 through December 31, 2017, and returning to 4.00 to 1.00 thereafter. 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 80% of the proved reserve value of the oil and gas properties included in the determination of the borrowing base. Amounts 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 as set forth in the table below on the unused portion of lender commitments, and which are included as a component of interest expense. 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% 0.50% 1.50% 0.375% Greater than or equal to 25% but less than 50% 0.75% 1.75% 0.375% Greater than or equal to 50% but less than 75% 1.00% 2.00% 0.500% Greater than or equal to 75% but less than 90% 1.25% 2.25% 0.500% Greater than or equal to 90% 1.50% 2.50% 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 (as defined in the credit agreement) of not more than 4.75 to 1.00 through December 31, 2016, reducing to 4.375 to 1.00 through December 31, 2017, and to 4.00 to 1.00 thereafter; and (2) a Current Ratio (as defined in the credit agreement) of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt discounts and premiums and is net of cash and cash equivalents, EBITDA is for the last four quarters 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, 2015 , the ratio of Total Debt to EBITDA was 2.67 to 1.00 and the Current Ratio was 3.63 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 amounts outstanding under the credit agreement are dependent on the timing of cash flows from operations, capital expenditures, acquisitions and dispositions 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, mergers, asset dispositions, 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). 8.625% Senior Notes due 2018 On November 2, 2010, the Company issued $400.0 million aggregate principal amount of 8.625% Senior Notes due 2018 in a private placement. On November 17, 2011, the Company issued an additional $200.0 million aggregate principal amount of 8.625% Senior Notes in a private placement. These notes were issued as “additional notes” under the indenture governing the 8.625% Senior Notes pursuant to which the Company had previously issued $400.0 million aggregate principal amount of 8.625% Senior Notes in November 2010, and under the indenture are treated as a single series with substantially identical terms as the 8.625% Senior Notes previously issued in November 2010. In June 2011 and February 2012, the Company completed the exchange of registered 8.625% Senior Notes for any and all of its then unregistered $400.0 million and $200.0 million aggregate principal amount of 8.625% Senior Notes, respectively. On April 14, 2015, the Company settled a cash tender offer for any or all of the outstanding $600.0 million aggregate principal amount of its 8.625% Senior Notes. The tender offer expired on April 23, 2015. On April 28, 2015, the Company made an aggregate cash payment of $276.4 million for the $264.2 million aggregate principal amount of 8.625% Senior Notes validly tendered in the tender offer. This represented a tender offer premium totaling $12.2 million , equal to $1,046.13 for each $1,000 principal amount of 8.625% Senior Notes validly tendered and accepted for payment pursuant to the tender offer. In addition, all 8.625% Senior Notes accepted for payment received accrued and unpaid interest of $0.8 million from the last interest payment date up to, but not including, the settlement date. In connection with the cash tender offer, the Company also sent a notice of redemption to the trustee for its 8.625% Senior Notes to conditionally call for redemption on May 14, 2015 all of the 8.625% Senior Notes then outstanding, conditioned upon and subject to the Company receiving specified net proceeds from one or more securities offerings, which conditions were satisfied. On May 14, 2015, the Company paid an aggregate redemption price of $352.6 million , including a redemption premium of $14.5 million , which represented 104.313% of the principal amount of the then outstanding 8.625% Senior Notes (or $1,043.13 for each $1,000 principal amount of the 8.625% Senior Notes) plus accrued and unpaid interest of $2.3 million from the last interest payment date up to, but not including, the redemption date, to redeem the then outstanding $335.8 million aggregate principal amount of 8.625% Senior Notes. As a result of the cash tender offer and the redemption of the 8.625% Senior Notes, the Company recorded a loss on extinguishment of debt of $38.1 million during the second quarter of 2015, which includes the premium paid to repurchase the 8.625% Senior Notes of $26.7 million and non-cash charges of $11.4 million attributable to the write-off of unamortized debt issuance costs and the remaining discount associated with the 8.625% Senior Notes. 7.50% Senior Notes due 2020 On September 10, 2012, the Company issued in a public offering $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020. On October 30, 2014, the Company issued in a private placement an additional $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020 at a price to the initial purchasers of 100.5% of par. In February 2015, the Company completed an exchange offer registered under the Securities Act of 1933, as amended, whereby registered 7.50% Senior Notes were exchanged for such privately placed 7.50% Senior Notes. The privately placed 7.50% Senior Notes have substantially identical terms, other than with respect to certain transfer restrictions and registration rights, as the exchanged 7.50% Senior Notes and our 7.50% Senior Notes that were issued on September 10, 2012. The Company may redeem all or a portion of the 7.50% Senior Notes at any time on or after September 15, 2016 at redemption prices decreasing from 103.75% to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest. Prior to September 15, 2016, the Company may redeem all or part of the 7.50% Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium (as defined in the indenture governing the original 7.50% Senior Notes). If a Change of Control (as defined in the indenture governing the original 7.50% Senior Notes) occurs, the Company may be required by holders to repurchase the 7.50% Senior Notes for cash at a price equal to 101% of the principal amount, plus any accrued and unpaid interest. 6.25% Senior Notes due 2023 On April 28, 2015, the Company closed a public offering of $650.0 million aggregate principal amount of 6.25% Senior Notes due 2023. The Company received proceeds of approximately $640.3 million , net of underwriting discounts and commissions. The net proceeds were used to fund the repurchase and redemption of the 8.625% Senior Notes described above as well as to temporarily repay borrowings outstanding under the Company’s revolving credit facility. The 6.25% Senior Notes bear interest at 6.25% per annum which is payable semi-annually on each April 15 and October 15 and mature on April 15, 2023. Before April 15, 2018, the Company may, at its option, redeem all or a portion of the 6.25% Senior Notes at 100% of the principal amount plus 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, 2018, plus accrued and unpaid interest. The 6.25% Senior Notes were guaranteed by the same subsidiaries that also guarantee the 7.50% Senior Notes and the revolving credit facility. The indentures governing 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, 2015 , the 7.50% Senior Notes and the 6.25% Senior Notes were guaranteed by all of the Company’s existing Material Domestic Subsidiaries (as defined in the credit agreement governing the revolving credit facility).

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	8. Asset Retirement Obligations The following table sets forth asset retirement obligations for the years ended December 31, 2015 and 2014 : Years Ended December 31, 2015 2014 (In thousands) Asset retirement obligations at beginning of period $12,512 $7,356 Liabilities incurred 3,227 6,284 Increase due to acquisition of oil and gas properties — 423 Liabilities settled (1,966 ) (1,784 ) Accretion expense 1,112 710 Revisions of previous estimates (1) 1,626 (477 ) Asset retirement obligations at end of period 16,511 12,512 Current portion of asset retirement obligations included in “Other current liabilities” (328 ) (325 ) Long-term asset retirement obligations $16,183 $12,187 (1) Revisions of previous estimates during the year ended December 31, 2015 are primarily attributable to increased estimates of future costs for oilfield services required to plug and abandon certain wells located in the Gulf Coast region.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	9. 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 increases, 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, 2015 , 2014 and 2013 was $2.2 million , $1.9 million , and $1.9 million , respectively, and includes rent expense primarily for the Company’s corporate office and field offices. At December 31, 2015 , total minimum commitments from long-term, non-cancelable operating and capital leases, drilling rigs and pipeline volume commitments are as shown in the table below. The total minimum commitments related to the drilling rigs 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. 2016 2017 2018 2019 2020 2021 and Thereafter Total (In thousands) Operating leases $4,055 $4,185 $4,248 $4,357 $4,450 $6,304 $27,599 Capital leases 1,733 1,733 1,700 1,677 978 — 7,821 Drilling rig contracts 24,261 20,513 3,957 — — — 48,731 Pipeline volume commitments 8,596 7,474 7,474 6,141 3,651 5,431 38,767 Total $38,645 $33,905 $17,379 $12,175 $9,079 $11,735 $122,918

Shareholders' Equity And Stock

Shareholders' Equity And Stock Incentive Plan	12 Months Ended
	Dec. 31, 2015
Shareholders' Equity And Stock Incentive Plan [Abstract]
Shareholders' Equity And Stock Incentive Plan	10. Shareholders’ Equity and Stock Incentive Plans Common Stock Offerings On March 20, 2015, the Company completed a public offering of 5.2 million shares of its common stock at a price of $44.75 per share, for proceeds of $231.3 million , net of offering costs. The Company used the net proceeds from the common stock offering to repay a portion of the borrowings under the Company’s revolving credit facility and for general corporate purposes. On October 21, 2015, the Company completed a public offering of 6.3 million shares of its common stock at a price of $37.80 per share, for proceeds of $238.8 million , net of offering costs. The Company used the net proceeds from the common stock offering to repay borrowings under the Company’s revolving credit facility and for general corporate purposes. Exercise of Warrants On November 24, 2009, the Company entered into an agreement with an unrelated third party and its affiliate under which the Company issued 118,200 warrants to purchase shares of the Company’s common stock. In May 2015, the holders of the warrants exercised all warrants outstanding on a “cashless” basis at an exercise price of $22.09 resulting in the issuance of 71,913 shares of the Company’s common stock. Stock-Based Compensation Plans The Company has established the Incentive Plan of Carrizo Oil & Gas, Inc., as amended (the “Incentive Plan”), which authorizes the granting of stock options, SARs that may be settled in cash or common stock at the option of the Company, restricted stock awards, restricted stock units and performance share awards to employees and independent contractors. The Incentive Plan also authorizes the granting of stock options, restricted stock awards and restricted stock units to directors. On May 15, 2014, the Incentive Plan was amended and restated, to increase the number of shares available for issuance under the Incentive Plan. The Company may grant awards covering up to 10,822,500 shares (subject to certain limitations) under the Incentive Plan, and at December 31, 2015 , there were 3,861,389 common shares remaining available for grant under the Incentive Plan. The Company has also established the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The Cash SAR Plan authorizes the granting of SARs to employees and independent contractors that may only be settled in cash. Restricted Stock Awards and Units. The Company grants restricted stock awards and units to employees, independent contractors and directors. Restricted stock awards are treated as issued and outstanding as of the grant date because the shares of common stock are issued in the name of employees, but held by the Company until the restrictions are satisfied. Although the shares of common stock are not issued to employees until vesting, during the restriction period, the terms of the award agreement provide employees and their permitted transferees the right to vote on their unvested shares. Restricted stock units do not have the right to vote on unvested shares and are not considered issued and outstanding until the shares of common stock are issued to the employee upon vesting. Restricted stock units are payable, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock on the vesting date. Most restricted stock awards and units contain a service condition, and certain restricted stock units also contain performance conditions. All performance conditions have been met for all awards outstanding at December 31, 2015 . The table below summarizes restricted stock award and unit activity for the years ended December 31, 2015 , 2014 and 2013 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2013 Unvested restricted stock awards and units, beginning of period 1,146,274 $26.95 Granted 932,763 $28.16 Vested (557,136 ) $25.98 Forfeited (77,034 ) $26.03 Unvested restricted stock awards and units, end of period 1,444,867 $28.03 For the Year Ended December 31, 2014 Unvested restricted stock awards and units, beginning of period 1,444,867 $28.03 Granted 576,812 $48.64 Vested (647,306 ) $32.64 Forfeited (38,691 ) $32.89 Unvested restricted stock awards and units, end of period 1,335,682 $34.55 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 The aggregate fair value of restricted stock awards and units that vested during the years ended December 31, 2015 , 2014 and 2013 was $32.0 million , $37.3 million and $16.0 million , respectively. As of December 31, 2015 , unrecognized compensation costs related to unvested restricted stock awards and units was $20.8 million and will be recognized over a weighted average period of 1.7 years. Stock Appreciation Rights. Employees and independent contractors have been or may by granted SARs under the Incentive Plan or Cash SAR Plan, representing the right to receive shares of common stock or cash, at the option of the Company, based on the appreciation in the stock price from the grant date price of the SAR. All SARs contain service and performance conditions. The performance conditions have been met for all SARs outstanding at December 31, 2015 . The table below summarizes the activity for SARs for the years ended December 31, 2015 , 2014 and 2013 : 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, 2013 Outstanding, beginning of period 1,035,823 $22.69 Granted 282,296 $28.68 Exercised (207,184 ) $19.30 $3.9 Forfeited (24,704 ) $27.77 Outstanding, end of period 1,086,231 $24.78 Exercisable, end of period 681,867 $22.55 For the Year Ended December 31, 2014 Outstanding, beginning of period 1,086,231 $24.78 Granted — — Exercised (321,033 ) $30.24 $7.8 Forfeited — — Outstanding, end of period 765,198 $22.49 Exercisable, end of period 587,481 $20.78 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 1.1 $5.1 Exercisable, end of period 626,661 $21.05 1.1 $5.0 As of December 31, 2015 , the liability for SARs was $7.0 million , which is classified as “Other current liabilities”, on the consolidated balance sheets. As of December 31, 2014 , the liability for SARs outstanding was $14.8 million , of which $13.9 million was classified as “Other current liabilities” with the remaining $0.9 million classified as “Other liabilities”. As of December 31, 2015 , unrecognized compensation costs related to unvested SARs was $0.1 million and will be recognized over a weighted average period of 0.4 years. The Company used the Black-Scholes-Merton option pricing model to compute the grant date fair value of SARs. The following table summarizes the assumptions used to calculate the fair value of SARs granted during 2013 : Year Ended December 31, 2013 Stock price on the date of grant $13.36 Volatility factor 44.5 % Dividend yield — % Risk-free interest rate 1.0 % Expected term (in years) 3.5 Performance Share Awards. The Company grants performance share awards to employees and independent contractors, where each performance share represents the value of one share of common stock. Performance share awards are payable, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock on the vesting date. The number of performance shares that will vest is subject to a market condition, which is based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a defined peer group over the three year performance period. The range of performance shares which may be earned by an award recipient ranges from zero and 200% of the performance shares granted depending on the Company’s TSR as compared to the peer group at the end of the performance period, which is also the vesting date. The performance share awards also contain service and performance conditions. The performance conditions have been met for all performance share awards outstanding at December 31, 2015 . The table below summarizes performance share award activity for the years ended December 31, 2015 and 2014 : Performance Share Awards Weighted Average Grant Date Fair Value For the Year Ended December 31, 2014 Unvested performance share awards, beginning of period — — Granted 56,342 $68.15 Vested — — Forfeited — — Unvested performance share awards, end of period 56,342 $68.15 For the Year Ended December 31, 2015 Unvested performance share awards, beginning of period 56,342 $68.15 Granted 56,517 $65.51 Vested — — Forfeited — — Unvested performance share awards, end of period 112,859 $66.83 As of December 31, 2015 , unrecognized compensation costs related to unvested performance share awards was $4.2 million and will be recognized over a weighted average period of 1.9 years. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled, even if the Company’s TSR relative to the TSR achieved by the defined peer group over the performance period results in the vesting of zero performance share awards. The grant date fair value of the performance share awards is determined using the Monte Carlo simulation. The Monte Carlo simulation is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The following table summarizes the assumptions used to calculate the fair value of the performance share awards granted in 2015 and 2014 : Years Ended December 31, 2015 2014 Number of simulations 500,000 500,000 Stock price on the date of grant $53.58 $53.96 Volatility factor 45.3 % 49.9 % Dividend yield — % — % Risk-free interest rate 0.9 % 0.9 % Expected term (in years) 2.89 2.97 Stock Options. The Company may grant stock options to employees, independent contractors and directors. Stock options can be settled, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock at on the exercise date. The price at which shares of common stock may be purchased due to the exercise of stock options must not be less than the fair market value of the common stock on the date of grant. The table below summarizes the activity for stock options for the years ended December 31, 2015 , 2014 and 2013 : Stock Options Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Cash Received from Exercises (In millions) Tax Benefit Realized from Exercises (In millions) For the Year Ended December 31, 2013 Outstanding, beginning of period 242,854 $7.24 Granted — — Exercised (206,501 ) $6.07 $4.4 $1.3 $1.5 Forfeited — — Outstanding, end of period 36,353 $13.91 1.1 $1.1 Exercisable, end of period 36,353 $13.91 1.1 $1.1 For the Year Ended December 31, 2014 Outstanding, beginning of period 36,353 $13.91 Granted — — Exercised (33,086 ) $13.20 $1.3 $0.4 $0.4 Forfeited — — Expired (834 ) $27.25 Outstanding, end of period 2,433 $19.02 0.5 $0.1 Exercisable, end of period 2,433 $19.02 0.5 $0.1 For the Year Ended December 31, 2015 Outstanding, beginning of period 2,433 $19.02 Granted — — Exercised (2,433 ) $19.02 $0.1 $— $0.1 Forfeited — — Outstanding, end of period — — 0 — Exercisable, end of period — — 0 — As of December 31, 2015 , all stock options were vested and exercised and accordingly, the Company had no unrecognized compensation costs related to stock options. Stock-Based Compensation Expense The Company recognized the following stock-based compensation expense associated with restricted stock awards and units, SARs, and performance share awards for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations: Years Ended December 31, 2015 2014 2013 (In thousands) Restricted stock awards and units $23,668 $29,597 $18,997 Stock appreciation rights (6,326 ) 1,985 17,303 Performance share awards 1,961 1,395 — 19,303 32,977 36,300 Less: amounts capitalized (4,574 ) (7,099 ) (6,927 ) Total stock-based compensation expense $14,729 $25,878 $29,373 Income tax benefit $5,155 $9,059 $10,281

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share [Text Block]	11. Earnings Per Share Basic income (loss) from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted income (loss) from continuing operations 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 excludes the number of awards, units, options and warrants from the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are greater than the average market prices of the Company’s common stock for the year as the effect would be anti-dilutive to the computation. 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 year was the end of the performance period. When a loss from continuing operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. Supplemental income (loss) from continuing operations per common share information is provided below: Years Ended December 31, 2015 2014 2013 (In thousands, except per share amounts) Income (Loss) From Continuing Operations ($1,157,885 ) $222,283 $21,858 Basic weighted average common shares outstanding 51,457 45,372 40,781 Effect of dilutive instruments: Restricted stock awards and units — 684 492 Performance share awards — 56 — Stock options — 13 47 Warrants — 69 35 Diluted weighted average common shares outstanding 51,457 46,194 41,355 Income (Loss) From Continuing Operations Per Common Share Basic ($22.50 ) $4.90 $0.54 Diluted ($22.50 ) $4.81 $0.53 For the year ended December 31, 2015, the Company reported a loss from continuing operations. As a result, the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 0.6 million shares of restricted stock awards and units and performance share awards and an insignificant number of shares of stock options and warrants. For the years ended December 31, 2014 and 2013, the number of shares of restricted stock awards and units, performance share awards, options and warrants excluded due to anti-dilutive effects were insignificant.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	12. Related Party Transactions Avista Joint Ventures . Effective August 2008, the Company’s wholly owned subsidiary Carrizo (Marcellus) LLC entered into a joint venture arrangement with ACP II Marcellus LLC (“ACP II”), an affiliate of Avista Capital Partners, LP, a private equity fund. Effective September 2011, the Company’s wholly-owned subsidiary, Carrizo (Utica) LLC, entered into a joint venture in the Utica with ACP II and ACP III Utica LLC (“ACP III”), an affiliate of ACP II and Avista Capital Partners, LP. (collectively with ACP II and ACP III, “Avista”). During the term of the Avista joint ventures, the joint venture partners acquired and sold acreage and the Company exercised options under the applicable Avista joint venture agreements to acquire acreage from Avista. The Avista Utica joint venture agreements were terminated on October 31, 2013 in connection with the Company’s purchase of certain ACP III assets. After giving effect to such transaction, the Company and Avista remain working interest partners in Utica with the Company acting as the operator of the jointly owned properties which are now subject to standard joint operating agreements. The joint operating agreements with Avista provide for limited areas of mutual interest around properties jointly owned by the Company and Avista. Carrizo Relationship with Avista. Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which entity has the ability to control Avista and its affiliates. As previously disclosed, the Company has been and is a party to prior arrangements with affiliates of Avista Capital Holdings, LP. The terms of the joint ventures with Avista in the Utica and the Marcellus and a related prior acquisition transaction were each separately approved by a special committee of the Company’s independent directors. In determining whether to approve or disapprove a transaction, such special committee has determined whether the transaction is desirable and in the best interest of the Company and has evaluated such transaction is fair to the Company and its shareholders on the same basis as comparable arm’s length transactions. The committee has applied, and may in other transactions also apply, standards under relevant debt agreements if required. Amounts due from Avista and Affiliates . As of December 31, 2015 and 2014 , related party receivable on the consolidated balance sheets included $2.4 million and $1.9 million , respectively, representing the net amounts ACP II and ACP III owes the Company related to activity within the Avista Marcellus and Avista Utica joint ventures.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	13. Derivative Instruments The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a substantial, but varying, portion of its forecasted oil and gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. As of December 31, 2015, the Company’s commodity derivative instruments consisted of fixed price swaps, costless 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. Costless Collars: A collar is a combination of options including a purchased put option (fixed floor price) and a sold call option (fixed ceiling price) and allows the Company to benefit from increases in commodity prices up to the fixed ceiling price and protect the Company from decreases in commodity prices below the fixed floor price. At settlement, if the market price is below the fixed floor price or is above the fixed ceiling price, the Company receives the fixed price and pays the market price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. These contracts were executed contemporaneously with the same counterparties and were premium neutral such that no premiums were paid to or received from the counterparties. 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. 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. The following sets forth a summary of the Company’s open crude oil derivative positions at average NYMEX prices as of December 31, 2015 . Period Type of Contract Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) FY 2016 Fixed Price Swaps 9,315 $60.03 FY 2016 Costless Collars 5,490 $50.96 $74.73 FY 2018 Sold Call Options 2,488 $60.00 FY 2018 Sold Call Options 900 $75.00 FY 2019 Sold Call Options 2,975 $62.50 FY 2019 Sold Call Options 900 $77.50 FY 2020 Sold Call Options 3,675 $65.00 FY 2020 Sold Call Options 900 $80.00 On February 11, 2015, the Company entered into derivative transactions offsetting its then existing crude oil derivative positions covering the periods from March 2015 through December 2016. As a result of the offsetting derivative transactions, the Company locked in $166.4 million of cash flows, of which $118.9 million was received due to contract settlements during the year ended December 31, 2015, and is included in the gain on derivatives, net in the consolidated statements of operations. As of December 31, 2015, the fair value of the remaining locked in cash flows is $47.5 million , of which $44.8 million is a current asset and is classified as "Derivative assets" in the consolidated balance sheets. The derivative assets associated with the offsetting derivative transactions are not subject to price risk and the locked in cash flows will be received as the applicable contracts settle. Included in the $99.3 million gain on derivatives, net for the year ended December 31, 2015, is an $8.4 million gain representing the increase in fair value of the then-existing crude oil derivative positions from December 31, 2014 to February 11, 2015. The offsetting derivative transactions are not included in the table above. Additionally, subsequent to entering into the offsetting derivative transactions described above, the Company entered into costless collars for the periods from March 2015 through December 2016 that will continue to provide the Company with downside protection at crude oil prices below the weighted average floor prices yet allow the Company to benefit from an increase in crude oil prices up to the weighted average ceiling prices. During the third and fourth quarter of 2015, the Company sold out-of-the-money call options for the years 2017 through 2020 at ceiling prices of $60.00 per Bbl, $60.00 per Bbl, $62.50 per Bbl, and $65.00 per Bbl, respectively, and used the premium value associated with the sale of those out-of-the-money call options to obtain a higher weighted average fixed price of $60.03 per Bbl on newly executed fixed price swaps for the year 2016. These out-of-the-money call options and in-the-money fixed price swaps were executed contemporaneously with the same counterparties, therefore, no cash premiums were paid to or received from the counterparties as the premium value associated with the call options was immediately applied to the fixed price swaps for the year 2016. During the fourth quarter of 2015, crude oil prices continued on a downward trend which decreased the value of call option contracts. In December 2015, the Company used this opportunity to purchase all of its previously existing 2017 sold call options. The Company also raised the ceiling on portions of its sold call options in 2018, 2019, and 2020 by buying back 900 Bbls/d of its then existing sold call options described above and simultaneously selling 900 Bbls/d of out-of-the-money call options for the years 2018 through 2020 at ceiling prices of $75.00 per Bbl, $77.50 per Bbl, and $80.00 per Bbl, respectively. The crude oil derivative positions table above shows the net effect of the purchased and sold out-of-the-money call options for each of the years 2017 through 2020. As a result of the purchased and sold out-of-the-money call options executed in December 2015, the Company incurred net premiums of approximately $5.0 million , the payment of which is deferred until settlement. See “Note 17. Subsequent Events” for details of transactions entered into subsequent to December 31, 2015. For the years ended December 31, 2015 , 2014 and 2013 , the Company recorded in the consolidated statements of operations a gain on derivatives, net of $99.3 million , $201.9 million , and a loss on derivatives, net of $18.4 million , respectively. The Company typically has numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. The Company includes any deferred premiums associated with its hedge positions in the fair value amounts. The Company nets its 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. The fair value of derivative instruments where the Company is in a net asset position with its counterparties as of December 31, 2015 and 2014 totaled $119.6 million and $214.8 million , respectively, and is summarized by counterparty in the table below: Counterparty December 31, 2015 December 31, 2014 Societe Generale 37 % 26 % Wells Fargo 35 % 37 % Citibank 13 % — % Regions 9 % 8 % Union Bank 5 % 4 % Capital One 1 % — % Credit Suisse — % 24 % Royal Bank of Canada — % 1 % Total 100 % 100 % The counterparties to the Company’s derivative instruments are also lenders under the Company’s credit agreement, which allows the Company to satisfy any need for margin obligations resulting from adverse changes in the fair value of its derivative instruments with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Because each of the counterparties have investment grade credit ratings, 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. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. Although the Company does not currently anticipate such nonperformance, it continues to monitor the credit ratings of its counterparties.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	14. 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 location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of December 31, 2015 and 2014 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: December 31, 2015 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $159,447 ($28,347 ) $131,100 Derivative assets-non current 10,780 (9,665 ) 1,115 Derivative liabilities Other current liabilities (28,364 ) 28,347 (17 ) Derivative liabilities-non current (22,313 ) 9,665 (12,648 ) Total $119,550 $— $119,550 December 31, 2014 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $183,625 ($12,524 ) $171,101 Derivative assets-non current 44,725 (1,041 ) 43,684 Derivative liabilities Other current liabilities (12,707 ) 12,524 (183 ) Derivative liabilities-non current (1,058 ) 1,041 (17 ) Total $214,585 $— $214,585 The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for crude oil and natural gas, discount rates and volatility factors. 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. To date, adjustments for credit quality have not had a material impact on the fair values. The derivative asset and liability fair values reported in the consolidated balance sheets that pertain to the Company’s derivative instruments, as well as the Company’s crude oil derivative instruments that were entered into subsequent to the offsetting derivative transactions, are as of a particular point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. However, the fair value of the net derivative asset attributable to the offsetting crude oil derivative transactions are not subject to price risk as changes in the fair value of the original positions are offset by changes in the fair value of the offsetting positions. The Company includes any deferred premiums associated with its hedge positions in the fair value amounts. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments 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. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the years ended December 31, 2015 and 2014 . 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 classified as Level 1 under the fair value hierarchy with the exception of the deferred purchase payment, which is classified as Level 2 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 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 long-term debt with the fair values of the Company’s senior notes and other long-term debt based on quoted market prices and the fair value of the deferred purchase payment based on indirect observable market rates. December 31, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) Deferred purchase payment due 2015 $— $— $148,900 $148,558 8.625% Senior Notes due 2018 — — 596,555 597,000 7.50% Senior Notes due 2020 601,251 528,000 601,466 573,000 6.25% Senior Notes due 2023 650,000 533,000 — — Other long-term debt due 2028 4,425 4,182 4,425 4,071

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2015
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	15. 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. Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A. CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,578,034 $52,067 $— ($2,397,919 ) $232,182 Total property and equipment, net 44,499 1,671,774 3,059 (2,471 ) 1,716,861 Investment in subsidiaries (815,836 ) — — 815,836 — Other assets 94,338 156 — (16,632 ) 77,862 Total Assets $1,901,035 $1,723,997 $3,059 ($1,601,186 ) $2,026,905 Liabilities and Shareholders’ Equity Current liabilities $161,792 $2,521,572 $3,059 ($2,400,939 ) $285,484 Long-term liabilities 1,279,859 18,261 — (753 ) 1,297,367 Total shareholders’ equity 459,384 (815,836 ) — 800,506 444,054 Total Liabilities and Shareholders’ Equity $1,901,035 $1,723,997 $3,059 ($1,601,186 ) $2,026,905 December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,380,445 $245,051 $111 ($2,346,986 ) $278,621 Total property and equipment, net 613 2,562,029 39,939 26,672 2,629,253 Investment in subsidiaries 233,173 — — (233,173 ) — Other assets 140,774 — — (67,172 ) 73,602 Total Assets $2,755,005 $2,807,080 $40,050 ($2,620,659 ) $2,981,476 Liabilities and Shareholders’ Equity Current liabilities $296,686 $2,434,649 $39,955 ($2,346,986 ) $424,304 Long-term liabilities 1,364,793 139,353 — (50,415 ) 1,453,731 Total shareholders’ equity 1,093,526 233,078 95 (223,258 ) 1,103,441 Total Liabilities and Shareholders’ Equity $2,755,005 $2,807,080 $40,050 ($2,620,659 ) $2,981,476 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) 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 ) Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $3,938 $706,121 $128 $— $710,187 Total costs and expenses (76,531 ) 442,343 30 (5,865 ) 359,977 Income from continuing operations before income taxes 80,469 263,778 98 5,865 350,210 Income tax expense (28,164 ) (92,322 ) — (7,441 ) (127,927 ) Equity in income of subsidiaries 171,554 — — (171,554 ) — Income from continuing operations $223,859 $171,456 $98 ($173,130 ) $222,283 Income from discontinued operations, net of income taxes 4,060 — — — 4,060 Net income $227,919 $171,456 $98 ($173,130 ) $226,343 Year Ended December 31, 2013 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $6,490 $513,692 $— $— $520,182 Total costs and expenses 134,874 349,782 3 762 485,421 Income (loss) from continuing operations before income taxes (128,384 ) 163,910 (3 ) (762 ) 34,761 Income tax (expense) benefit 44,934 (57,369 ) — (468 ) (12,903 ) Equity in income of subsidiaries 106,538 — — (106,538 ) — Income (loss) from continuing operations $23,088 $106,541 ($3 ) ($107,768 ) $21,858 Income from discontinued operations, net of income taxes 21,825 — — — 21,825 Net income (loss) $44,913 $106,541 ($3 ) ($107,768 ) $43,683 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) 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 Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($132,683 ) $634,970 ($12 ) $— $502,275 Net cash used in investing activities from continuing operations (305,718 ) (906,509 ) (37,609 ) 309,160 (940,676 ) Net cash provided by financing activities from continuing operations 300,290 271,539 37,621 (309,160 ) 300,290 Net cash used in discontinued operations (8,490 ) — — — (8,490 ) Net decrease in cash and cash equivalents (146,601 ) — — — (146,601 ) Cash and cash equivalents, beginning of year 157,439 — — — 157,439 Cash and cash equivalents, end of year $10,838 $— $— $— $10,838 Year Ended December 31, 2013 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($55,888 ) $423,366 ($4 ) $— $367,474 Net cash used in investing activities from continuing operations (86,322 ) (513,710 ) (2,057 ) 92,204 (509,885 ) Net cash provided by financing activities from continuing operations 120,326 90,143 2,061 (92,204 ) 120,326 Net cash provided by (used in) discontinued operations 127,429 — (519 ) — 126,910 Net increase (decrease) in cash and cash equivalents 105,545 (201 ) (519 ) — 104,825 Cash and cash equivalents, beginning of year 51,894 201 519 — 52,614 Cash and cash equivalents, end of year $157,439 $— $— $— $157,439

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Disclosures	16. Supplemental Cash Flow Information Supplemental disclosures to the consolidated statements of cash flows are presented below: Years Ended December 31, 2015 2014 2013 (In thousands) Net cash provided by operating activities: Cash paid for interest, net of amounts capitalized $64,692 $49,379 $50,770 Cash paid for income taxes — — 505 Non-cash investing and financing activities: Capital expenditures included in accounts payable and accrued capital expenditures $90,008 $176,886 $114,988 Other non-cash investing activities (1) 27,415 6,789 10,698 Purchase price adjustments related to the Eagle Ford Shale Acquisition — 3,197 — EFM deferred purchase payment — 148,900 — (1) Other non-cash investing activities includes items such as capital lease transactions, non-cash property exchanges, non-cash capitalized ARO additions and other non-cash activity.

Subsequent Events (Unaudited)

Subsequent Events (Unaudited)	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	17. Subsequent Events (Unaudited) In February 2016, the Company entered into the following oil and gas derivative instruments: Period Type of Contract Crude Oil Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) January - June 2017 Fixed Price Swaps 6,000 $50.27 Period Type of Contract Natural Gas Volumes (in MMBtu/d) Weighted Average Ceiling Price ($/MMBtu) FY 2017 Sold Call Options 33,000 $3.00 FY 2018 Sold Call Options 33,000 $3.25 FY 2019 Sold Call Options 33,000 $3.25 FY 2020 Sold Call Options 33,000 $3.50 The Company sold out-of-the-money natural gas call options for the years 2017 through 2020 and used the associated premium value to obtain a higher weighted average fixed price of $50.27 per Bbl on newly executed crude oil fixed price swaps for the first half of the year 2017. These out-of-the-money natural gas call options and in-the-money crude oil fixed price swaps were executed contemporaneously with the same counterparty, therefore, no cash premiums were paid to or received from the counterparty as the premium value associated with the natural gas call options was immediately applied to the crude oil fixed price swaps for the first half of the year 2017.

Supplemental Disclosures About

Supplemental Disclosures About Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Disclosures About Oil And Gas Producing Activities	18. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited) As of December 31, 2015, 2014 and 2013, the Company’s oil and gas properties are located in the U.S. As of January 1, 2013, the Company also had oil and gas properties located in the U.K. All information presented as “U.K.” in this footnote relates to the U.K. discontinued operations. For additional information see “Note 3. Discontinued Operations.” Costs Incurred Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Years Ended December 31, 2015 2014 2013 (In thousands) U.S. Property acquisition costs Proved property acquisition costs $— $183,633 $— Unproved property acquisition costs 63,446 215,021 254,099 Total property acquisition costs 63,446 398,654 254,099 Exploration costs 117,227 194,956 106,329 Development costs 389,396 530,268 423,871 Total costs incurred $570,069 $1,123,878 $784,299 Costs incurred exclude capitalized interest on U.S. unproved properties of $32.1 million , $34.5 million , and $29.9 million for the years ended December 31, 2015 , 2014 and 2013 , 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 wells of $4.9 million , $4.5 million and $3.7 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Proved Oil and Gas Reserve Quantities Proved reserves are generally those quantities of oil and 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 proved 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 are generally proved 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 oil and gas reserve quantities at December 31, 2015 , 2014 , and 2013 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. The Company’s net proved oil and gas reserves and changes in net proved oil and gas reserves, which are located in the U.S. and U.K., are summarized below: Crude Oil and Condensate (MBbls) Natural Gas Liquids (MBbls) U.S. U.K. Worldwide U.S. U.K. Worldwide Proved reserves: January 1, 2013 39,075 5,241 44,316 5,383 — 5,383 Extensions and discoveries 27,295 — 27,295 2,992 — 2,992 Revisions of previous estimates 778 — 778 308 — 308 Sales of reserves in place (876 ) (5,241 ) (6,117 ) — — — Production (4,231 ) — (4,231 ) (531 ) — (531 ) December 31, 2013 62,041 — 62,041 8,152 — 8,152 Extensions and discoveries 29,793 — 29,793 3,681 — 3,681 Revisions of previous estimates 3,046 — 3,046 1,270 — 1,270 Purchases of reserves in place 12,730 — 12,730 1,335 — 1,335 Production (6,906 ) — (6,906 ) (925 ) — (925 ) December 31, 2014 100,704 — 100,704 13,513 — 13,513 Extensions and discoveries 26,358 — 26,358 5,292 — 5,292 Revisions of previous estimates (9,059 ) — (9,059 ) 2,768 — 2,768 Production (8,415 ) — (8,415 ) (1,352 ) — (1,352 ) December 31, 2015 109,588 — 109,588 20,221 — 20,221 Proved developed reserves: December 31, 2013 18,321 — 18,321 2,779 — 2,779 December 31, 2014 35,238 — 35,238 5,294 — 5,294 December 31, 2015 42,311 — 42,311 7,933 — 7,933 Proved undeveloped reserves: December 31, 2013 43,720 — 43,720 5,373 — 5,373 December 31, 2014 65,466 — 65,466 8,219 — 8,219 December 31, 2015 67,277 — 67,277 12,288 — 12,288 Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following: 2015 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations, of which 92% was in the Eagle Ford. 2014 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford and the Niobrara. 2013 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford and the Niobrara. Crude oil, condensate and natural gas liquids revisions of previous estimates are primarily attributable to the following: 2015 Negative price revisions as a result of the significant decrease in the oil price used to calculate our proved oil reserves estimates of 11,194 MBbls, partially offset by positive performance revisions of 4,904 MBbls. Crude oil, condensate and natural gas liquids purchases of reserves in place are primarily attributable to the following: 2014 Acquisition of proved developed and undeveloped reserves from Eagle Ford Minerals, LLC. Crude oil, condensate and natural gas liquids sales of reserves in place are primarily attributable to the following: 2013 Sales of U.K. North Sea properties to Iona Energy during the first quarter and sales of U.S. properties in East Texas in the third quarter. Natural Gas (MMcf) Oil-Equivalent Proved Reserves (MBoe) U.S. U.K. Worldwide U.S. U.K. Worldwide Proved reserves: January 1, 2013 423,672 4,664 428,336 115,070 6,018 121,088 Extensions and discoveries 73,360 — 73,360 42,514 — 42,514 Revisions of previous estimates 29,819 — 29,819 6,055 — 6,055 Sales of reserves in place (307,472 ) (4,664 ) (312,136 ) (52,121 ) (6,018 ) (58,139 ) Production (31,422 ) — (31,422 ) (9,999 ) — (9,999 ) December 31, 2013 187,957 — 187,957 101,519 — 101,519 Extensions and discoveries 30,343 — 30,343 38,531 — 38,531 Revisions of previous estimates 18,913 — 18,913 7,469 — 7,469 Purchases of reserves in place 8,681 — 8,681 15,512 — 15,512 Production (24,877 ) — (24,877 ) (11,978 ) — (11,978 ) December 31, 2014 221,017 — 221,017 151,053 — 151,053 Extensions and discoveries 33,925 — 33,925 37,304 — 37,304 Revisions of previous estimates 11,808 — 11,808 (4,323 ) — (4,323 ) Production (21,812 ) — (21,812 ) (13,402 ) — (13,402 ) December 31, 2015 244,938 — 244,938 170,632 — 170,632 Proved developed reserves: December 31, 2013 106,976 — 106,976 38,929 — 38,929 December 31, 2014 149,697 — 149,697 65,482 — 65,482 December 31, 2015 154,725 — 154,725 76,032 — 76,032 Proved undeveloped reserves: December 31, 2013 80,981 — 80,981 62,590 — 62,590 December 31, 2014 71,320 — 71,320 85,571 — 85,571 December 31, 2015 90,213 — 90,213 94,600 — 94,600 Natural gas extensions and discoveries are primarily attributable to the following: 2015 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations, of which 81% was in the Eagle Ford. 2014 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford. 2013 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford. Natural gas revisions of previous estimates are primarily attributable to the following: 2015 Positive performance revisions of 39,715 MMcf, partially offset by negative price revisions of 27,908 MMcf. 2014 Positive price revisions in the U.S. primarily in the Marcellus. 2013 Positive price revisions in the U.S. primarily in the Marcellus. Natural gas purchases of reserves in place are primarily attributable to the following: 2014 Acquisition of proved developed and undeveloped reserves from Eagle Ford Minerals, LLC. Natural gas sales of reserves in place are primarily attributable to the following: 2013 Sale of U.S. properties in the Barnett Shale to EnerVest during the fourth quarter and U.K. properties to Iona during the first quarter. Standardized Measure The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows: U.S. (In thousands) 2013 Future cash inflows $6,936,276 Future production costs (1,629,663 ) Future development costs (1,340,722 ) Future income taxes (835,840 ) Future net cash flows 3,130,051 Less 10% annual discount to reflect timing of cash flows (1,508,640 ) Standard measure of discounted future net cash flows $1,621,411 2014 Future cash inflows $10,380,951 Future production costs (2,532,106 ) Future development costs (1,680,795 ) Future income taxes (1,354,524 ) Future net cash flows 4,813,526 Less 10% annual discount to reflect timing of cash flows (2,258,444 ) Standard measure of discounted future net cash flows $2,555,082 2015 Future cash inflows $5,878,348 Future production costs (2,124,059 ) Future development costs (1,178,773 ) Future income taxes — Future net cash flows 2,575,516 Less 10% annual discount to reflect timing of cash flows (1,210,292 ) Standard measure of discounted future net cash flows $1,365,224 Reserve estimates and future cash flows are based on the average realized prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2015 , 2014 and 2013 were $47.24 , $92.24 , and $99.44 per Bbl, respectively, for crude oil and condensate, $12.00 , $27.80 and $25.60 per Bbl, respectively, for natural gas liquids, and $1.87 , $3.24 and $2.97 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 oil and gas reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end 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 oil and gas reserve estimates. Changes in Standardized Measure Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below: U.S. U.K. Worldwide (In thousands) Standardized measure — January 1, 2013 $1,179,483 $238,912 $1,418,395 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production (232,361 ) — (232,361 ) Net change in estimated future development costs (10,602 ) — (10,602 ) Net change due to revisions in quantity estimates 205,686 — 205,686 Accretion of discount 141,229 44,160 185,389 Changes in production rates (timing) and other 56,052 (44,160 ) 11,892 Total revisions 160,004 — 160,004 Net change due to extensions and discoveries, net of estimated future development and production costs 873,028 — 873,028 Net change due to sales of minerals in place (191,155 ) (441,597 ) (632,752 ) Sales of oil and gas produced, net of production costs (444,841 ) — (444,841 ) Previously estimated development costs incurred 217,395 — 217,395 Net change in income taxes (172,503 ) 202,685 30,182 Net change in standardized measure of discounted future net cash flows 441,928 (238,912 ) 203,016 Standardized measure — December 31, 2013 $1,621,411 $— $1,621,411 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ($240,533 ) $— ($240,533 ) Net change in estimated future development costs 89,401 — 89,401 Net change due to revisions in quantity estimates 205,166 — 205,166 Accretion of discount 202,672 — 202,672 Changes in production rates (timing) and other (61,099 ) — (61,099 ) Total revisions 195,607 — 195,607 Net change due to extensions and discoveries, net of estimated future development and production costs 867,615 — 867,615 Net change due to purchases of minerals in place 352,867 — 352,867 Sales of oil and gas produced, net of production costs (598,036 ) — (598,036 ) Previously estimated development costs incurred 415,963 — 415,963 Net change in income taxes (300,345 ) — (300,345 ) Net change in standardized measure of discounted future net cash flows 933,671 — 933,671 Standardized measure — December 31, 2014 $2,555,082 $— $2,555,082 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ($2,547,213 ) $— ($2,547,213 ) Net change in estimated future development costs 342,238 — 342,238 Net change due to revisions in quantity estimates (157,271 ) — (157,271 ) Accretion of discount 326,074 — 326,074 Changes in production rates (timing) and other (139,533 ) — (139,533 ) Total revisions (2,175,705 ) — (2,175,705 ) Net change due to extensions and discoveries, net of estimated future development and production costs 252,155 — 252,155 Sales of oil and gas produced, net of production costs (312,213 ) — (312,213 ) Previously estimated development costs incurred 340,247 — 340,247 Net change in income taxes 705,658 — 705,658 Net change in standardized measure of discounted future net cash flows (1,189,858 ) — (1,189,858 ) Standardized measure — December 31, 2015 $1,365,224 $— $1,365,224

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	19. Selected Quarterly Financial Data (Unaudited) The following table presents selected quarterly financial data for the years ended December 31, 2015 and 2014 : 2015 First Second Third Fourth (In thousands, except per share amounts) Total revenues $100,050 $123,494 $106,237 $99,422 Loss from continuing operations (1)(2)(3) ($21,476 ) ($46,970 ) ($708,768 ) ($380,671 ) Net loss ($21,210 ) ($46,132 ) ($707,647 ) ($380,165 ) Net loss per common share - basic Loss from continuing operations ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss per common share ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) Net loss per common share - diluted Loss from continuing operations ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss per common share ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) 2014 First Second Third Fourth (In thousands, except per share amounts) Total revenues $157,212 $193,475 $196,225 $163,275 Income from continuing operations $6,621 $3,214 $82,997 $129,451 Net income $5,976 $2,319 $83,789 $134,259 Net income per common share - basic Income from continuing operations $0.15 $0.07 $1.83 $2.85 Net income per common share $0.13 $0.05 $1.85 $2.96 Net income per common share - diluted Income from continuing operations $0.14 $0.07 $1.80 $2.80 Net income per common share $0.13 $0.05 $1.82 $2.91 (1) In the second quarter of 2015, the Company recognized a loss on extinguishment of debt of $38.1 million as a result of the cash tender offer and redemption of the 8.625% Senior Notes. (2) In the third quarter of 2015, the Company recognized an after-tax impairment in the carrying value of proved oil and gas properties of $522.7 million ( $812.8 million pre-tax). (3) In the fourth quarter of 2015, the Company recognized an after-tax impairment in the carrying value of proved oil and gas properties of $273.1 million ( $411.6 million pre-tax). The sum of the quarterly net income (loss) per common share may not agree with the net income (loss) per common share for the years ended December 31, 2015 and 2014 as each quarterly computation is based on the net income (loss) for each period and the weighted average common shares outstanding during each period.

Summary Of Significant Accoun26

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
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.
Discontinued Operations	Discontinued Operations On February 22, 2013, the Company closed on the sale of Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all of its interest in the Huntington Field discovery, including a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) for an agreed-upon price of $184.0 million , including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding under Carrizo UK’s senior secured multicurrency credit facility as of the closing date. The liabilities, results of operations and cash flows associated with Carrizo UK have been classified as discontinued operations in the consolidated financial statements. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to discontinued operations is included in “Note 3. Discontinued Operations”, “Note 15. Condensed Consolidating Financial Information” and “Note 18. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited).”
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 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, drilling requirements and royalty obligations. 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, stock-based compensation, collectability of receivables, and in evaluating disputed claims, interpreting contractual arrangements (including royalty obligations and notional interest calculations) 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, counterparty creditworthiness, 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 Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the consolidated balance sheets and totaled $49.1 million and $70.5 million as of December 31, 2015 and 2014 , respectively.
Accounts Receivable And Allowance For Doubtful Accounts	Accounts Receivable 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, 2015 and 2014 , the Company’s allowance for doubtful accounts was $1.0 million and zero , 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 customers 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 does not require collateral from its customers and joint interest owners. The Company generally has the right to withhold future revenue distributions to recover any non-payment of joint interest billings. The Company’s derivative instruments in a net asset position also subject the Company to a concentration of credit risk. See “Note 13. Derivative Instruments.”
Major Customers	Major Customers Shell Trading (US) Company accounted for approximately 65% , 44% , and 47% of the Company’s oil and gas revenues in 2015 , 2014 , and 2013 , respectively. Flint Hills Resources, LP accounted for approximately 26% and 23% of the Company’s oil and gas revenues in 2014 and 2013 , 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 and totaled $15.8 million , $18.8 million and $15.0 million for the years ended December 31, 2015, 2014 and 2013 , 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 capitalized 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 $22.05 , $26.20 and $21.38 for the years ended December 31, 2015, 2014 and 2013 , respectively. Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost of exploratory wells in progress, and related capitalized interest. Exploratory wells in progress and 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 added to the oil and gas property costs subject to amortization. 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 and completion capital expenditure plans. The Company expects to complete its evaluation of the majority of its unevaluated leaseholds within the next five years and exploratory wells in progress within the next year. Geological and geophysical costs not associated with specific prospects are recorded to oil and gas property costs subject to amortization immediately. The Company capitalized interest costs associated with its unproved properties totaling $32.1 million , $34.5 million and $29.9 million for the years ended December 31, 2015, 2014 and 2013 , respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties using a weighted average interest rate based on outstanding borrowings. Capitalized costs, less accumulated amortization and 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. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period. The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prices are held constant indefinitely and are not changed 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 because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. During 2015, the Company recorded after-tax impairments in the carrying value of proved oil and gas properties of $795.8 million ( $1,224.4 million pre-tax) due primarily to declines in the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period. There were no impairments of proved oil and gas properties for the years ending December 31, 2014 and 2013. See “Note 5. Property and Equipment, Net” for further details of the impairment. Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of capitalized 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 2015 and 2014 the Company did not have any sales of oil and gas properties that significantly altered such relationship. On February 22, 2013, the Company closed the sale of Carrizo UK, which included all of the Company’s proved reserves in its U.K. cost center. As a result, in the first quarter of 2013, the Company recognized a $37.3 million pre-tax gain in “Net income from discontinued operations, net of income taxes” in the consolidated statements of operations. Further, on October 31, 2013, the Company closed the sale of its remaining oil and gas properties in the Barnett. The proved reserves attributable to the Barnett sale represented 40% of the Company’s proved reserves as of October 31, 2013, which significantly altered the relationship between capitalized costs and proved reserves of oil and gas attributable to the Company’s U.S. cost center. As a result, the Company recognized a pre-tax loss on the sale of $45.4 million in “Loss on sale of oil and gas properties” in the consolidated statements of operations in the fourth quarter of 2013. 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.
Financial Instruments	Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities 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 derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The carrying amounts of long-term debt under the Company’s revolving credit facility approximate fair value as borrowings bear interest at variable rates of interest. 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 any unamortized premium or discount and the notes bear interest at fixed rates of interest. See “Note 7. Long-Term Debt” and “Note 14. 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 when the production equipment and facilities are installed with an associated increase in 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. 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 8. 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 9. Commitments and Contingencies.”
Revenue Recognition	Revenue Recognition Oil and 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 an asset or 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, 2015 and 2014 , 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 substantial, but varying, portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. All derivative instruments are recorded on the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its 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 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 derivative instruments, including volumes, types of instruments and counterparties. These policies require that 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 13. Derivative Instruments” for further discussion of the Company’s derivative instruments.
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. 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. Stock Appreciation Rights. For SARs, stock-based compensation expense is based on the fair value liability (using the Black-Scholes-Merton option pricing model) remeasured at each reporting period, recognized over the vesting period (generally three years) using the graded vesting method. Each award includes a performance condition that must be met in order for that award to vest. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. 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 prepared by an independent third party) and recognized over the vesting period (generally three years) using the straight-line method. Each award includes a performance condition that must be met in order for that award to vest. 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 an industry peer group generally over a 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. See “Note 10. Shareholders’ Equity and Stock Incentive Plans.” Assumptions. The Black-Scholes-Merton option pricing model and the Monte Carlo valuation model require the Company to make the following assumptions: • The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant. • The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future. • The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date. For the Monte Carlo valuation model, daily, historical volatility for the industry peer group for the same time period as the Company is also used. • For the Black-Scholes-Merton option pricing model, the expected term is based on historical exercises for various groups of employees and independent contractors, while the Monte Carlo valuation model uses an expected term based on the performance period for the award.
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 routinely assesses the realizability of its deferred tax assets by taxing jurisdiction and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the benefit from deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance. As of December 31, 2015 , the Company recorded a valuation allowance against the net deferred tax asset of $324.7 million , reducing the net deferred tax asset to zero . See “Note 6. Income Taxes” for further discussion of the 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.
Recently Adopted Accounting Pronouncements	Recent Accounting Pronouncements In November, 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes. Update 2015 (“Update 2015-17”). Updated 2015-17 eliminates the current requirement to present deferred tax assets and liabilities as current and noncurrent on the consolidated balance sheets. Instead all deferred tax assets and liabilities will be presented as noncurrent. For public entities, Update 2015-17 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 31, 2016 and may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented with early adoption permitted. The adoption of Update 2015-17 is not expected to have a significant impact on the Company's consolidated financial statements, other than balance sheet reclassifications. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“Update 2015-03”). The objective of Update 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. Under Update 2015-15, debt issuance costs associated with line-of-credit agreements may be deferred and presented as an asset in the balance sheet, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. For public entities, Update 2015-03 and Update 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and applied retrospectively with early adoption permitted. The adoption of Update 2015-03 and Update 2015-15 will not have an impact on the Company’s consolidated financial statements, other than balance sheet reclassifications. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry specific guidance in Subtopic 932-605, Extractive Activities- Oil and Gas- Revenue Recognition. Update 2014-09 requires entities to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. In April 2015, the FASB proposed to delay the effective date one year. This proposal was approved in July 2015 and as such, Update 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period for public entities. The Company is currently evaluating the impact of the adoption of Update 2014-09 on its consolidated financial statements.

Earnings Per Share (Policies)

Earnings Per Share (Policies)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share, Policy	Basic income (loss) from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted income (loss) from continuing operations 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 excludes the number of awards, units, options and warrants from the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are greater than the average market prices of the Company’s common stock for the year as the effect would be anti-dilutive to the computation. 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 year was the end of the performance period. When a loss from continuing operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	The following table summarizes the amounts included in income from discontinued operations, net of income taxes presented in the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (In thousands) Revenues $— $— $— Costs and expenses General and administrative 1,426 656 916 Accretion related to asset retirement obligations — — 36 Gain on sale of discontinued operations — — (37,294 ) Increase (decrease) in estimated future obligations (6,424 ) (7,638 ) 44 Loss on derivatives, net — 34 109 Other income, net — — (438 ) Income From Discontinued Operations Before Income Taxes 4,998 6,948 36,627 Income tax expense (2,267 ) (2,888 ) (14,802 ) Income From Discontinued Operations, Net of Income Taxes $2,731 $4,060 $21,825

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following presents the purchase price and the allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date: October 24, 2014 (In thousands) Assets Other current assets $485 Proved and unproved oil and gas properties 244,124 Total assets acquired $244,609 Liabilities Asset retirement obligations $423 Total liabilities assumed $423 Net Assets Acquired $244,186
Business Acquisition, Pro Forma Information [Table Text Block]	The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2014, and December 31, 2013, assuming the Eagle Ford Shale Acquisition had been completed as of January 1, 2013, including adjustments to reflect the 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 Eagle Ford Shale Acquisition. Years Ended December 31, 2014 2013 (In thousands, except per share data) (Unaudited) Total revenues $761,199 $575,721 Income From Continuing Operations $264,714 $36,356 Income From Continuing Operations Per Common Share Basic $5.83 $0.89 Diluted $5.73 $0.88 Weighted Average Common Shares Outstanding Basic 45,372 40,781 Diluted 46,194 41,355

Property And Equipment, Net (Ta

Property And Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Schedule Of Property And Equipment	As of December 31, 2015 and 2014 , total property and equipment, net consisted of the following: December 31, 2015 2014 (In thousands) Proved properties $3,976,511 $3,174,268 Accumulated depreciation, depletion and amortization and impairment (2,607,360 ) (1,087,541 ) Proved properties, net 1,369,151 2,086,727 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 280,263 401,954 Exploratory wells in progress 9,432 71,402 Capitalized interest 45,757 61,841 Total unproved properties, not being amortized 335,452 535,197 Other property and equipment 22,677 16,017 Accumulated depreciation (10,419 ) (8,688 ) Other property and equipment, net 12,258 7,329 Total property and equipment, net $1,716,861 $2,629,253

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 (In thousands) Current income tax (expense) benefit U.S. Federal $— $— $411 State — — (141 ) Total current income tax benefit — — 270 Deferred income tax (expense) benefit U.S. Federal 131,502 (122,342 ) (12,404 ) State 9,373 (5,585 ) (769 ) Total deferred income tax (expense) benefit 140,875 (127,927 ) (13,173 ) Total income tax (expense) benefit from continuing operations $140,875 ($127,927 ) ($12,903 )
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, 2015 2014 2013 (In thousands) Income (loss) from continuing operations before income taxes ($1,298,760 ) $350,210 $34,761 Income tax (expense) benefit at the statutory rate 454,566 (122,574 ) (12,166 ) State income tax (expense) benefit, net of U.S. Federal income taxes and increase in valuation allowance 9,373 (5,585 ) (859 ) Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense 1,671 — — Deferred tax asset valuation allowance (323,586 ) — — Other (1,149 ) 232 122 Total income tax (expense) benefit from continuing operations $140,875 ($127,927 ) ($12,903 )
Schedule Of Deferred Tax Assets And Liabilities	As of December 31, 2015 and 2014 , deferred tax assets and liabilities are comprised of the following: December 31, 2015 2014 (In thousands) Deferred income tax assets Net operating loss carryforward - U.S. Federal and State $119,783 $56,876 Oil and gas properties 232,786 — Asset retirement obligations 5,779 4,379 Stock-based compensation 4,741 7,867 Fair value of derivative instruments 4,433 70 Other 3,435 2,989 Deferred income tax assets 370,957 72,181 Deferred tax asset valuation allowance (324,681 ) (1,095 ) Net deferred income tax assets 46,276 71,086 Deferred income tax liabilities Oil and gas properties — (134,518 ) Fair value of derivative instruments (46,276 ) (75,175 ) (46,276 ) (209,693 ) Net deferred income tax liability $— ($138,607 )
Schedule Of Net Deferred Income Assets And Liabilities	At December 31, 2015 and 2014 , the net deferred income tax asset (liability) is classified as follows: December 31, 2015 2014 (In thousands) Net current deferred income tax liability ($46,758 ) ($61,258 ) Net noncurrent deferred income tax asset (liability) 46,758 (77,349 ) Net deferred income tax liability $— ($138,607 )

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule Of Debt	Long-term debt consisted of the following as of December 31, 2015 and 2014 : December 31, 2015 2014 (In thousands) Deferred purchase payment $— $150,000 Unamortized discount for deferred purchase payment — (1,100 ) Senior Secured Revolving Credit Facility due 2018 — — 8.625% Senior Notes due 2018 — 600,000 Unamortized discount for 8.625% Senior Notes — (3,444 ) 7.50% Senior Notes due 2020 600,000 600,000 Unamortized premium for 7.50% Senior Notes 1,251 1,465 6.25% Senior Notes due 2023 650,000 — Other long-term debt due 2028 4,425 4,425 Long-term debt $1,255,676 $1,351,346
Interest and Commitment Fee Rates	Amounts 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 as set forth in the table below on the unused portion of lender commitments, and which are included as a component of interest expense. 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% 0.50% 1.50% 0.375% Greater than or equal to 25% but less than 50% 0.75% 1.75% 0.375% Greater than or equal to 50% but less than 75% 1.00% 2.00% 0.500% Greater than or equal to 75% but less than 90% 1.25% 2.25% 0.500% Greater than or equal to 90% 1.50% 2.50% 0.500%

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 : Years Ended December 31, 2015 2014 (In thousands) Asset retirement obligations at beginning of period $12,512 $7,356 Liabilities incurred 3,227 6,284 Increase due to acquisition of oil and gas properties — 423 Liabilities settled (1,966 ) (1,784 ) Accretion expense 1,112 710 Revisions of previous estimates (1) 1,626 (477 ) Asset retirement obligations at end of period 16,511 12,512 Current portion of asset retirement obligations included in “Other current liabilities” (328 ) (325 ) Long-term asset retirement obligations $16,183 $12,187

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Total Minimum Commitments From Long-Term Non-Cancelable Operating Leases, Drilling Rig, Seismic And Pipeline Volume Commitments	At December 31, 2015 , total minimum commitments from long-term, non-cancelable operating and capital leases, drilling rigs and pipeline volume commitments are as shown in the table below. The total minimum commitments related to the drilling rigs 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. 2016 2017 2018 2019 2020 2021 and Thereafter Total (In thousands) Operating leases $4,055 $4,185 $4,248 $4,357 $4,450 $6,304 $27,599 Capital leases 1,733 1,733 1,700 1,677 978 — 7,821 Drilling rig contracts 24,261 20,513 3,957 — — — 48,731 Pipeline volume commitments 8,596 7,474 7,474 6,141 3,651 5,431 38,767 Total $38,645 $33,905 $17,379 $12,175 $9,079 $11,735 $122,918

Shareholders' Equity And Stoc35

Shareholders' Equity And Stock Incentive Plan (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 , 2014 and 2013 : Restricted Stock Awards and Units Weighted Average Grant Date Fair Value For the Year Ended December 31, 2013 Unvested restricted stock awards and units, beginning of period 1,146,274 $26.95 Granted 932,763 $28.16 Vested (557,136 ) $25.98 Forfeited (77,034 ) $26.03 Unvested restricted stock awards and units, end of period 1,444,867 $28.03 For the Year Ended December 31, 2014 Unvested restricted stock awards and units, beginning of period 1,444,867 $28.03 Granted 576,812 $48.64 Vested (647,306 ) $32.64 Forfeited (38,691 ) $32.89 Unvested restricted stock awards and units, end of period 1,335,682 $34.55 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
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity	The table below summarizes the activity for SARs for the years ended December 31, 2015 , 2014 and 2013 : 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, 2013 Outstanding, beginning of period 1,035,823 $22.69 Granted 282,296 $28.68 Exercised (207,184 ) $19.30 $3.9 Forfeited (24,704 ) $27.77 Outstanding, end of period 1,086,231 $24.78 Exercisable, end of period 681,867 $22.55 For the Year Ended December 31, 2014 Outstanding, beginning of period 1,086,231 $24.78 Granted — — Exercised (321,033 ) $30.24 $7.8 Forfeited — — Outstanding, end of period 765,198 $22.49 Exercisable, end of period 587,481 $20.78 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 1.1 $5.1 Exercisable, end of period 626,661 $21.05 1.1 $5.0
Schedule of Share-based Payment Award, Non-Options, Valuation Assumptions	The following table summarizes the assumptions used to calculate the fair value of SARs granted during 2013 : Year Ended December 31, 2013 Stock price on the date of grant $13.36 Volatility factor 44.5 % Dividend yield — % Risk-free interest rate 1.0 % Expected term (in years) 3.5
Share-based Compensation, Performance Shares Award Unvested Activity	he table below summarizes performance share award activity for the years ended December 31, 2015 and 2014 : Performance Share Awards Weighted Average Grant Date Fair Value For the Year Ended December 31, 2014 Unvested performance share awards, beginning of period — — Granted 56,342 $68.15 Vested — — Forfeited — — Unvested performance share awards, end of period 56,342 $68.15 For the Year Ended December 31, 2015 Unvested performance share awards, beginning of period 56,342 $68.15 Granted 56,517 $65.51 Vested — — Forfeited — — Unvested performance share awards, end of period 112,859 $66.83
Schedule of Share-based Payment Award, Performance Share Award, Valuation Assumptions	The following table summarizes the assumptions used to calculate the fair value of the performance share awards granted in 2015 and 2014 : Years Ended December 31, 2015 2014 Number of simulations 500,000 500,000 Stock price on the date of grant $53.58 $53.96 Volatility factor 45.3 % 49.9 % Dividend yield — % — % Risk-free interest rate 0.9 % 0.9 % Expected term (in years) 2.89 2.97
Summary Of Stock Options Activity	The table below summarizes the activity for stock options for the years ended December 31, 2015 , 2014 and 2013 : Stock Options Weighted Average Exercise Prices Weighted Average Remaining Life (In years) Aggregate Intrinsic Value (In millions) Cash Received from Exercises (In millions) Tax Benefit Realized from Exercises (In millions) For the Year Ended December 31, 2013 Outstanding, beginning of period 242,854 $7.24 Granted — — Exercised (206,501 ) $6.07 $4.4 $1.3 $1.5 Forfeited — — Outstanding, end of period 36,353 $13.91 1.1 $1.1 Exercisable, end of period 36,353 $13.91 1.1 $1.1 For the Year Ended December 31, 2014 Outstanding, beginning of period 36,353 $13.91 Granted — — Exercised (33,086 ) $13.20 $1.3 $0.4 $0.4 Forfeited — — Expired (834 ) $27.25 Outstanding, end of period 2,433 $19.02 0.5 $0.1 Exercisable, end of period 2,433 $19.02 0.5 $0.1 For the Year Ended December 31, 2015 Outstanding, beginning of period 2,433 $19.02 Granted — — Exercised (2,433 ) $19.02 $0.1 $— $0.1 Forfeited — — Outstanding, end of period — — 0 — Exercisable, end of period — — 0 —
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]	The Company recognized the following stock-based compensation expense associated with restricted stock awards and units, SARs, and performance share awards for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations: Years Ended December 31, 2015 2014 2013 (In thousands) Restricted stock awards and units $23,668 $29,597 $18,997 Stock appreciation rights (6,326 ) 1,985 17,303 Performance share awards 1,961 1,395 — 19,303 32,977 36,300 Less: amounts capitalized (4,574 ) (7,099 ) (6,927 ) Total stock-based compensation expense $14,729 $25,878 $29,373 Income tax benefit $5,155 $9,059 $10,281

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Supplemental income (loss) from continuing operations per common share information is provided below: Years Ended December 31, 2015 2014 2013 (In thousands, except per share amounts) Income (Loss) From Continuing Operations ($1,157,885 ) $222,283 $21,858 Basic weighted average common shares outstanding 51,457 45,372 40,781 Effect of dilutive instruments: Restricted stock awards and units — 684 492 Performance share awards — 56 — Stock options — 13 47 Warrants — 69 35 Diluted weighted average common shares outstanding 51,457 46,194 41,355 Income (Loss) From Continuing Operations Per Common Share Basic ($22.50 ) $4.90 $0.54 Diluted ($22.50 ) $4.81 $0.53

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Positions	The following sets forth a summary of the Company’s open crude oil derivative positions at average NYMEX prices as of December 31, 2015 . Period Type of Contract Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) FY 2016 Fixed Price Swaps 9,315 $60.03 FY 2016 Costless Collars 5,490 $50.96 $74.73 FY 2018 Sold Call Options 2,488 $60.00 FY 2018 Sold Call Options 900 $75.00 FY 2019 Sold Call Options 2,975 $62.50 FY 2019 Sold Call Options 900 $77.50 FY 2020 Sold Call Options 3,675 $65.00 FY 2020 Sold Call Options 900 $80.00 In February 2016, the Company entered into the following oil and gas derivative instruments: Period Type of Contract Crude Oil Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) January - June 2017 Fixed Price Swaps 6,000 $50.27 Period Type of Contract Natural Gas Volumes (in MMBtu/d) Weighted Average Ceiling Price ($/MMBtu) FY 2017 Sold Call Options 33,000 $3.00 FY 2018 Sold Call Options 33,000 $3.25 FY 2019 Sold Call Options 33,000 $3.25 FY 2020 Sold Call Options 33,000 $3.50
Schedule of Derivative Instruments by Counterparty	The fair value of derivative instruments where the Company is in a net asset position with its counterparties as of December 31, 2015 and 2014 totaled $119.6 million and $214.8 million , respectively, and is summarized by counterparty in the table below: Counterparty December 31, 2015 December 31, 2014 Societe Generale 37 % 26 % Wells Fargo 35 % 37 % Citibank 13 % — % Regions 9 % 8 % Union Bank 5 % 4 % Capital One 1 % — % Credit Suisse — % 24 % Royal Bank of Canada — % 1 % Total 100 % 100 %

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Assets And Liabilities Measured At Fair Value On A Recurring Basis	The following tables summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of December 31, 2015 and 2014 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: December 31, 2015 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $159,447 ($28,347 ) $131,100 Derivative assets-non current 10,780 (9,665 ) 1,115 Derivative liabilities Other current liabilities (28,364 ) 28,347 (17 ) Derivative liabilities-non current (22,313 ) 9,665 (12,648 ) Total $119,550 $— $119,550 December 31, 2014 Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets (In thousands) Derivative assets Derivative assets-current $183,625 ($12,524 ) $171,101 Derivative assets-non current 44,725 (1,041 ) 43,684 Derivative liabilities Other current liabilities (12,707 ) 12,524 (183 ) Derivative liabilities-non current (1,058 ) 1,041 (17 ) Total $214,585 $— $214,585
Schedule of Fair Value of Debt Instruments	The following table presents the carrying amounts of long-term debt with the fair values of the Company’s senior notes and other long-term debt based on quoted market prices and the fair value of the deferred purchase payment based on indirect observable market rates. December 31, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) Deferred purchase payment due 2015 $— $— $148,900 $148,558 8.625% Senior Notes due 2018 — — 596,555 597,000 7.50% Senior Notes due 2020 601,251 528,000 601,466 573,000 6.25% Senior Notes due 2023 650,000 533,000 — — Other long-term debt due 2028 4,425 4,182 4,425 4,071

Condensed Consolidating Finan39

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	15. 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. Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A. CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING BALANCE SHEETS (In thousands) December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,578,034 $52,067 $— ($2,397,919 ) $232,182 Total property and equipment, net 44,499 1,671,774 3,059 (2,471 ) 1,716,861 Investment in subsidiaries (815,836 ) — — 815,836 — Other assets 94,338 156 — (16,632 ) 77,862 Total Assets $1,901,035 $1,723,997 $3,059 ($1,601,186 ) $2,026,905 Liabilities and Shareholders’ Equity Current liabilities $161,792 $2,521,572 $3,059 ($2,400,939 ) $285,484 Long-term liabilities 1,279,859 18,261 — (753 ) 1,297,367 Total shareholders’ equity 459,384 (815,836 ) — 800,506 444,054 Total Liabilities and Shareholders’ Equity $1,901,035 $1,723,997 $3,059 ($1,601,186 ) $2,026,905 December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,380,445 $245,051 $111 ($2,346,986 ) $278,621 Total property and equipment, net 613 2,562,029 39,939 26,672 2,629,253 Investment in subsidiaries 233,173 — — (233,173 ) — Other assets 140,774 — — (67,172 ) 73,602 Total Assets $2,755,005 $2,807,080 $40,050 ($2,620,659 ) $2,981,476 Liabilities and Shareholders’ Equity Current liabilities $296,686 $2,434,649 $39,955 ($2,346,986 ) $424,304 Long-term liabilities 1,364,793 139,353 — (50,415 ) 1,453,731 Total shareholders’ equity 1,093,526 233,078 95 (223,258 ) 1,103,441 Total Liabilities and Shareholders’ Equity $2,755,005 $2,807,080 $40,050 ($2,620,659 ) $2,981,476 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (In thousands) 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 ) Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $3,938 $706,121 $128 $— $710,187 Total costs and expenses (76,531 ) 442,343 30 (5,865 ) 359,977 Income from continuing operations before income taxes 80,469 263,778 98 5,865 350,210 Income tax expense (28,164 ) (92,322 ) — (7,441 ) (127,927 ) Equity in income of subsidiaries 171,554 — — (171,554 ) — Income from continuing operations $223,859 $171,456 $98 ($173,130 ) $222,283 Income from discontinued operations, net of income taxes 4,060 — — — 4,060 Net income $227,919 $171,456 $98 ($173,130 ) $226,343 Year Ended December 31, 2013 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $6,490 $513,692 $— $— $520,182 Total costs and expenses 134,874 349,782 3 762 485,421 Income (loss) from continuing operations before income taxes (128,384 ) 163,910 (3 ) (762 ) 34,761 Income tax (expense) benefit 44,934 (57,369 ) — (468 ) (12,903 ) Equity in income of subsidiaries 106,538 — — (106,538 ) — Income (loss) from continuing operations $23,088 $106,541 ($3 ) ($107,768 ) $21,858 Income from discontinued operations, net of income taxes 21,825 — — — 21,825 Net income (loss) $44,913 $106,541 ($3 ) ($107,768 ) $43,683 CARRIZO OIL & GAS, INC. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) 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 Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($132,683 ) $634,970 ($12 ) $— $502,275 Net cash used in investing activities from continuing operations (305,718 ) (906,509 ) (37,609 ) 309,160 (940,676 ) Net cash provided by financing activities from continuing operations 300,290 271,539 37,621 (309,160 ) 300,290 Net cash used in discontinued operations (8,490 ) — — — (8,490 ) Net decrease in cash and cash equivalents (146,601 ) — — — (146,601 ) Cash and cash equivalents, beginning of year 157,439 — — — 157,439 Cash and cash equivalents, end of year $10,838 $— $— $— $10,838 Year Ended December 31, 2013 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($55,888 ) $423,366 ($4 ) $— $367,474 Net cash used in investing activities from continuing operations (86,322 ) (513,710 ) (2,057 ) 92,204 (509,885 ) Net cash provided by financing activities from continuing operations 120,326 90,143 2,061 (92,204 ) 120,326 Net cash provided by (used in) discontinued operations 127,429 — (519 ) — 126,910 Net increase (decrease) in cash and cash equivalents 105,545 (201 ) (519 ) — 104,825 Cash and cash equivalents, beginning of year 51,894 201 519 — 52,614 Cash and cash equivalents, end of year $157,439 $— $— $— $157,439
Schedule Of Condensed Consolidating Balance Sheets	December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,578,034 $52,067 $— ($2,397,919 ) $232,182 Total property and equipment, net 44,499 1,671,774 3,059 (2,471 ) 1,716,861 Investment in subsidiaries (815,836 ) — — 815,836 — Other assets 94,338 156 — (16,632 ) 77,862 Total Assets $1,901,035 $1,723,997 $3,059 ($1,601,186 ) $2,026,905 Liabilities and Shareholders’ Equity Current liabilities $161,792 $2,521,572 $3,059 ($2,400,939 ) $285,484 Long-term liabilities 1,279,859 18,261 — (753 ) 1,297,367 Total shareholders’ equity 459,384 (815,836 ) — 800,506 444,054 Total Liabilities and Shareholders’ Equity $1,901,035 $1,723,997 $3,059 ($1,601,186 ) $2,026,905 December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Assets Total current assets $2,380,445 $245,051 $111 ($2,346,986 ) $278,621 Total property and equipment, net 613 2,562,029 39,939 26,672 2,629,253 Investment in subsidiaries 233,173 — — (233,173 ) — Other assets 140,774 — — (67,172 ) 73,602 Total Assets $2,755,005 $2,807,080 $40,050 ($2,620,659 ) $2,981,476 Liabilities and Shareholders’ Equity Current liabilities $296,686 $2,434,649 $39,955 ($2,346,986 ) $424,304 Long-term liabilities 1,364,793 139,353 — (50,415 ) 1,453,731 Total shareholders’ equity 1,093,526 233,078 95 (223,258 ) 1,103,441 Total Liabilities and Shareholders’ Equity $2,755,005 $2,807,080 $40,050 ($2,620,659 ) $2,981,476
Schedule Of Condensed Consolidating Statements Of Operations	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 ) Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $3,938 $706,121 $128 $— $710,187 Total costs and expenses (76,531 ) 442,343 30 (5,865 ) 359,977 Income from continuing operations before income taxes 80,469 263,778 98 5,865 350,210 Income tax expense (28,164 ) (92,322 ) — (7,441 ) (127,927 ) Equity in income of subsidiaries 171,554 — — (171,554 ) — Income from continuing operations $223,859 $171,456 $98 ($173,130 ) $222,283 Income from discontinued operations, net of income taxes 4,060 — — — 4,060 Net income $227,919 $171,456 $98 ($173,130 ) $226,343 Year Ended December 31, 2013 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Total revenues $6,490 $513,692 $— $— $520,182 Total costs and expenses 134,874 349,782 3 762 485,421 Income (loss) from continuing operations before income taxes (128,384 ) 163,910 (3 ) (762 ) 34,761 Income tax (expense) benefit 44,934 (57,369 ) — (468 ) (12,903 ) Equity in income of subsidiaries 106,538 — — (106,538 ) — Income (loss) from continuing operations $23,088 $106,541 ($3 ) ($107,768 ) $21,858 Income from discontinued operations, net of income taxes 21,825 — — — 21,825 Net income (loss) $44,913 $106,541 ($3 ) ($107,768 ) $43,683
Schedule Of Condensed Consolidating Statements Of Cash Flows	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 Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($132,683 ) $634,970 ($12 ) $— $502,275 Net cash used in investing activities from continuing operations (305,718 ) (906,509 ) (37,609 ) 309,160 (940,676 ) Net cash provided by financing activities from continuing operations 300,290 271,539 37,621 (309,160 ) 300,290 Net cash used in discontinued operations (8,490 ) — — — (8,490 ) Net decrease in cash and cash equivalents (146,601 ) — — — (146,601 ) Cash and cash equivalents, beginning of year 157,439 — — — 157,439 Cash and cash equivalents, end of year $10,838 $— $— $— $10,838 Year Ended December 31, 2013 Parent Company Combined Guarantor Subsidiaries Combined Non- Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities from continuing operations ($55,888 ) $423,366 ($4 ) $— $367,474 Net cash used in investing activities from continuing operations (86,322 ) (513,710 ) (2,057 ) 92,204 (509,885 ) Net cash provided by financing activities from continuing operations 120,326 90,143 2,061 (92,204 ) 120,326 Net cash provided by (used in) discontinued operations 127,429 — (519 ) — 126,910 Net increase (decrease) in cash and cash equivalents 105,545 (201 ) (519 ) — 104,825 Cash and cash equivalents, beginning of year 51,894 201 519 — 52,614 Cash and cash equivalents, end of year $157,439 $— $— $— $157,439

Supplemental Cash Flow Inform40

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplemental disclosures to the consolidated statements of cash flows are presented below: Years Ended December 31, 2015 2014 2013 (In thousands) Net cash provided by operating activities: Cash paid for interest, net of amounts capitalized $64,692 $49,379 $50,770 Cash paid for income taxes — — 505 Non-cash investing and financing activities: Capital expenditures included in accounts payable and accrued capital expenditures $90,008 $176,886 $114,988 Other non-cash investing activities (1) 27,415 6,789 10,698 Purchase price adjustments related to the Eagle Ford Shale Acquisition — 3,197 — EFM deferred purchase payment — 148,900 —

Subsequent Events (Unaudited) (

Subsequent Events (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Schedule of Derivative Positions	The following sets forth a summary of the Company’s open crude oil derivative positions at average NYMEX prices as of December 31, 2015 . Period Type of Contract Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) Weighted Average Ceiling Price ($/Bbl) FY 2016 Fixed Price Swaps 9,315 $60.03 FY 2016 Costless Collars 5,490 $50.96 $74.73 FY 2018 Sold Call Options 2,488 $60.00 FY 2018 Sold Call Options 900 $75.00 FY 2019 Sold Call Options 2,975 $62.50 FY 2019 Sold Call Options 900 $77.50 FY 2020 Sold Call Options 3,675 $65.00 FY 2020 Sold Call Options 900 $80.00 In February 2016, the Company entered into the following oil and gas derivative instruments: Period Type of Contract Crude Oil Volumes (in Bbls/d) Weighted Average Floor Price ($/Bbl) January - June 2017 Fixed Price Swaps 6,000 $50.27 Period Type of Contract Natural Gas Volumes (in MMBtu/d) Weighted Average Ceiling Price ($/MMBtu) FY 2017 Sold Call Options 33,000 $3.00 FY 2018 Sold Call Options 33,000 $3.25 FY 2019 Sold Call Options 33,000 $3.25 FY 2020 Sold Call Options 33,000 $3.50

Supplemental Disclosures Abou42

Supplemental Disclosures About Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 (In thousands) U.S. Property acquisition costs Proved property acquisition costs $— $183,633 $— Unproved property acquisition costs 63,446 215,021 254,099 Total property acquisition costs 63,446 398,654 254,099 Exploration costs 117,227 194,956 106,329 Development costs 389,396 530,268 423,871 Total costs incurred $570,069 $1,123,878 $784,299
Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas Reserves	The Company’s net proved oil and gas reserves and changes in net proved oil and gas reserves, which are located in the U.S. and U.K., are summarized below: Crude Oil and Condensate (MBbls) Natural Gas Liquids (MBbls) U.S. U.K. Worldwide U.S. U.K. Worldwide Proved reserves: January 1, 2013 39,075 5,241 44,316 5,383 — 5,383 Extensions and discoveries 27,295 — 27,295 2,992 — 2,992 Revisions of previous estimates 778 — 778 308 — 308 Sales of reserves in place (876 ) (5,241 ) (6,117 ) — — — Production (4,231 ) — (4,231 ) (531 ) — (531 ) December 31, 2013 62,041 — 62,041 8,152 — 8,152 Extensions and discoveries 29,793 — 29,793 3,681 — 3,681 Revisions of previous estimates 3,046 — 3,046 1,270 — 1,270 Purchases of reserves in place 12,730 — 12,730 1,335 — 1,335 Production (6,906 ) — (6,906 ) (925 ) — (925 ) December 31, 2014 100,704 — 100,704 13,513 — 13,513 Extensions and discoveries 26,358 — 26,358 5,292 — 5,292 Revisions of previous estimates (9,059 ) — (9,059 ) 2,768 — 2,768 Production (8,415 ) — (8,415 ) (1,352 ) — (1,352 ) December 31, 2015 109,588 — 109,588 20,221 — 20,221 Proved developed reserves: December 31, 2013 18,321 — 18,321 2,779 — 2,779 December 31, 2014 35,238 — 35,238 5,294 — 5,294 December 31, 2015 42,311 — 42,311 7,933 — 7,933 Proved undeveloped reserves: December 31, 2013 43,720 — 43,720 5,373 — 5,373 December 31, 2014 65,466 — 65,466 8,219 — 8,219 December 31, 2015 67,277 — 67,277 12,288 — 12,288 Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following: 2015 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations, of which 92% was in the Eagle Ford. 2014 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford and the Niobrara. 2013 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford and the Niobrara. Crude oil, condensate and natural gas liquids revisions of previous estimates are primarily attributable to the following: 2015 Negative price revisions as a result of the significant decrease in the oil price used to calculate our proved oil reserves estimates of 11,194 MBbls, partially offset by positive performance revisions of 4,904 MBbls. Crude oil, condensate and natural gas liquids purchases of reserves in place are primarily attributable to the following: 2014 Acquisition of proved developed and undeveloped reserves from Eagle Ford Minerals, LLC. Crude oil, condensate and natural gas liquids sales of reserves in place are primarily attributable to the following: 2013 Sales of U.K. North Sea properties to Iona Energy during the first quarter and sales of U.S. properties in East Texas in the third quarter. Natural Gas (MMcf) Oil-Equivalent Proved Reserves (MBoe) U.S. U.K. Worldwide U.S. U.K. Worldwide Proved reserves: January 1, 2013 423,672 4,664 428,336 115,070 6,018 121,088 Extensions and discoveries 73,360 — 73,360 42,514 — 42,514 Revisions of previous estimates 29,819 — 29,819 6,055 — 6,055 Sales of reserves in place (307,472 ) (4,664 ) (312,136 ) (52,121 ) (6,018 ) (58,139 ) Production (31,422 ) — (31,422 ) (9,999 ) — (9,999 ) December 31, 2013 187,957 — 187,957 101,519 — 101,519 Extensions and discoveries 30,343 — 30,343 38,531 — 38,531 Revisions of previous estimates 18,913 — 18,913 7,469 — 7,469 Purchases of reserves in place 8,681 — 8,681 15,512 — 15,512 Production (24,877 ) — (24,877 ) (11,978 ) — (11,978 ) December 31, 2014 221,017 — 221,017 151,053 — 151,053 Extensions and discoveries 33,925 — 33,925 37,304 — 37,304 Revisions of previous estimates 11,808 — 11,808 (4,323 ) — (4,323 ) Production (21,812 ) — (21,812 ) (13,402 ) — (13,402 ) December 31, 2015 244,938 — 244,938 170,632 — 170,632 Proved developed reserves: December 31, 2013 106,976 — 106,976 38,929 — 38,929 December 31, 2014 149,697 — 149,697 65,482 — 65,482 December 31, 2015 154,725 — 154,725 76,032 — 76,032 Proved undeveloped reserves: December 31, 2013 80,981 — 80,981 62,590 — 62,590 December 31, 2014 71,320 — 71,320 85,571 — 85,571 December 31, 2015 90,213 — 90,213 94,600 — 94,600 Natural gas extensions and discoveries are primarily attributable to the following: 2015 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations, of which 81% was in the Eagle Ford. 2014 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford. 2013 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford. Natural gas revisions of previous estimates are primarily attributable to the following: 2015 Positive performance revisions of 39,715 MMcf, partially offset by negative price revisions of 27,908 MMcf. 2014 Positive price revisions in the U.S. primarily in the Marcellus. 2013 Positive price revisions in the U.S. primarily in the Marcellus. Natural gas purchases of reserves in place are primarily attributable to the following: 2014 Acquisition of proved developed and undeveloped reserves from Eagle Ford Minerals, LLC. Natural gas sales of reserves in place are primarily attributable to the following: 2013 Sale of U.S. properties in the Barnett Shale to EnerVest during the fourth quarter and U.K. properties to Iona during the first quarter.
Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	he standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows: U.S. (In thousands) 2013 Future cash inflows $6,936,276 Future production costs (1,629,663 ) Future development costs (1,340,722 ) Future income taxes (835,840 ) Future net cash flows 3,130,051 Less 10% annual discount to reflect timing of cash flows (1,508,640 ) Standard measure of discounted future net cash flows $1,621,411 2014 Future cash inflows $10,380,951 Future production costs (2,532,106 ) Future development costs (1,680,795 ) Future income taxes (1,354,524 ) Future net cash flows 4,813,526 Less 10% annual discount to reflect timing of cash flows (2,258,444 ) Standard measure of discounted future net cash flows $2,555,082 2015 Future cash inflows $5,878,348 Future production costs (2,124,059 ) Future development costs (1,178,773 ) Future income taxes — Future net cash flows 2,575,516 Less 10% annual discount to reflect timing of cash flows (1,210,292 ) Standard measure of discounted future net cash flows $1,365,224
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	hanges in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below: U.S. U.K. Worldwide (In thousands) Standardized measure — January 1, 2013 $1,179,483 $238,912 $1,418,395 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production (232,361 ) — (232,361 ) Net change in estimated future development costs (10,602 ) — (10,602 ) Net change due to revisions in quantity estimates 205,686 — 205,686 Accretion of discount 141,229 44,160 185,389 Changes in production rates (timing) and other 56,052 (44,160 ) 11,892 Total revisions 160,004 — 160,004 Net change due to extensions and discoveries, net of estimated future development and production costs 873,028 — 873,028 Net change due to sales of minerals in place (191,155 ) (441,597 ) (632,752 ) Sales of oil and gas produced, net of production costs (444,841 ) — (444,841 ) Previously estimated development costs incurred 217,395 — 217,395 Net change in income taxes (172,503 ) 202,685 30,182 Net change in standardized measure of discounted future net cash flows 441,928 (238,912 ) 203,016 Standardized measure — December 31, 2013 $1,621,411 $— $1,621,411 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ($240,533 ) $— ($240,533 ) Net change in estimated future development costs 89,401 — 89,401 Net change due to revisions in quantity estimates 205,166 — 205,166 Accretion of discount 202,672 — 202,672 Changes in production rates (timing) and other (61,099 ) — (61,099 ) Total revisions 195,607 — 195,607 Net change due to extensions and discoveries, net of estimated future development and production costs 867,615 — 867,615 Net change due to purchases of minerals in place 352,867 — 352,867 Sales of oil and gas produced, net of production costs (598,036 ) — (598,036 ) Previously estimated development costs incurred 415,963 — 415,963 Net change in income taxes (300,345 ) — (300,345 ) Net change in standardized measure of discounted future net cash flows 933,671 — 933,671 Standardized measure — December 31, 2014 $2,555,082 $— $2,555,082 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ($2,547,213 ) $— ($2,547,213 ) Net change in estimated future development costs 342,238 — 342,238 Net change due to revisions in quantity estimates (157,271 ) — (157,271 ) Accretion of discount 326,074 — 326,074 Changes in production rates (timing) and other (139,533 ) — (139,533 ) Total revisions (2,175,705 ) — (2,175,705 ) Net change due to extensions and discoveries, net of estimated future development and production costs 252,155 — 252,155 Sales of oil and gas produced, net of production costs (312,213 ) — (312,213 ) Previously estimated development costs incurred 340,247 — 340,247 Net change in income taxes 705,658 — 705,658 Net change in standardized measure of discounted future net cash flows (1,189,858 ) — (1,189,858 ) Standardized measure — December 31, 2015 $1,365,224 $— $1,365,224

Selected Quarterly Financial 43

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	The following table presents selected quarterly financial data for the years ended December 31, 2015 and 2014 : 2015 First Second Third Fourth (In thousands, except per share amounts) Total revenues $100,050 $123,494 $106,237 $99,422 Loss from continuing operations (1)(2)(3) ($21,476 ) ($46,970 ) ($708,768 ) ($380,671 ) Net loss ($21,210 ) ($46,132 ) ($707,647 ) ($380,165 ) Net loss per common share - basic Loss from continuing operations ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss per common share ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) Net loss per common share - diluted Loss from continuing operations ($0.46 ) ($0.92 ) ($13.75 ) ($6.73 ) Net loss per common share ($0.46 ) ($0.90 ) ($13.73 ) ($6.72 ) 2014 First Second Third Fourth (In thousands, except per share amounts) Total revenues $157,212 $193,475 $196,225 $163,275 Income from continuing operations $6,621 $3,214 $82,997 $129,451 Net income $5,976 $2,319 $83,789 $134,259 Net income per common share - basic Income from continuing operations $0.15 $0.07 $1.83 $2.85 Net income per common share $0.13 $0.05 $1.85 $2.96 Net income per common share - diluted Income from continuing operations $0.14 $0.07 $1.80 $2.80 Net income per common share $0.13 $0.05 $1.82 $2.91

Summary Of Significant Accoun44

Summary Of Significant Accounting Policies (Narrative) (Details) $ in Thousands	3 Months Ended			9 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe	Dec. 31, 2013USD ($)$ / Boe	Feb. 22, 2013USD ($)
Summary Of Significant Accounting Policies [Line Items]
Other Accounts Payable and Accrued Liabilities	$ 49,100				$ 49,100	$ 70,500
Allowance for doubtful accounts receivable	1,000				1,000	0
Internal costs capitalized, Oil and Gas Producing Activities					$ 15,800	$ 18,800	$ 15,000
Average DD&A Per Boe (in USD per BOE) | $ / Boe					22.05	26.20	21.38
Capitalized interest					$ 32,100	$ 34,500	$ 29,900
Reserves discount factor					10.00%
After-tax impairment of oil and gas properties	273,100	$ 522,700			$ 795,800
Impairment of oil and gas properties	411,600	812,800		$ 0	1,224,367	0	$ 0
Gain on sale of discontinued operations						37,300
Percent of total proved reserves that were sold			40.00%				40.00%
Loss on sale of oil and gas properties			$ 45,377		0	0	$ 45,377
Deferred Tax Assets, Valuation Allowance	324,681	$ 187,600			324,681	1,095
Deferred Tax Assets, Net	$ 0				$ 0
Evaluation Period For Unevaluated Leaseholds					5 years
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
Stock Appreciation Rights (SARs) [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]
Expiration period, in years					4 years
Stock Appreciation Rights (SARs) [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Expiration period, in years					7 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
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%
Carrizo United Kingdom [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of non-operating working interest overriding royalty interests								15.00%
Disposal Group, Including Discontinued Operation, Consideration								$ 184,000
Gain on sale of discontinued operations					$ 0	$ 0	$ (37,294)
Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Customer percentage of total revenue					65.00%	44.00%	47.00%
Customer Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Customer percentage of total revenue						26.00%	23.00%
Contractor [Member] | Restricted Stock Granted To Contractors [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years					3 years
Huntington Field Development Project Credit Facility [Member] | Carrizo United Kingdom [Member]
Summary Of Significant Accounting Policies [Line Items]
Long-term Line of Credit								$ 55,000

Discontinued Operations (Narrat

Discontinued Operations (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 22, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of discontinued operations		$ (37,300)
Other current liabilities	$ 2,666	4,405
Liabilities of discontinued operations	1,088	8,394
Carrizo United Kingdom [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of non-operating working interest overriding royalty interests				15.00%
Disposal Group, Including Discontinued Operation, Consideration				$ 184,000
Gain on sale of discontinued operations	0	0	$ 37,294
Liabilities of Disposal Group, Including Discontinued Operation	$ 3,800	$ 12,800
Carrizo United Kingdom [Member] | Huntington Field Development Project Credit Facility [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Line of Credit				$ 55,000

Discontinued Operations (Statem

Discontinued Operations (Statements of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Gain on sale of discontinued operations		$ 37,300
Income From Discontinued Operations, Net of Income Taxes	$ 2,731	4,060	$ 21,825
Carrizo United Kingdom [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenues	0	0	0
General and administrative	1,426	656	916
Accretion related to asset retirement obligations	0	0	36
Gain on sale of discontinued operations	0	0	(37,294)
Increase (decrease) in estimated future obligations	(6,424)	(7,638)	44
Loss on derivatives, net	0	34	109
Other income, net	0	0	(438)
Income From Discontinued Operations Before Income Taxes	4,998	6,948	36,627
Income tax expense	(2,267)	(2,888)	(14,802)
Income From Discontinued Operations, Net of Income Taxes	$ 2,731	$ 4,060	$ 21,825

Acquisitions and Divestitures47

Acquisitions and Divestitures (Narrative) (Details) - USD ($) $ in Thousands	Feb. 13, 2015	Oct. 24, 2014	Dec. 31, 2013	Feb. 16, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Net proceeds from sale of properties			$ 191,800
Payments to Acquire Oil and Gas Property					$ 1,817	$ 92,961	$ 0
Purchase price adjustments		$ 3,200			0	3,197	$ 0
Sale price of oil and gas property and equipment			$ 218,000
Percent of total proved reserves that were sold			40.00%				40.00%
Loss on sale of oil and gas properties			$ (45,377)		$ 0	$ 0	$ (45,377)
Eagle Ford Shale Transaction [Member]
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property	$ 148,800	$ 93,000
Adjusted Purchase Price for Acquisition of Oil and Gas Property	$ 241,800
Total Agreed Upon Purchase Price of Oil and Gas Property and Equipment				$ 250,000
Percentage of Working Interest Prior to Acquisition						75.00%
Percentage of Working Interest Subsequent to Acquisition		100.00%
Revenue of Acquiree since Acquisition Date, Actual						$ 13,100
Earnings (Loss) of Acquiree since Acquisition Date, Actual						$ 11,000
Deferred purchase payment due to EFM [Member]
Business Acquisition [Line Items]
Debt Instrument, Unamortized Discount		$ 2,600
Long-term Debt, Gross		$ 147,445

Schedule of Consideration Paid

Schedule of Consideration Paid for Transactions of Assets Acquired and Liabilities Assumed (Table) (Details) $ in Thousands	Oct. 24, 2014USD ($)
Acquisitions - Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract]
Business Combination, Current Assets	$ 485
Business Combination, Oil and Gas Properties, Net	244,124
Business Combination, Total Assets	244,609
Business Combination, Liabilities	423
Business Combination, Net	$ 244,186

Acquisitions (Schedule of Resul

Acquisitions (Schedule of Results of Operations) (Table) (Details) - USD ($) $ / shares in Units, shares in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Acquisitions - Results of Operations [Abstract]
Business Acquisition, Pro Forma Revenue	$ 761,199,000	$ 575,721,000
Business Acquisition, Pro Forma Net Income (Loss)	$ 264,714,000	$ 36,356,000
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 5.83	$ 0.89
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 5.73	$ 0.88
Weighted Average Basic Shares Outstanding, Pro Forma	45,372	40,781
Pro Forma Weighted Average Shares Outstanding, Diluted	46,194	41,355

Property And Equipment, Net (Na

Property And Equipment, Net (Narrative) (Details) $ in Thousands	3 Months Ended			9 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbls	Sep. 30, 2015USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2015USD ($)$ / bbls	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Mar. 31, 2016$ / bbls
Property, Plant and Equipment [Line Items]
Unproved properties, not being amortized	$ 335,452				$ 335,452	$ 535,197
Capitalized costs of unproved properties					33,600	258,400	$ 43,500
After-tax impairment of oil and gas properties	273,100	$ 522,700			795,800
Impairment of oil and gas properties	$ 411,600	$ 812,800		$ 0	1,224,367	0	0
Proceeds from sale of property					8,047	12,576	$ 238,470
Sale price of oil and gas property and equipment			$ 218,000
Net proceeds from sale of properties			$ 191,800
Percent of total proved reserves that were sold			40.00%				40.00%
Loss on sale of oil and gas properties			$ (45,377)		0	0	$ (45,377)
Payments to Acquire Oil and Gas Property					$ 1,817	$ 92,961	$ 0
Estimated Price to Calculated Forecasted Ceiling Test Impairment | $ / bbls	50				50			46

Property And Equipment, Net (Sc

Property And Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Proved properties, net	$ 3,976,511	$ 3,174,268
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities	2,607,360	1,087,541
Proved properties, net	1,369,151	2,086,727
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	280,263	401,954
Exploratory wells in progress	9,432	71,402
Capitalized interest	45,757	61,841
Total unproved properties, not being amortized	335,452	535,197
Accumulated depreciation	(10,419)	(8,688)
Property, Plant and Equipment, Other, Net	12,258	7,329
Other property and equipment, net	22,677	16,017
Total property and equipment, net	$ 1,716,861	$ 2,629,253

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Feb. 28, 2005
Income Taxes [Line Items]
Deferred Tax Assets, Valuation Allowance	$ 324,681	$ 187,600	$ 1,095
Deferred Tax Assets, Net	$ 0
U.S. federal statutory corporate pretax rate	35.00%
Ownership percentage change	5.00%
Change in beneficial ownership, percentage	50.00%
Annual limitation on net operating loss carryforwards				$ 12,600
Pre-change in net operating loss	$ 9,800
Stock-based compensation deductions not reflected in deferred tax assets	44,700
Recognized deferred tax assets associated with stock based compensation tax deductions	15,700
United States Of America [Member]
Income Taxes [Line Items]
Operating loss carry forwards subject to expiration	$ 366,800

Income Taxes (Schedule Of Compo

Income Taxes (Schedule Of Components Of Income Tax (Expense) Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current income tax (expense) benefit
U.S. Federal	$ 0	$ 0	$ 411
State	0	0	(141)
Total current income tax benefit	0	0	270
Deferred income tax (expense) benefit
U.S. Federal	131,502	(122,342)	(12,404)
State	9,373	(5,585)	(769)
Total deferred income tax (expense) benefit	140,875	(127,927)	(13,173)
Total income tax (expense) benefit from continuing operations	$ 140,875	$ (127,927)	$ (12,903)

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income (loss) from continuing operations before income taxes	$ (1,298,760)	$ 350,210	$ 34,761
Income tax (expense) benefit at the statutory rate	(454,566)	122,574	12,166
State income tax (expense) benefit, net of U.S. Federal income taxes and increase in valuation allowance	9,373	(5,585)	(859)
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	1,671	0	0
Deferred tax asset valuation allowance	(323,586)	0	0
Other	(1,149)	232	122
Total income tax (expense) benefit from continuing operations	$ 140,875	$ (127,927)	$ (12,903)

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Deferred income tax assets
Net operating loss carryforward - U.S. Federal and State	$ 119,783		$ 56,876
Oil and gas properties	232,786		0
Asset retirement obligations	5,779		4,379
Stock-based compensation	4,741		7,867
Fair value of derivative instruments	4,433		70
Other	3,435		2,989
Deferred income tax assets	370,957		72,181
Deferred tax asset valuation allowance	(324,681)	$ (187,600)	(1,095)
Net deferred income tax assets	46,276		71,086
Deferred income tax liabilities
Oil and gas properties	0		(134,518)
Fair value of derivative instruments	(46,276)		(75,175)
Deferred income tax liabilities	(46,276)		(209,693)
Net deferred income tax asset (liability)	$ 0		$ (138,607)

Income Taxes (Schedule Of Net D

Income Taxes (Schedule Of Net Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Net current deferred income tax liability	$ (46,758)	$ (61,258)
Net noncurrent deferred income tax asset	46,758
Net noncurrent deferred income tax liability	0	(77,349)
Net deferred income tax asset (liability)	$ 0	$ (138,607)

Debt (Narrative) (Details)

Debt (Narrative) (Details)	Apr. 28, 2015USD ($)	May. 14, 2015USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015	Feb. 16, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)Rate	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 30, 2015USD ($)	May. 05, 2015USD ($)	Apr. 14, 2015USD ($)	Oct. 30, 2014USD ($)	Sep. 10, 2012USD ($)	Nov. 17, 2011USD ($)	Nov. 02, 2010USD ($)
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt						$ 38,100,000	$ (38,137,000)	$ 0	$ 0
Deferred Purchase Payment [Member]
Debt Instrument [Line Items]
Deferred purchase payment			$ 0				0	150,000,000
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility current borrowing base			685,000,000				685,000,000			$ 685,000,000	$ 685,000,000
Line of credit facility amount outstanding			0				0	0
Letters of credit outstanding amount			$ 560,000				$ 560,000
Ratio of total debt to EBITDA			2.67
Pre-Tax SEC PV10 Reserve Value Percentage | Rate							80.00%
Federal funds rate plus percentage			0.50%				0.50%
Adjusted LIBO rate plus percentage			1.00%				1.00%
Current ratio			3.63
Senior Secured Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current ratio			1
Senior Secured Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA			4
Bridge Loan [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity											$ 15,000,000
Quarters Ending December 31, 2015 Through December 31, 2016 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA			4.75
Quarter Ending March 31, 2017 Through December 31, 2017 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA			4.375
Quarters Ending March 31, 2018 And Thereafter [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA			4
8.625% Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount															$ 200,000,000	$ 400,000,000
Debt instrument interest rate																8.625%
Long-term Debt, Gross			$ 0				$ 0	600,000,000				$ 600,000,000
Debt Instrument, Cash Consideration for Tender Offer	$ 276,400,000
Debt Instrument, Repurchased Face Amount	264,200,000	$ 335,800,000
Redemption Premium	12,200,000	14,500,000				26,700,000
Tender Offer Consideration Rate	1,046.13
Principal amount per note		1,000
Accrued interest paid associated with tender offer	822,879
Debt Instrument, Redemption, Cash Consideration		$ 352,600,000
Debt Instrument, Redemption Price, Percentage		104.313%
Debt Instrument, Redemption Price per Note		$ 1,043.13
Accrued interest paid associated with redemption of debt		$ 2,300,000
Write off of Deferred Debt Issuance Cost and Unamortized Discount						$ 11,400,000
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount														$ 300,000,000
Debt instrument interest rate			7.50%				7.50%
Long-term Debt, Gross			$ 600,000,000				$ 600,000,000	600,000,000					$ 300,000,000
Senior Notes Issuance Price Percentage of Principal Amount in Private Placement													100.50%
Change of control repurchase price percentage			101.00%				101.00%
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			103.75%				103.75%
7.50% Senior Notes [Member] | Prior to September 15, 2015 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount			100.00%				100.00%
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 650,000,000
Debt instrument interest rate	6.25%
Long-term Debt, Gross			$ 650,000,000				$ 650,000,000	0
Proceeds from Issuance of Debt	$ 640,300,000
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
Eagle Ford Shale Transaction [Member]
Debt Instrument [Line Items]
Total Agreed Upon Purchase Price of Oil and Gas Property and Equipment					$ 250,000,000

Debt (Schedule Of Debt) (Detail

Debt (Schedule Of Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Apr. 14, 2015	Dec. 31, 2014	Oct. 30, 2014
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 1,255,676		$ 1,351,346
Deferred Purchase Payment [Member]
Debt Instrument [Line Items]
Deferred purchase payment	0		150,000
Unamortized discount	0		(1,100)
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility amount outstanding	0		0
8.625% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0	$ 600,000	600,000
Unamortized discount	0		(3,444)
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	600,000		600,000	$ 300,000
Debt Instrument, Unamortized Premium	1,251		1,465
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	650,000		0
Other Long Term Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,425		$ 4,425

Debt Interest and Commitment Fe

Debt Interest and Commitment Fee Rates (Details)	12 Months Ended
	Dec. 31, 2015
Less than 25 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	0.50%
Margin for eurodollar loans	1.50%
Debt Instrument, Unused Borrowing Capacity, Fee	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	0.75%
Margin for eurodollar loans	1.75%
Debt Instrument, Unused Borrowing Capacity, Fee	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	1.00%
Margin for eurodollar loans	2.00%
Debt Instrument, Unused Borrowing Capacity, Fee	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	1.25%
Margin for eurodollar loans	2.25%
Debt Instrument, Unused Borrowing Capacity, Fee	0.50%
Greater than or equal to 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.50%
Margin for eurodollar loans	2.50%
Debt Instrument, Unused Borrowing Capacity, Fee	0.50%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 12,512	$ 7,356
Liabilities incurred	3,227	6,284
Liabilities settled	(1,966)	(1,784)
Accretion expense	1,112	710
Revisions of previous estimates (1)	1,626	(477)
Asset retirement obligations at end of period	16,511	12,512
Current portion of asset retirement obligations included in “Other current liabilities”	(328)	(325)
Long-term asset retirement obligations	16,183	12,187
Eagle Ford Shale Transaction [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred	$ 0	$ 423

Commitments and Contingencies61

Commitments and Contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Rent expense	$ 2,200	$ 1,900	$ 1,900
Operating leases
2,016	4,055
2,017	4,185
2,018	4,248
2,019	4,357
2,020	4,450
2021 and Thereafter	6,304
Total	27,599
Capital leases
2,016	1,733
2,017	1,733
2,018	1,700
2,019	1,677
2,020	978
2021 and Thereafter	0
Total	7,821
Drilling rig contracts
2,016	24,261
2,017	20,513
2,018	3,957
2,019	0
2,020	0
2021 and Thereafter	0
Total	48,731
Pipeline volume commitments
2,016	8,596
2,017	7,474
2,018	7,474
2,019	6,141
2,020	3,651
2021 and Thereafter	5,431
Total	38,767
Total
2,016	38,645
2,017	33,905
2,018	17,379
2,019	12,175
2,020	9,079
2021 and Thereafter	11,735
Total	$ 122,918

Shareholders' Equity And Stoc62

Shareholders' Equity And Stock Incentive Plan (Narrative) (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 21, 2015	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested				$ 32,000,000	$ 37,300,000	$ 16,000,000
Common stock offerings, net of offering costs, shares	6,300,000		5,200,000
Sale of Stock, Price Per Share			$ 44.75				$ 37.80
Proceeds from Issuance or Sale of Equity	$ 238,842,000		$ 231,316,000
Class of Warrant or Right, Outstanding					118,200
Issuance of warrants to purchase of common stock					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	3,861,389			3,861,389
Shares Granted, Options				0	0	0
Compensation Not yet Recognized, Stock Options	$ 0			$ 0
Total intrinsic value, Options Exercised				100,000	$ 1,300,000	$ 4,400,000
Proceeds from stock options exercised				46,000	437,000	1,253,000
Tax Benefit Realized from Exercises				$ 100,000	$ 400,000	$ 1,500,000
Grants in Period, Performance Shares				401,421	576,812	932,763
Grant Date Fair Value, Performance Shares	$ 44.22			$ 44.22	$ 34.55	$ 28.03		$ 26.95
Stock Incentive Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum issuance of grant awards under Incentive Plan	10,822,500			10,822,500
Restricted Stock Award And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost not yet recognized	$ 20,800,000			$ 20,800,000
Compensation cost not yet recognized, period for recognition				1 year 8 months 12 days
Cash Settled Stock Appreciation Rights Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
SARs, Granted				0	0	282,296
Liability for cash stock appreciation rights				$ 7,000,000	$ 14,800,000
Liability for cash stock appreciation rights, classified as other accrued liabilities					13,900,000
Liability for cash stock appreciation rights remainder, classified as other long term liabilities					900,000
Cash paid at exercises, Stock Appreciation Rights				1,500,000	$ 7,800,000	$ 3,900,000
Compensation cost not yet recognized	100,000			$ 100,000
Compensation cost not yet recognized, period for recognition				4 months 24 days
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost not yet recognized	$ 4,200,000			$ 4,200,000
Compensation cost not yet recognized, period for recognition				1 year 10 months 24 days
Grants in Period, Performance Shares				56,517	56,342
Grant Date Fair Value, Performance Shares	$ 66.83			$ 66.83	$ 68.15	$ 0
Vesting period, in years				3 years
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] | 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%

Shareholders' Equity And Stoc63

Shareholders' Equity And Stock Incentive Plan (Summary Of Restricted Stock Award And Unit Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock Awards and Units
Unvested Shares/Units, Beginning of Period	1,335,682	1,444,867	1,146,274
Granted Shares/Units	401,421	576,812	932,763
Vested Shares/Units	(671,417)	(647,306)	(557,136)
Forfeited Shares/Units	(23,689)	(38,691)	(77,034)
Unvested Shares/Units, End of Period	1,041,997	1,335,682	1,444,867
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 34.55	$ 28.03	$ 26.95
Granted, Grant-date Fair Value (USD per share)	51.45	48.64	28.16
Vested, Grant-date Fair Value (USD per share)	32.96	32.64	25.98
Forfeited, Grant-date Fair Value (USD per share)	43.36	32.89	26.03
Grant-date Fair Value, End of Period (USD per share)	$ 44.22	$ 34.55	$ 28.03

Shareholders' Equity And Stoc64

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
SARs, Outstanding, beginning of period	765,198	1,086,231	1,035,823
SARs, Granted	0	0	282,296
SARs, Exercised	(64,745)	(321,033)	(207,184)
SARs, Forfeitures	0	0	(24,704)
SARs, Outstanding, end of period	700,453	765,198	1,086,231
SARs, Exercisable, End of Period	626,661	587,481	681,867
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	$ 22.49	$ 24.78	$ 22.69
Weighted Average Exercise Prices, Granted	0	0	28.68
Weighted Average Exercise Prices, Exercised	29.40	30.24	19.30
Weighted Average Exercise Prices, Forfeitures	0	0	27.77
Weighted Average Exercise Prices, Outstanding, End of Period	$ 21.86	$ 22.49	$ 24.78
Cash paid at exercises, Stock Appreciation Rights	$ 1.5	$ 7.8	$ 3.9
Weighted Average Exercise Prices, Exercisable, End of Period	$ 21.05	$ 20.78	$ 22.55
Weighted Average Remaining Life, Outstanding, End of Period	1 year 1 month 6 days
Weighted Average Remaining Life, Exercisable, End of Period	1 year 1 month 6 days
Aggregate Intrinsic Value, Outstanding, End of Period	$ 5.1
Aggregate Intrinsic Value, Exercisable, End of Period	$ 5

Shareholders' Equity And Stoc65

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, 2013$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock price on the date of grant (USD per share)	$ 13.36
Volatility factor	44.54%
Dividend yield	0.00%
Risk-free interest rate	1.00%
Expected Term	3 years 6 months

Shareholders' Equity And Stoc66

Shareholders' Equity And Stock Incentive Plan Summary of Unvested Performance Share Award Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Performance Share Awards
Unvested Shares/Units, Beginning of Period	1,335,682	1,444,867	1,146,274
Granted Shares/Units	401,421	576,812	932,763
Vested Shares/Units	(671,417)	(647,306)	(557,136)
Forfeited Shares/Units	(23,689)	(38,691)	(77,034)
Unvested Shares/Units, End of Period	1,041,997	1,335,682	1,444,867
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 34.55	$ 28.03	$ 26.95
Vested, Grant-date Fair Value (USD per share)	32.96	32.64	25.98
Granted, Grant-date Fair Value (USD per share)	51.45	48.64	28.16
Forfeited, Grant-date Fair Value (USD per share)	43.36	32.89	26.03
Grant-date Fair Value, End of Period (USD per share)	$ 44.22	$ 34.55	$ 28.03
Performance Shares [Member]
Performance Share Awards
Unvested Shares/Units, Beginning of Period	56,342	0
Granted Shares/Units	56,517	56,342
Vested Shares/Units	0	0
Forfeited Shares/Units	0	0
Unvested Shares/Units, End of Period	112,859	56,342	0
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 68.15	$ 0
Vested, Grant-date Fair Value (USD per share)	0	0
Granted, Grant-date Fair Value (USD per share)	65.51	68.15
Forfeited, Grant-date Fair Value (USD per share)	0	0
Grant-date Fair Value, End of Period (USD per share)	$ 66.83	$ 68.15	$ 0

Shareholders' Equity and Stoc67

Shareholders' Equity and Stock Incentive Plan (Summary of Performance Share Awards Fair Value Assumptions) (Details) - Performance Shares [Member]	12 Months Ended
	Dec. 31, 2015$ / sharesRate	Dec. 31, 2014$ / sharesRate
Number of simulations	500,000	500,000
Stock price on the date of grant | $ / shares	$ 53.58	$ 53.96
Volatility factor	45.30%	49.90%
Dividend yield	0.00%	0.00%
Risk-free interest rate	0.87%	0.90%
Expected Term	2 years 10 months 20 days	2 years 11 months 20 days

Shareholders' Equity And Stoc68

Shareholders' Equity And Stock Incentive Plan (Summary Of Stock Options Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Options
Shares, Outstanding, beginning of period	2,433	36,353	242,854
Shares Granted, Options	0	0	0
Shares, Exercised	(2,433)	(33,086)	(206,501)
Shares, Forfeited	0	0	0
Shares, Expired		(834)
Shares, Outstanding, end of period	0	2,433	36,353
Shares, Exercisable, end of period	0	2,433	36,353
Weighted Average Exercise Prices
Weighted-Average Exercise Prices, Outstanding, beginning period (USD per share)	$ 19.02	$ 13.91	$ 7.24
Weighted-Average Exercise Prices, Granted (USD per share)	0	0	0
Weighted-Average Exercise Prices, Exercised (USD per share)	19.02	13.20	6.07
Weighted-Average Exercise Prices, Forfeited (USD per share)	0	0	0
Weighted Average Exercise Prices, Expired (USD per share)		27.25
Weighted-Average Exercise Prices, Outstanding, end of period (USD per share)	0	19.02	13.91
Weighted-Average Exercise Prices, Exercisable, end of period (USD per share)	$ 0	$ 19.02	$ 13.91
Additional Disclosures
Weighted-Average Remaining Life, Outstanding, end of period	0 years	6 months 7 days	1 year 25 days
Weighted - Average Remaining Life, Exercisable, end of period	0 years	6 months 7 days	1 year 25 days
Aggregate Intrinsic Value, Outstanding, Exercised	$ 100	$ 1,300	$ 4,400
Aggregate Intrinsic Value, Outstanding, end of period	0	100	1,100
Aggregate Intrinsic Value, Exercisable, end of period	0	100	1,100
Cash Received from Exercises	46	437	1,253
Tax Benefit Realized from Exercises	$ 100	$ 400	$ 1,500

Shareholders' Equity And Stoc69

Shareholders' Equity And Stock Incentive Plan (Stock-Based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	$ 19,303	$ 32,977	$ 36,300
Less: amounts capitalized	(4,574)	(7,099)	(6,927)
Total stock-based compensation expense	14,729	25,878	29,373
Income Tax Benefit	5,155	9,059	10,281
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	23,668	29,597	18,997
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	(6,326)	1,985	17,303
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	$ 1,961	$ 1,395	$ 0

Earnings Per Share (Narrative)

Earnings Per Share (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015shares
Restricted Stock Awards And Units [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	629,335

Earnings Per Share (Schedule of

Earnings Per Share (Schedule of Earnings per Share Reconciliation Table) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share Reconciliation [Abstract]
Income (Loss) From Continuing Operations									$ (1,157,885)	$ 222,283	$ 21,858
Weighted Average Number of Shares Outstanding, Basic									51,457	45,372	40,781
Effect of dilutive instruments
Incremental Common Shares Attributable to Dilutive Effect of Nonvested Shares with Forfeitable Dividends									0	684	492
Stock options									0	13	47
Warrants									0	69	35
Weighted Average Number of Shares Outstanding, Diluted									51,457	46,194	41,355
Income (Loss) from Continuing Operations Per Common Share
Income (loss) from continuing operations, Per Basic Share	$ (6.73)	$ (13.75)	$ (0.92)	$ (0.46)	$ 2.85	$ 1.83	$ 0.07	$ 0.15	$ (22.50)	$ 4.90	$ 0.54
Income (Loss) from Continuing Operations, Per Diluted Share	$ (6.73)	$ (13.75)	$ (0.92)	$ (0.46)	$ 2.80	$ 1.80	$ 0.07	$ 0.14	$ (22.50)	$ 4.81	$ 0.53

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Due from Related Parties, Current	$ 2.4	$ 1.9

Derivative Instruments (Schedul

Derivative Instruments (Schedule Of U.S. Crude Oil Derivative Positions) (Details) - Crude Oil [Member]	Dec. 31, 2015bbl / d$ / bbls
Fixed Price Swaps [Member] | Weighted Average Floor Price of $60.03 [Member] | 2016 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	9,315
Weighted Average Floor Price ($/Bbl)	60.03
Costless Collars [Member] | Weighted Average Floor Price of $50.96, Weighted Average Ceiling Price of $74.73 [Member] | 2016 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	5,490
Weighted Average Floor Price ($/Bbl)	50.96
Weighted Average Ceiling Price ($/Bbl)	74.73
Sold Call Options [Member] | Weighted Average Ceiling Price of $60.00 [Member] | 2018 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	2,488
Weighted Average Ceiling Price ($/Bbl)	60
Sold Call Options [Member] | Weighted Average Ceiling Price of $75.00 [Member] | 2018 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	900
Weighted Average Ceiling Price ($/Bbl)	75
Sold Call Options [Member] | Weighted Average Ceiling Price of $62.50 [Member] | 2019 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	2,975
Weighted Average Ceiling Price ($/Bbl)	62.50
Sold Call Options [Member] | Weighted Average Ceiling Price of $77.50 [Member] | 2019 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	900
Weighted Average Ceiling Price ($/Bbl)	77.50
Sold Call Options [Member] | Weighted Average Ceiling Price of $65.00 [Member] | 2020 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	3,675
Weighted Average Ceiling Price ($/Bbl)	65
Sold Call Options [Member] | Weighted Average Ceiling Price of $80.00 [Member] | 2020 [Member]
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	900
Weighted Average Ceiling Price ($/Bbl)	80

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) $ in Thousands	1 Months Ended	9 Months Ended	12 Months Ended
	Feb. 11, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)bbl / d$ / bbls	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Derivative [Line Items]
Value of Offsetting Derivative Transactions | $	$ 166,400		$ 47,500
Derivative, Gain Recognized on Offsetting Derivative Transaction | $		$ 118,900
(Gain) loss on derivatives, net | $	$ (8,400)		(99,261)	$ (201,907)	$ 18,417
Derivative Asset | $			119,600	$ 214,800
Value of Offsetting Derivative Transactions Current Asset | $			$ 44,800
Crude Oil [Member] | Costless Collars [Member] | 2017 [Member]
Derivative [Line Items]
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			60
Crude Oil [Member] | Sold Call Options [Member]
Derivative [Line Items]
Net premiums | $			$ 5,000
Weighted Average Ceiling Price of $60.00 [Member] | Crude Oil [Member] | Sold Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			2,488
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			60
Weighted Average Ceiling Price of $62.50 [Member] | Crude Oil [Member] | Sold Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			2,975
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			62.50
Weighted Average Ceiling Price of $65.00 [Member] | Crude Oil [Member] | Sold Call Options [Member] | 2020 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			3,675
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			65
Weighted Average Floor Price of $60.03 [Member] | Crude Oil [Member] | Fixed Price Swaps [Member] | 2016 [Member]
Derivative [Line Items]
Weighted Average Floor Price ($/Bbl) | $ / bbls			60.03
Volumes (in Bbls/d)			9,315
Weighted Average Ceiling Price of $75.00 [Member] | Crude Oil [Member] | Sold Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			900
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			75
Weighted Average Ceiling Price of $77.50 [Member] | Crude Oil [Member] | Sold Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			900
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			77.50
Weighted Average Ceiling Price of $80.00 [Member] | Crude Oil [Member] | Sold Call Options [Member] | 2020 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			900
Weighted Average Ceiling Price ($/Bbl) | $ / bbls			80
Buy [Member] | Crude Oil [Member] | Sold Call Options [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			900
Sell [Member] | Crude Oil [Member] | Sold Call Options [Member]
Derivative [Line Items]
Volumes (in Bbls/d)			900

Derivative Instruments (Sched75

Derivative Instruments (Schedule of Derivative Instruments by Counterparty) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Concentration Risk, Percentage	100.00%	100.00%
Derivative Credit Risk [Member] | Societe Generale [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	37.00%	26.00%
Derivative Credit Risk [Member] | Union Bank [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	5.00%	4.00%
Derivative Credit Risk [Member] | Customer One [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	1.00%	0.00%
Derivative Credit Risk [Member] | Regions [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	9.00%	8.00%
Derivative Credit Risk [Member] | Credit Suisse [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%	24.00%
Derivative Credit Risk [Member] | Wells Fargo [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	35.00%	37.00%
Derivative Credit Risk [Member] | Citibank [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%	0.00%
Derivative Credit Risk [Member] | Royal Bank of Canada [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%	1.00%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset	$ 119,600,000	$ 214,800,000
Derivative, Fair Value, Net [Abstract]
Fair value amount of transfers in or out of Levels 1 or 2	0	0
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Derivative, Fair Value, Net [Abstract]
Derivative asset (liabilities), gross amount recognized	119,550,000	214,585,000
Derivative liabilities (assets), gross amounts offset in the consolidated balance sheets	0	0
Derivative Asset (Liability), Net	119,550,000	214,585,000
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Current Assets [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	159,447,000	183,625,000
Derivative Asset, Fair Value, Gross Liability	28,347,000	12,524,000
Derivative Asset	131,100,000	171,101,000
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Assets [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	10,780,000	44,725,000
Derivative Asset, Fair Value, Gross Liability	9,665,000	1,041,000
Derivative Asset	1,115,000	43,684,000
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Derivative Liabilities Current [Member]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	(28,364,000)	(12,707,000)
Derivative Liability, Fair Value, Gross Asset	28,347,000	12,524,000
Derivative Liability	(17,000)	(183,000)
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Liabilities [Member]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	(22,313,000)	(1,058,000)
Derivative Liability, Fair Value, Gross Asset	9,665,000	1,041,000
Derivative Liability	$ (12,648,000)	$ (17,000)

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Apr. 14, 2015	Dec. 31, 2014	Oct. 30, 2014
8.625% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	$ 0	$ 600,000	$ 600,000
7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	600,000		600,000	$ 300,000
6.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	650,000		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] | Deferred Purchase Payment [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	0		148,900
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 8.625% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	0		596,555
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	601,251		601,466
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	650,000		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] | Deferred Purchase Payment [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	0		148,558
Estimate of Fair Value Measurement [Member] | 8.625% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	0		597,000
Estimate of Fair Value Measurement [Member] | 7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	528,000		573,000
Estimate of Fair Value Measurement [Member] | 6.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	533,000		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	$ 4,182		$ 4,071

Condensed Consolidating Finan78

Condensed Consolidating Financial Information (Narrative) (Details)	Dec. 31, 2015
Condensed Consolidating Financial Information [Abstract]
Voting interest of the subsidiary owned by the registrant	100.00%

Condensed Consolidating Finan79

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Total current assets	$ 232,182	$ 278,621
Total property and equipment, net	1,716,861	2,629,253
Investment in subsidiaries	0	0
Other assets	77,862	73,602
Total Assets	2,026,905	2,981,476
Current Liabilities	285,484	424,304
Long-term liabilities	1,297,367	1,453,731
Total shareholders’ equity	444,054	1,103,441	$ 841,604	$ 585,016
Total Liabilities and Shareholders’ Equity	2,026,905	2,981,476
Parent Company [Member]
Total Assets	1,901,035	2,755,005
Total Liabilities and Shareholders’ Equity	1,901,035	2,755,005
Combined Guarantor Subsidiaries [Member]
Total Assets	1,723,997	2,807,080
Total Liabilities and Shareholders’ Equity	1,723,997	2,807,080
Combined Non-Guarantor Subsidiaries [Member]
Total Assets	3,059	40,050
Total Liabilities and Shareholders’ Equity	3,059	40,050
Consolidation, Eliminations [Member]
Total Assets	(1,601,186)	(2,620,659)
Total Liabilities and Shareholders’ Equity	(1,601,186)	(2,620,659)
Reportable Legal Entities [Member] | Parent Company [Member]
Total current assets	2,578,034	2,380,445
Total property and equipment, net	44,499	613
Investment in subsidiaries	(815,836)	233,173
Other assets	94,338	140,774
Current Liabilities	161,792	296,686
Long-term liabilities	1,279,859	1,364,793
Total shareholders’ equity	459,384	1,093,526
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Total current assets	52,067	245,051
Total property and equipment, net	1,671,774	2,562,029
Investment in subsidiaries	0	0
Other assets	156	0
Current Liabilities	2,521,572	2,434,649
Long-term liabilities	18,261	139,353
Total shareholders’ equity	(815,836)	233,078
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Total current assets	0	111
Total property and equipment, net	3,059	39,939
Investment in subsidiaries	0	0
Other assets	0	0
Current Liabilities	3,059	39,955
Long-term liabilities	0	0
Total shareholders’ equity	0	95
Consolidation, Eliminations [Member]
Total current assets	(2,397,919)	(2,346,986)
Total property and equipment, net	(2,471)	26,672
Investment in subsidiaries	815,836	(233,173)
Other assets	(16,632)	(67,172)
Current Liabilities	(2,400,939)	(2,346,986)
Long-term liabilities	(753)	(50,415)
Total shareholders’ equity	$ 800,506	$ (223,258)

Condensed Consolidating Finan80

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended									9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Total revenues	$ 99,422	$ 106,237	$ 123,494	$ 100,050	$ 163,275	$ 196,225	$ 193,475	$ 157,212				$ 429,203	$ 710,187	$ 520,182
Total costs and expenses												1,727,963	359,977	485,421
Income (loss) from continuing operations before income taxes												(1,298,760)	350,210	34,761
Loss on sale of oil and gas properties									$ 45,377			0	0	45,377
Income tax benefit												140,875	(127,927)	(12,903)
Equity in loss of subsidiaries												0	0	0
Income (Loss) From Continuing Operations												(1,157,885)	222,283	21,858
Income from discontinued operations, net of income taxes												2,731	4,060	21,825
Net income from discontinued operations, net of income taxes												2,731	4,060	21,825
Net Income (Loss)	$ (380,165)	$ (707,647)	$ (46,132)	$ (21,210)	$ 134,259	$ 83,789	$ 2,319	$ 5,976				(1,155,154)	226,343	43,683
Parent Company [Member]
Total revenues														6,490
Total costs and expenses														134,874
Income tax benefit														44,934
Equity in loss of subsidiaries														106,538
Income (Loss) From Continuing Operations												(1,132,641)	223,859	23,088
Net income from discontinued operations, net of income taxes														21,825
Net Income (Loss)												(1,129,910)	227,919	44,913
Combined Guarantor Subsidiaries [Member]
Total revenues														513,692
Total costs and expenses														349,782
Income tax benefit														(57,369)
Equity in loss of subsidiaries														0
Income (Loss) From Continuing Operations												(1,049,010)	171,456	106,541
Net income from discontinued operations, net of income taxes														0
Net Income (Loss)												(1,049,010)	171,456	106,541
Combined Non-Guarantor Subsidiaries [Member]
Total revenues														0
Total costs and expenses														3
Income tax benefit														0
Equity in loss of subsidiaries														0
Income (Loss) From Continuing Operations												0	98	(3)
Net income from discontinued operations, net of income taxes														0
Net Income (Loss)												0	98	(3)
Consolidation, Eliminations [Member]
Total revenues														0
Total costs and expenses														762
Income tax benefit														(468)
Equity in loss of subsidiaries														(106,538)
Income (Loss) From Continuing Operations												1,023,766	(173,130)	(107,768)
Net income from discontinued operations, net of income taxes														0
Net Income (Loss)												1,023,766	(173,130)	(107,768)
Reportable Legal Entities [Member] | Parent Company [Member]
Total revenues										$ 1,708	$ 3,938
Costs and Expenses										95,464			(76,531)
Income (loss) from continuing operations before income taxes												(93,756)	80,469	(128,384)
Income tax benefit										10,125	(28,164)
Equity in loss of subsidiaries										1,049,010			(171,554)
Income from discontinued operations, net of income taxes										2,731	4,060
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Total revenues										427,495	706,121
Costs and Expenses										1,603,515	442,343
Income (loss) from continuing operations before income taxes												(1,176,020)	263,778	163,910
Income tax benefit										127,010			(92,322)
Equity in loss of subsidiaries										0			0
Income from discontinued operations, net of income taxes										0	0
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Total revenues										0	128
Costs and Expenses										0	30
Income (loss) from continuing operations before income taxes												0	98	(3)
Income tax benefit										0	0
Equity in loss of subsidiaries										0			0
Income from discontinued operations, net of income taxes										0			0
Consolidation, Eliminations [Member]
Total revenues										0	0
Costs and Expenses										28,984	$ (5,865)
Income (loss) from continuing operations before income taxes												$ (28,984)	5,865	$ (762)
Income tax benefit										3,740			(7,441)
Equity in loss of subsidiaries										(1,049,010)			171,554
Income from discontinued operations, net of income taxes										$ 0			$ 0

Condensed Consolidating Finan81

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net cash provided by operating activities from continuing operations	$ 378,735	$ 502,275	$ 367,474
Net cash used in investing activities from continuing operations	(673,376)	(940,676)	(509,885)
Net cash provided by financing activities from continuing operations	330,767	300,290	120,326
Net cash used in discontinued operations	(4,046)	(8,490)	126,910
Net increase in cash and cash equivalents	32,080	(146,601)	104,825
Cash and cash equivalents, beginning of year	10,838	157,439	52,614
Cash and cash equivalents, end of year	42,918	10,838	157,439
Cash and cash equivalents	42,918	10,838	157,439	$ 52,614
Parent Company [Member]
Net increase in cash and cash equivalents	32,080	(146,601)	105,545
Cash and cash equivalents, beginning of year	10,838	157,439
Cash and cash equivalents, end of year	42,918	10,838	157,439
Combined Guarantor Subsidiaries [Member]
Net increase in cash and cash equivalents	0	0	(201)
Cash and cash equivalents, beginning of year	0	0
Cash and cash equivalents, end of year	0	0	0
Combined Non-Guarantor Subsidiaries [Member]
Net increase in cash and cash equivalents	0	0	(519)
Cash and cash equivalents, beginning of year	0	0
Cash and cash equivalents, end of year	0	0	0
Consolidation, Eliminations [Member]
Net cash provided by operating activities from continuing operations			0
Net cash used in investing activities from continuing operations			92,204
Net cash provided by financing activities from continuing operations			(92,204)
Net cash used in discontinued operations			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
Reportable Legal Entities [Member] | Parent Company [Member]
Net cash provided by operating activities from continuing operations	2,655	(132,683)	(55,888)
Net cash used in investing activities from continuing operations	(447,296)	(305,718)	(86,322)
Net cash provided by financing activities from continuing operations	480,767	300,290	120,326
Net cash used in discontinued operations	(4,046)	(8,490)	127,429
Cash and cash equivalents, beginning of year			51,894
Cash and cash equivalents		10,838	157,439
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Net cash provided by operating activities from continuing operations	376,080	634,970	423,366
Net cash used in investing activities from continuing operations	(674,758)	(906,509)	(513,710)
Net cash provided by financing activities from continuing operations	298,678	271,539	90,143
Net cash used in discontinued operations	0	0	0
Cash and cash equivalents, beginning of year			201
Cash and cash equivalents		0	0
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Net cash provided by operating activities from continuing operations	0	(12)	(4)
Net cash used in investing activities from continuing operations	0	(37,609)	(2,057)
Net cash provided by financing activities from continuing operations	0	37,621	2,061
Net cash used in discontinued operations	0	0	(519)
Cash and cash equivalents, beginning of year			519
Cash and cash equivalents		0	0
Consolidation, Eliminations [Member]
Net cash provided by operating activities from continuing operations	0	0
Net cash used in investing activities from continuing operations	448,678	309,160
Net cash provided by financing activities from continuing operations	(448,678)	(309,160)
Net cash used in discontinued operations	$ 0	0
Cash and cash equivalents		$ 0	$ 0

Supplemental Cash Flow Inform82

Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	Oct. 24, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Line Items]
Cash paid for interest, net of amounts capitalized		$ 64,692	$ 49,379	$ 50,770
Cash paid for income taxes		0	0	505
Capital Expenditures Incurred but Not yet Paid		90,008	176,886	114,988
Other Non-Cash Investing Activities		27,415	6,789	10,698
Purchase price adjustments	$ 3,200	0	3,197	0
Deferred Purchase Payment [Member]
Supplemental Cash Flow Information [Line Items]
Long-term Debt		$ 0	$ 148,900	$ 0

Subsequent Events (Unaudited)83

Subsequent Events (Unaudited) (Schedule of Crude Oil Derivative Instruments) (Details) - Subsequent Event [Member] - January through June 2017 [Member] - Crude Oil [Member] - Weighted Average Floor Price of $50.27 [Member] - Fixed Price Swaps [Member] bbl / d in Thousands	Feb. 22, 2016bbl / d$ / bbls
Derivative [Line Items]
Volumes (in Bbls/d) | bbl / d	6
Weighted Average Floor Price ($/Bbl) | $ / bbls	50.27

Subsequent Events (Unaudited)84

Subsequent Events (Unaudited) (Schedule of Natural Gas Derivative Instruments) (Details) - Subsequent Event [Member] - Natural Gas [Member] - Sold Call Options [Member] MMBTU / d in Thousands	Feb. 22, 2016MMBTU / d$ / MMBTU
Weighted Average Ceiling Price of $3.00 [Member] | 2017 [Member]
Derivative [Line Items]
Natural Gas Volumes (in MMBtu/d) | MMBTU / d	33
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3
Weighted Average Ceiling Price of $3.25 [Member] | 2018 [Member]
Derivative [Line Items]
Natural Gas Volumes (in MMBtu/d) | MMBTU / d	33
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
Weighted Average Ceiling Price of $3.25 [Member] | 2019 [Member]
Derivative [Line Items]
Natural Gas Volumes (in MMBtu/d) | MMBTU / d	33
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
Weighted Average Ceiling Price of $3.50 [Member] | 2020 [Member]
Derivative [Line Items]
Natural Gas Volumes (in MMBtu/d) | MMBTU / d	33
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.50

Subsequent Events (Unaudited)85

Subsequent Events (Unaudited) (Narrative) (Details) - Subsequent Event	Feb. 22, 2016$ / bbls$ / MMBTU
Natural Gas [Member] | Sold Call Options [Member] | Weighted Average Ceiling Price of $3.00 [Member] | 2017 [Member]
Subsequent Event [Line Items]
Weighted Average Ceiling Price ($/MMBtu)	3
Natural Gas [Member] | Sold Call Options [Member] | Weighted Average Ceiling Price of $3.25 [Member] | 2018 [Member]
Subsequent Event [Line Items]
Weighted Average Ceiling Price ($/MMBtu)	3.25
Natural Gas [Member] | Sold Call Options [Member] | Weighted Average Ceiling Price of $3.25 [Member] | 2019 [Member]
Subsequent Event [Line Items]
Weighted Average Ceiling Price ($/MMBtu)	3.25
Natural Gas [Member] | Sold Call Options [Member] | Weighted Average Ceiling Price of $3.50 [Member] | 2020 [Member]
Subsequent Event [Line Items]
Weighted Average Ceiling Price ($/MMBtu)	3.50
Crude Oil [Member] | Fixed Price Swaps [Member] | Weighted Average Floor Price of $50.27 [Member] | January through June 2017 [Member]
Subsequent Event [Line Items]
Weighted Average Floor Price ($/Bbl) | $ / bbls	50.27

Supplemental Disclosures Abou86

Supplemental Disclosures About Oil And Gas Producing Activities (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015$ / bbls$ / MMcf	Dec. 31, 2014$ / bbls$ / MMcf	Dec. 31, 2013$ / bbls$ / MMcf
Crude Oil and NGL (Bbl) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates	47.24	92.24	99.44
Natural Gas Liquids (Bbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates	12	27.80	25.60
Natural Gas, Per Thousand Cubic Feet [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates | $ / MMcf	1.87	3.24	2.97

Supplemental Disclosures Abou87

Supplemental Disclosures About Oil and Gas Producing Activities (Narrative 2) (Details) MMcf in Thousands, MBbls in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MBblsMMcf	Dec. 31, 2014USD ($)MMcf	Dec. 31, 2013USD ($)MMcf
Supplemental Oil And Gas Reserve Information [Line Items]
Capitalized interest | $	$ 32.1	$ 34.5	$ 29.9
Asset retirement obligation additions | $	$ 4.9	$ 4.5	$ 3.7
Reserves discount factor	10.00%
Natural Gas (Mcf) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates	11,808	18,913	29,819
Price Reserve Revisions [Member] | Crude Oil and NGL (Bbl) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates | MBbls	(11,194)
Price Reserve Revisions [Member] | Natural Gas (Mcf) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates	39,715
Performance Reserve Revisions [Member] | Crude Oil and NGL (Bbl) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates | MBbls	4,904
Performance Reserve Revisions [Member] | Natural Gas (Mcf) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates	27,908
Eagle Ford Shale [Member] | Crude Oil and NGL (Bbl) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
PercentageOfReserveAdditions	92.00%
Eagle Ford Shale [Member] | Natural Gas (Mcf) [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
PercentageOfReserveAdditions	81.00%

Supplemental Disclosures Abou88

Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) - U.S. [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$ 0	$ 183,633	$ 0
Unproved property acquisition costs	63,446	215,021	254,099
Total property acquisition costs	63,446	398,654	254,099
Exploration costs	117,227	194,956	106,329
Development costs	389,396	530,268	423,871
Total costs incurred	$ 570,069	$ 1,123,878	$ 784,299

Supplemental Disclosures Abou89

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	12 Months Ended
	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf
Crude Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	100,704	62,041	44,316
Extensions and discoveries	26,358	29,793	27,295
Revisions of previous estimates	(9,059)	3,046	778
Sales of reserves in place			(6,117)
Purchases of reserves in place		12,730
Production	(8,415)	(6,906)	(4,231)
Proved developed and undeveloped reserves end of year	109,588	100,704	62,041
Proved developed reserves (volume)	42,311	35,238	18,321
Proved undeveloped reserve (volume)	67,277	65,466	43,720
Crude Oil [Member] | U.S. [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	100,704	62,041	39,075
Extensions and discoveries	26,358	29,793	27,295
Revisions of previous estimates	(9,059)	3,046	778
Sales of reserves in place			(876)
Purchases of reserves in place		12,730
Production	(8,415)	(6,906)	(4,231)
Proved developed and undeveloped reserves end of year	109,588	100,704	62,041
Proved developed reserves (volume)	42,311	35,238	18,321
Proved undeveloped reserve (volume)	67,277	65,466	43,720
Crude Oil [Member] | U.K.
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	0	0	5,241
Extensions and discoveries	0	0	0
Revisions of previous estimates	0	0	0
Sales of reserves in place			(5,241)
Purchases of reserves in place		0
Production	0	0	0
Proved developed and undeveloped reserves end of year	0	0	0
Proved developed reserves (volume)	0	0	0
Proved undeveloped reserve (volume)	0	0	0
Natural Gas Liquids (Bbls) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	13,513	8,152	5,383
Extensions and discoveries	5,292	3,681	2,992
Revisions of previous estimates	2,768	1,270	308
Sales of reserves in place			0
Purchases of reserves in place		1,335
Production	(1,352)	(925)	(531)
Proved developed and undeveloped reserves end of year	20,221	13,513	8,152
Proved developed reserves (volume)	7,933	5,294	2,779
Proved undeveloped reserve (volume)	12,288	8,219	5,373
Natural Gas Liquids (Bbls) [Member] | U.S. [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	13,513	8,152	5,383
Extensions and discoveries	5,292	3,681	2,992
Revisions of previous estimates	2,768	1,270	308
Sales of reserves in place			0
Purchases of reserves in place		1,335
Production	(1,352)	(925)	(531)
Proved developed and undeveloped reserves end of year	20,221	13,513	8,152
Proved developed reserves (volume)	7,933	5,294	2,779
Proved undeveloped reserve (volume)	12,288	8,219	5,373
Natural Gas Liquids (Bbls) [Member] | U.K.
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	0	0	0
Extensions and discoveries	0	0	0
Revisions of previous estimates	0	0	0
Sales of reserves in place			0
Purchases of reserves in place		0
Production	0	0	0
Proved developed and undeveloped reserves end of year	0	0	0
Proved developed reserves (volume)	0	0	0
Proved undeveloped reserve (volume)	0	0	0
Natural Gas (Mcf) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year | MMcf	221,017	187,957	428,336
Extensions and discoveries | MMcf	33,925	30,343	73,360
Revisions of previous estimates | MMcf	11,808	18,913	29,819
Sales of reserves in place | MMcf			(312,136)
Purchases of reserves in place | MMcf		8,681
Production | MMcf	(21,812)	(24,877)	(31,422)
Proved developed and undeveloped reserves end of year | MMcf	244,938	221,017	187,957
Proved developed reserves (volume) | MMcf	154,725	149,697	106,976
Proved undeveloped reserve (volume) | MMcf	90,213	71,320	80,981
Natural Gas (Mcf) [Member] | U.S. [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year | MMcf	221,017	187,957	423,672
Extensions and discoveries | MMcf	33,925	30,343	73,360
Revisions of previous estimates | MMcf	11,808	18,913	29,819
Sales of reserves in place | MMcf			(307,472)
Purchases of reserves in place | MMcf		8,681
Production | MMcf	(21,812)	(24,877)	(31,422)
Proved developed and undeveloped reserves end of year | MMcf	244,938	221,017	187,957
Proved developed reserves (volume) | MMcf	154,725	149,697	106,976
Proved undeveloped reserve (volume) | MMcf	90,213	71,320	80,981
Natural Gas (Mcf) [Member] | U.K.
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year | MMcf	0	0	4,664
Extensions and discoveries | MMcf	0	0	0
Revisions of previous estimates | MMcf	0	0	0
Sales of reserves in place | MMcf			(4,664)
Purchases of reserves in place | MMcf		0
Production | MMcf	0	0	0
Proved developed and undeveloped reserves end of year | MMcf	0	0	0
Proved developed reserves (volume) | MMcf	0	0	0
Proved undeveloped reserve (volume) | MMcf	0	0	0
Barrel of Oil Equivalent (Boe) [Domain]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves, net Boe, beginning of year | MBoe	151,053	101,519	121,088
Extensions and discoveries, Boe | MBoe	37,304	38,531	42,514
Revisions of previous estimates, Boe | MBoe	(4,323)	7,469	6,055
Sales of reserves in place, Boe | MBoe			(58,139)
Purchases of reserves in place, Boe		15,512
Production, Boe | MBoe	(13,402)	(11,978)	(9,999)
Proved developed and undeveloped reserves, net Boe, end of year | MBoe	170,632	151,053	101,519
Proved developed reserves (energy) | MBoe	76,032	65,482	38,929
Proved undeveloped reserves (energy) | MBoe	94,600	85,571	62,590
Barrel of Oil Equivalent (Boe) [Domain] | U.S. [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves, net Boe, beginning of year | MBoe	151,053	101,519	115,070
Extensions and discoveries, Boe | MBoe	37,304	38,531	42,514
Revisions of previous estimates, Boe | MBoe	(4,323)	7,469	6,055
Sales of reserves in place, Boe | MBoe			(52,121)
Purchases of reserves in place, Boe		15,512
Production, Boe | MBoe	(13,402)	(11,978)	(9,999)
Proved developed and undeveloped reserves, net Boe, end of year | MBoe	170,632	151,053	101,519
Proved developed reserves (energy) | MBoe	76,032	65,482	38,929
Proved undeveloped reserves (energy) | MBoe	94,600	85,571	62,590
Barrel of Oil Equivalent (Boe) [Domain] | U.K.
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves, net Boe, beginning of year | MBoe	0	0	6,018
Extensions and discoveries, Boe | MBoe	0	0	0
Revisions of previous estimates, Boe | MBoe	0	0	0
Sales of reserves in place, Boe | MBoe			(6,018)
Purchases of reserves in place, Boe		0
Production, Boe | MBoe	0	0	0
Proved developed and undeveloped reserves, net Boe, end of year | MBoe	0	0	0
Proved developed reserves (energy) | MBoe	0	0	0
Proved undeveloped reserves (energy) | MBoe	0	0	0

Supplemental Disclosures Abou90

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, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standard measure of discounted future net cash flows	$ 1,365,224	$ 2,555,082	$ 1,621,411	$ 1,418,395
U.S. [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	5,878,348	10,380,951	6,936,276
Future production costs	(2,124,059)	(2,532,106)	(1,629,663)
Future development costs	(1,178,773)	(1,680,795)	(1,340,722)
Future income taxes	0	(1,354,524)	(835,840)
Future net cash flows	2,575,516	4,813,526	3,130,051
Less 10% annual discount to reflect timing of cash flows	(1,210,292)	(2,258,444)	(1,508,640)
Standard measure of discounted future net cash flows	1,365,224	2,555,082	1,621,411	1,179,483
U.K.
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standard measure of discounted future net cash flows	$ 0	$ 0	$ 0	$ 238,912

Supplemental Disclosures Abou91

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, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 2,555,082	$ 1,621,411	$ 1,418,395
Net change in sales prices and production costs related to future production	(2,547,213)	(240,533)	(232,361)
Net change in estimated future development costs	342,238	89,401	(10,602)
Net change due to revisions in quantity estimates	(157,271)	205,166	205,686
Accretion of discount	326,074	202,672	185,389
Changes in production rates (timing) and other	(139,533)	(61,099)	11,892
Total revisions	(2,175,705)	195,607	160,004
Net change due to extensions and discoveries, net of estimated future development and production costs	252,155	867,615	873,028
Increase Due to Purchases of Minerals in Place		352,867
Net change due to sales of minerals in place			(632,752)
Sales of oil and gas produced, net of production costs	(312,213)	(598,036)	(444,841)
Previously estimated development costs incurred	340,247	415,963	217,395
Net change in income taxes	705,658	(300,345)	30,182
Net change in standardized measure of discounted future net cash flows	(1,189,858)	933,671	203,016
Standardized measure — end of period	1,365,224	2,555,082	1,621,411
United States [Member]
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	2,555,082	1,621,411	1,179,483
Net change in sales prices and production costs related to future production	(2,547,213)	(240,533)	(232,361)
Net change in estimated future development costs	342,238	89,401	(10,602)
Net change due to revisions in quantity estimates	(157,271)	205,166	205,686
Accretion of discount	326,074	202,672	141,229
Changes in production rates (timing) and other	(139,533)	(61,099)	56,052
Total revisions	(2,175,705)	195,607	160,004
Net change due to extensions and discoveries, net of estimated future development and production costs	252,155	867,615	873,028
Increase Due to Purchases of Minerals in Place		352,867
Net change due to sales of minerals in place			(191,155)
Sales of oil and gas produced, net of production costs	(312,213)	(598,036)	(444,841)
Previously estimated development costs incurred	340,247	415,963	217,395
Net change in income taxes	705,658	(300,345)	(172,503)
Net change in standardized measure of discounted future net cash flows	(1,189,858)	933,671	441,928
Standardized measure — end of period	1,365,224	2,555,082	1,621,411
United Kingdom [Member]
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	0	0	238,912
Net change in sales prices and production costs related to future production	0	0	0
Net change in estimated future development costs	0	0	0
Net change due to revisions in quantity estimates	0	0	0
Accretion of discount	0	0	44,160
Changes in production rates (timing) and other	0	0	(44,160)
Total revisions	0	0	0
Net change due to extensions and discoveries, net of estimated future development and production costs	0	0	0
Increase Due to Purchases of Minerals in Place		0
Net change due to sales of minerals in place			(441,597)
Sales of oil and gas produced, net of production costs	0	0	0
Previously estimated development costs incurred	0	0	0
Net change in income taxes	0	0	202,685
Net change in standardized measure of discounted future net cash flows	0	0	(238,912)
Standardized measure — end of period	$ 0	$ 0	$ 0

Selected Quarterly Financial 92

Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 99,422	$ 106,237	$ 123,494	$ 100,050	$ 163,275	$ 196,225	$ 193,475	$ 157,212	$ 429,203	$ 710,187	$ 520,182
Net income (loss) from continuing operations	(380,671)	(708,768)	(46,970)	(21,476)	129,451	82,997	3,214	6,621
Net income (loss)	$ (380,165)	$ (707,647)	$ (46,132)	$ (21,210)	$ 134,259	$ 83,789	$ 2,319	$ 5,976	$ (1,155,154)	$ 226,343	$ 43,683
Income (Loss) from Continuing Operations (in dollars per share)	$ (6.73)	$ (13.75)	$ (0.92)	$ (0.46)	$ 2.85	$ 1.83	$ 0.07	$ 0.15	$ (22.50)	$ 4.90	$ 0.54
Net income (loss) per share basic (in dollars per share)	(6.72)	(13.73)	(0.90)	(0.46)	2.96	1.85	0.05	0.13	(22.45)	4.99	1.07
Net income (loss) from continuing operations, diluted (in dollars per share)	(6.73)	(13.75)	(0.92)	(0.46)	2.80	1.80	0.07	0.14	(22.50)	4.81	0.53
Net income per share, diluted (in dollars per share)	$ (6.72)	$ (13.73)	$ (0.90)	$ (0.46)	$ 2.91	$ 1.82	$ 0.05	$ 0.13	$ (22.45)	$ 4.90	$ 1.06

Selected Quarterly Financial 93

Selected Quarterly Financial Data Narrative (Details) - USD ($) $ in Thousands	3 Months Ended			9 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Gains (Losses) on Extinguishment of Debt				$ 38,100		$ (38,137)	$ 0	$ 0
After-tax impairment of oil and gas properties	$ 273,100	$ 522,700				795,800
Impairment of oil and gas properties	$ 411,600	$ 812,800			$ 0	1,224,367	0	0
Gain on sale of discontinued operations							(37,300)
Loss on sale of oil and gas properties			$ (45,377)			$ 0	$ 0	$ (45,377)