Carrizo Oil & Gas (CRZO) Inactive 10-K3 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 25, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Entity Registrant Name	'CARRIZO OIL & GAS INC	'	'
Entity Central Index Key	'0001040593	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	45,473,352	'
Entity Public Float	'	'	$1.10
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS	'	'
Cash and cash equivalents	$157,439	$52,095
Accounts receivable, net	104,553	112,821
Accounts receivable - related party	6,642	9,815
Current assets held for sale	0	1,882
Fair value of derivative instruments	0	23,981
Deferred income taxes	4,201	0
Prepaids and other current assets	6,926	8,111
Total current assets	279,761	208,705
Oil and gas properties using the full cost method of accounting	'	'
Proved oil and gas properties, net	1,408,484	1,152,548
Unproved properties, not being amortized	377,437	323,688
Other property and equipment, net	8,294	11,438
TOTAL PROPERTY AND EQUIPMENT, NET	1,794,215	1,487,674
LONG-TERM ASSETS HELD FOR SALE	0	132,626
DEFERRED FINANCING COSTS, NET	22,899	23,914
FAIR VALUE OF DERIVATIVE INSTRUMENTS	9,284	5,180
DEFERRED INCOME TAXES	0	21,272
OTHER ASSETS	4,601	4,625
TOTAL ASSETS	2,110,760	1,883,996
CURRENT LIABILITIES	'	'
Accounts payable, trade	54,371	44,775
Accounts payable - related party	2,775	0
Revenue and royalties payable	80,198	82,300
Accrued drilling costs	85,452	60,729
Accrued interest	17,430	18,012
Other accrued liabilities	41,759	28,445
Advances for joint operations	19,967	8,069
Fair value of derivative instruments	9,947	0
Deferred income taxes	0	7,925
Current liabilities associated with assets held for sale	0	48,663
Current liabilities of discontinued operations	10,936	0
Total current liabilities	322,835	298,918
LONG-TERM DEBT, NET OF DEBT DISCOUNT	900,247	967,808
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE	0	23,547
LONG-TERM LIABILITIES OF DISCONTINUED OPERATIONS	17,336	0
ASSET RETIREMENT OBLIGATIONS	6,576	4,489
DEFERRED INCOME TAXES	16,856	0
OTHER LIABILITIES	5,306	4,218
COMMITMENTS AND CONTINGENCIES	'	'
SHAREHOLDERSâ€™ EQUITY	'	'
Common stock, $0.01 par value (90,000 shares authorized, 45,469 and 40,165 shares issued and outstanding at December 31, 2013 and 2012, respectively)	455	402
Additional paid-in capital	879,948	667,096
Accumulated deficit	-38,799	-82,482
Total shareholdersâ€™ equity	841,604	585,016
TOTAL LIABILITIES AND SHAREHOLDERSâ€™ EQUITY	$2,110,760	$1,883,996

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
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)	45,469,000	40,165,000
Common stock, shares outstanding (in shares)	45,469,000	40,165,000

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
OIL AND GAS REVENUES	$520,182	$368,180	$202,167
COSTS AND EXPENSES	'	'	'
Lease operating	46,828	31,471	28,314
Production tax	19,811	13,542	5,697
Ad valorem tax	8,701	9,813	3,625
Depreciation, depletion and amortization	213,820	165,621	84,606
General and administrative (inclusive of stock-based compensation expense of $29,373, $11,689 and $11,864 for the years ended December 31, 2013, 2012 and 2011, respectively)	77,492	48,708	41,539
Accretion related to asset retirement obligations	471	372	235
Loss on sale of oil and gas properties	45,377	0	0
TOTAL COSTS AND EXPENSES	412,500	269,527	164,016
OPERATING INCOME	107,682	98,653	38,151
OTHER INCOME AND EXPENSES	'	'	'
Gain (loss) on derivative instruments, net	-18,417	31,371	48,423
Interest expense	-84,578	-73,006	-50,998
Capitalized interest	29,889	24,848	23,369
Other income (expense), net	185	267	-800
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	34,761	82,133	58,145
INCOME TAX EXPENSE	-12,903	-30,956	-25,611
NET INCOME FROM CONTINUING OPERATIONS	21,858	51,177	32,534
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	21,825	4,310	4,095
NET INCOME	$43,683	$55,487	$36,629
NET INCOME PER COMMON SHARE - BASIC	'	'	'
Net income from continued operations (in dollars per share)	$0.54	$1.29	$0.83
Net income (loss) from discontinued operations (in dollars per share)	$0.53	$0.11	$0.11
Net income per share basic (in dollars per share)	$1.07	$1.40	$0.94
NET INCOME PER COMMON SHARE - DILUTED	'	'	'
Net income from continuing operations (in dollars per share)	$0.53	$1.28	$0.82
Net income (loss) from discontinued operations (in dollars per share)	$0.53	$0.11	$0.10
Net income per share, diluted (in dollars per share)	$1.06	$1.39	$0.92
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING	'	'	'
Basic (in shares)	40,781	39,591	39,077
Diluted (in shares)	41,355	40,026	39,668

Consolidated_Statements_Of_Ope1

Consolidated Statements Of Operations (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Stock-based compensation, net of amounts capitalized	$29,373	$11,689	$11,864

Consolidated_Statements_Of_Sha

Consolidated Statements Of Shareholders' Equity (USD $)	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]
In Thousands, except Share data, unless otherwise specified	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]
BALANCE at Dec. 31, 2010	$456,636	$389	$630,845	($174,598)
BALANCE, shares at Dec. 31, 2010	'	38,906,177	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'
Stock options exercised for cash	48	1	47	'
Stock options exercised for cash, shares	151,500	151,500	'	'
Stock-based compensation	14,444	'	14,444	'
Restricted stock, net of forfeitures	-479	4	-483	'
Restricted stock, net of forfeitures, shares	'	439,237	'	'
Other	2,577	1	2,576	'
Other, shares	'	65,762	'	'
Net income (loss)	36,629	'	'	36,629
BALANCE at Dec. 31, 2011	509,855	395	647,429	-137,969
BALANCE, shares at Dec. 31, 2011	'	39,562,676	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'
Stock options exercised for cash	107	1	106	'
Stock options exercised for cash, shares	20,500	20,500	'	'
Stock-based compensation	17,396	'	17,396	'
Restricted stock, net of forfeitures	-80	5	-85	'
Restricted stock, net of forfeitures, shares	'	488,052	'	'
Other	2,251	1	2,250	'
Other, shares	'	93,289	'	'
Net income (loss)	55,487	'	'	55,487
BALANCE at Dec. 31, 2012	585,016	402	667,096	-82,482
BALANCE, shares at Dec. 31, 2012	'	40,164,517	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'
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, net of forfeitures	-533	6	-539	'
Restricted stock, 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	'	'

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net income (loss)	$43,683	$55,487	$36,629
Net income from discontinued operations, net of income taxes	-21,825	-4,310	-4,095
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities from continuing operations	'	'	'
Depreciation, depletion and amortization expense	213,820	165,621	84,606
Non-cash (gain) loss on derivatives, net	30,908	7,553	-12,971
Accretion expense related to asset retirement obligations	471	372	235
Loss on sale of oil and gas properties	45,377	0	0
Stock-based compensation, net of amounts capitalized	29,373	11,689	11,864
Deferred income taxes	10,934	30,142	24,546
Non-cash interest expense, net of amounts capitalized	3,932	4,584	3,061
Other, net	3,704	6,036	4,033
Changes in operating assets and liabilities-	'	'	'
Accounts receivable	11,557	-67,120	-23,910
Accounts payable	13,595	26,942	33,457
Accrued liabilities	-12,588	21,832	9,354
Other, net	-5,467	-5,757	-11,298
Net cash provided by operating activities from continuing operations	367,474	253,071	155,511
Net cash used in operating activities from discontinued operations	-623	-845	-1,173
Net cash provided by operating activities	366,851	252,226	154,338
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Capital expenditures - oil and gas properties	-786,976	-735,711	-516,004
Capital expenditures - other property and equipment	-968	-4,176	-1,363
Increase (decrease) in capital expenditure payables and accruals	32,261	-9,880	49,346
Proceeds from sales of oil and gas properties, net	238,470	341,597	167,265
Advances to operators	447	-3,687	390
Advances for joint operations	11,898	-46,110	50,772
Other, net	-5,017	-7,184	-474
Net cash used in investing activities from continuing operations	-509,885	-465,151	-250,068
Net cash provided by (used in) investing activities from discontinued operations	124,533	-42,265	-35,930
Net cash used in investing activities	-385,352	-507,416	-285,998
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from borrowings and issuances	582,000	1,040,772	879,061
Debt repayments	-651,325	-796,000	-752,660
Payments of debt issuance and retirement costs	-3,257	-7,101	-9,622
Proceeds from common stock offerings, net of offering costs	189,686	0	0
Excess tax benefits from stock-based compensation	1,969	0	0
Proceeds from stock options exercised	1,253	107	47
Net cash provided by financing activities from continuing operations	120,326	237,778	116,826
Net cash provided by financing activities from discontinued operations	3,000	41,914	38,818
Net cash provided by financing activities	123,326	279,692	155,644
NET INCREASE IN CASH AND CASH EQUIVALENTS	104,825	24,502	23,984
CASH AND CASH EQUIVALENTS, beginning of year	52,095	'	'
CASH AND CASH EQUIVALENTS, end of year	157,439	52,095	'
SUPPLEMENTAL CASH FLOW DISCLOSURES	'	'	'
Cash paid for interest, net of amounts capitalized	50,770	43,629	26,077
Cash paid for income taxes	505	587	4,156
Cash and Cash Equivalents, at Carrying Value, Consolidated	$157,439	$52,614	$28,112

Nature_Of_Operations

Nature Of Operations	12 Months Ended
Nature Of Operations	Dec. 31, 2013
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 Niobrara Formation in Colorado, the Marcellus Shale in Pennsylvania, and the Utica Shale in Ohio.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
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 all significant 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. These reclassifications had no effect on total assets, total liabilities, total shareholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.
	Discontinued Operations
	On December 27, 2012, the Company agreed to sell Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all of its interest in the Huntington Field discovery, where Carrizo UK owned a 15% non-operated working interest and certain overriding royalty interests. The sale closed on February 22, 2013. Accordingly, the Company classified the U.K. North Sea assets and associated liabilities as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in the consolidated balance sheets as of December 31, 2012. As of December 31, 2013, the Company classified the remaining liabilities associated with the U.K. North Sea as current and long-term liabilities of discontinued operations in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations in the consolidated statements of income, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relates to the Company’s continuing operations. Information related to discontinued operations is included in “Note 3. Discontinued Operations”, “Note 13. Condensed Consolidating Financial Information” and “Note 14. 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 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 the amortization 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 impairments of unevaluated leasehold costs, fair values of derivative instruments, stock-based compensation expense attributable to stock appreciation rights, 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 include highly liquid investments with original maturities of three months or less.
	Accounts Receivable and Allowance for Doubtful Accounts
	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. At December 31, 2013 and 2012, the Company’s allowance for doubtful accounts was $0.6 million and $1.4 million, respectively.
	Concentration of Credit Risk
	Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third-party working interest owners in the oil and gas industry or development advances to third-party operators for drilling and completion costs of wells in progress. This concentration of customers and joint interest owners 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. The Company generally has the right to offset revenue against related billings to joint interest owners.
	Derivative instruments subject the Company to a concentration of credit risk. See “Note 11. Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments.
	Major Customers
	In 2013, two customers accounted for approximately 47% and 23% of the Company’s oil and gas revenues. In 2012, two customers accounted for approximately 53% and 10% of the Company’s oil and gas revenues. In 2011, one customer accounted for approximately 43% of the Company’s oil and gas revenues.
	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. Internal costs, consisting of compensation and benefits, including stock-based compensation, associated with employees directly associated with acquisition, exploration and development activities are capitalized and totaled $15.0 million, $11.8 million and $9.6 million for the years ended December 31, 2013, 2012 and 2011, 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 rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter then applying such amount 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 depreciation, depletion and amortization (“DD&A”) per Boe was $21.38, $17.55 and $11.26 for the years ended December 31, 2013, 2012 and 2011, 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. Significant costs of unevaluated properties and exploratory wells in progress are assessed individually 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 unproved properties within the next five years and exploratory wells in progress within the next year. The costs of individually insignificant unevaluated leaseholds are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease term of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs and exploratory wells in progress of $29.9 million, $24.8 million and $23.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated leasehold and seismic costs and the average balance of exploratory wells in progress using a weighted-average interest rate based on outstanding borrowings.
	Proceeds from the sale of proved oil and gas properties or unevaluated leasehold costs 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. 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 income. 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 income in the fourth quarter of 2013. Other than the sales noted above, the Company has not had any sales that significantly altered the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center through December 31, 2013.
	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 increase the cost center ceiling applicable to the subsequent period.
	The estimated future net revenues used in the ceiling test 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 used in the ceiling test computation 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.
	Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from five to ten years.
	Deferred Financing Costs
	Deferred financing costs, net were $22.9 million and $23.9 million as of December 31, 2013 and 2012, respectively and include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of debt securities and costs associated with the revolving credit facility. The capitalized costs are amortized to interest expense using the effective interest method over the terms of the debt securities or credit facility.
	Financial Instruments
	The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative instruments 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 instruments are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including (a) quoted forward prices for oil and gas, (b) discount rates and (c) volatility factors. The carrying amounts of long-term debt under the Company’s revolving credit facility approximate fair value as the borrowings bear interest at variable rates of interest. The carrying amounts of the Company’s senior notes and convertible senior notes may not approximate fair value because the notes bear interest at fixed rates of interest. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.”
	Asset Retirement Obligations
	The Company’s asset retirement obligations represent the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of production equipment and facilities and restoring the surface of the land in accordance with the terms of the oil and gas lease 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 the oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. The asset retirement obligation is 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 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 an interim 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 obligation 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 the abandonment of oil and gas wells.
	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.
	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 oil and gas 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, 2013 and 2012, the Company did not have any material production imbalances.
	Derivative Instruments
	The Company uses commodity derivative instruments, primarily fixed price swaps and costless collars, to manage its exposure to commodity price risk. 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. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company 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 derivative instruments, net in the consolidated statements of income 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 in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes.
	The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. 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. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. See “Note 11. Derivative Instruments” for further discussion of the Company’s derivative instruments.
	Stock-Based Compensation
	The Company has granted stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock at the option of the Company, SARs that may only be settled in cash, restricted stock awards and units to directors, employees and independent contractors. The Company recognized the following stock-based compensation expense, net of amounts capitalized for the periods indicated which is reflected as general and administrative expense in the consolidated statements of income:


			Year Ended December 31,
			2013				2012				2011
			(In thousands)
	Stock appreciation rights		$	17,303			$	(2,116	)		$	1,546

	Restricted stock awards and units		18,997				17,049				13,965

			36,300				14,933				15,511

	Less: amounts capitalized		(6,927		)		(3,244		)		(3,647		)
	Stock-based compensation expense, net of amounts capitalized		$	29,373			$	11,689			$	11,864

	Income Tax Benefit		$	10,281			$	4,449			$	4,342

	Stock Options and SARs. For stock options and for SARs that the Company may elect to settle in cash or common stock, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally three years). For SARs that the Company has elected to settle in cash or SARs that may only be settled in cash, stock-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as other accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as long-term other liabilities. Subsequent to vesting, the liability for SARs that the Company expects to settle in cash is remeasured in earnings at each reporting period based on the fair value until the awards are settled. The Company recognizes stock-based compensation expense over the vesting period for stock options and SARs using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Stock options typically expire ten years after the date of grant. SARs typically expire between four and seven years after the date of grant.
	The Company uses the Black-Scholes-Merton option pricing model to compute the fair value of stock options and SARs, which requires 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.

•	The expected term is based on historical exercises for various groups of directors, employees and independent contractors.
Restricted Stock Awards and Units. For restricted stock awards and units, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally one to three years) using the straight-line method, except for award or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted stock awards and units is based on the price of the Company’s common stock on the grant date. 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.
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. The Company classifies interest and penalties associated with income taxes as interest expense.
Net Income From Continuing Operations Per Common Share
Supplemental net income from continuing operations per common share information is provided below:


		Year Ended December 31,
		2013				2012				2011
		(In thousands, except per share amounts)
Net income from continuing operations		$	21,858			$	51,177			$	32,534

Basic weighted average common shares outstanding		40,781				39,591				39,077

Effect of dilutive instruments		574				435				591

Diluted weighted average shares outstanding		41,355				40,026				39,668

Net income from continuing operations per common share
Basic		$	0.54			$	1.29			$	0.83

Diluted		$	0.53			$	1.28			$	0.82

Basic net income from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted net income 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 period which include restricted stock awards and units, stock options, SARs that the Company may elect to settle in cash or common stock, SARs the Company has elected to settle in common stock, warrants and convertible debt. The Company excludes the number of shares, units, options, rights 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 corresponding period as the effect would be antidilutive to the computation. The number of shares, units, options, rights and warrants excluded for the years ended December 31, 2013, 2012 and 2011 were not significant. Shares of common stock subject to issuance upon the conversion of the Company’s convertible senior notes did not have an effect on the calculation of dilutive shares for the years ended December 31, 2013, 2012 and 2011 because the conversion price was in excess of the market price of the common stock for those periods.
Recently Adopted Accounting Pronouncements
Effective January 1, 2013, the Company adopted the provisions of ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, and began providing enhanced disclosures regarding the effect or potential effect of netting arrangements on an entity’s financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The Company adopted this new disclosure requirement effective January 1, 2013. The adoption did not have a material effect on the Company’s consolidated financial statements.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	3. Discontinued Operations
	On February 22, 2013, the Company closed the sale of Carrizo UK, including it’s 15% non-operated working interest and certain overriding royalty interests in the Huntington Field discovery, to a subsidiary of Iona Energy Inc. (“Iona Energy”). Net proceeds received from the sale were approximately $144.1 million, which represents an agreed-upon price of $184.0 million, including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding as of the closing date under Carrizo UK’s senior secured multicurrency credit facility, less net purchase price adjustments (primarily related to working capital) and deferred consideration. The Company recognized a pre-tax gain of approximately $37.3 million, net of transaction costs and a $30.5 million accrual for estimated future obligations related to the sale. By the end of the third quarter of 2013, the Company had received the deferred consideration of $18.5 million, in accordance with the sale and purchase agreement, as amended.
	The Company’s current liabilities of discontinued operations of $10.9 million and long-term liabilities of discontinued operations of $17.3 million as of December 31, 2013 relate to 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 assets and liabilities related to the sale of Carrizo UK.
	As a result of the sale of Carrizo UK, the Company reclassified the balances associated with our U.K. North Sea operations from held for sale as of December 31, 2012 to discontinued operations as of December 31, 2013.
	The following table summarizes the amounts included in net income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of income for the years ended December 31, 2013, 2012 and 2011:


		For the Years Ended December 31,
		2013			2012			2011
		(In thousands)
	OIL AND GAS REVENUES	$	—		$	—		$	—

	COSTS AND EXPENSES
	General and administrative	916			62			242

	Accretion related to asset retirement obligations	36			363			76

	TOTAL COST AND EXPENSES	952			425			318

	OPERATING LOSS	(952		)	(425		)	(318		)
	OTHER INCOME AND EXPENSES
	Gain on sale of discontinued operations	37,294			—			—

	Adjustment of estimated future obligations	(44		)	—			—

	Gain (loss) on derivative instruments, net	(109		)	258			(1,432		)

	Interest expense	(253		)	(3,556		)	(1,805		)
	Capitalized interest	253			3,556			—

	Other income (expense), net	438			(591		)	259

	INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	36,627			(758		)	(3,296		)

	DEFERRED INCOME TAX (EXPENSE) BENEFIT	(14,802		)	5,068			7,391

	NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	21,825		$	4,310		$	4,095

	Income Taxes
	Carrizo UK is a disregarded entity for U.S. income tax purposes. Accordingly, the income tax (expense) benefit reflected above includes the Company’s U.S. (expense) benefit associated with the income (loss) from discontinued operations before income taxes. The related U.S. deferred tax assets and liabilities have been classified as deferred income taxes of continuing operations in the consolidated balance sheets.

Property_And_Equipment_Net

Property And Equipment, Net	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property And Equipment, Net	'
	4. Property and Equipment, Net
	At December 31, 2013 and 2012, property and equipment, net consisted of the following:


		December 31,
		2013			2012
		(In thousands)
	Proved oil and gas properties	$	2,182,226		$	1,713,827

	Accumulated depreciation, depletion and amortization	(773,742		)	(561,279		)
	Proved oil and gas properties, net	1,408,484			1,152,548

	Unproved properties, not being amortized
	Unevaluated leasehold and seismic costs	302,232			238,833

	Exploratory wells in progress	30,196			43,803

	Capitalized interest	45,009			41,052

	Total unproved properties, not being amortized	377,437			323,688

	Other property and equipment	15,260			17,079

	Accumulated depreciation	(6,966		)	(5,641		)
	Other property and equipment, net	8,294			11,438

	Total property and equipment, net	$	1,794,215		$	1,487,674

	Costs not subject to amortization totaling $377.4 million at December 31, 2013 were incurred in the following periods: $265.0 million in 2013 and $112.4 million in 2012.
	Sales of Barnett Properties
	During the second quarter of 2012, the Company sold a significant portion of its Barnett properties to an affiliate of Atlas Resource Partners, L.P. (“Atlas”). Net proceeds received from the sale were approximately $187.1 million, which represents an agreed upon price of $190.0 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 January 1, 2012 and the closing date of April 30, 2012. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.
	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.
	Sale and Acquisitions of Utica Properties
	In October 2012, the Company sold substantially all of its interests in unevaluated oil and gas properties dedicated to its Utica joint venture in the northern portion of the Utica play to a third party and received net cash proceeds of $51.7 million, after final post-closing adjustments and payments to the Company’s joint venture partner to exercise an option on properties involved in the transaction concurrently with the third party sale. Other assets included in the sale were an existing drilling pad and approved well drilling permits associated with the properties. The properties sold were located in Mercer and Crawford counties in Pennsylvania and Trumbull county in Ohio. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.
	In connection with the Utica sale transactions described above, the Company elected on January 15, 2013 to exercise its option to increase its participating interest from 10% to 50% in other unevaluated oil and gas properties dedicated to its Utica joint venture in the central and southern portions of the Utica play, by paying $63.1 million. In connection with this exercise of the Company’s option to increase its participating interest in the Avista Utica joint venture properties, its right to receive distributions associated with properties owned by ACP III through “B Units” interest in ACP III that the Company acquired at the formation of the Utica joint venture was terminated.
	On October 31, 2013, the Company completed the acquisition of additional interests in joint venture acreage located primarily in Guernsey and Noble counties, Ohio from ACP III. The transaction had an effective date of July 1, 2013, and the Company paid ACP III approximately $78.6 million in cash, subject to final post-closing adjustments. Prior to the Company’s acquisition from ACP III, the properties in the Avista Utica joint venture were held on an equal basis by the Company and ACP III. The purchase agreement provides for post-closing price and acreage adjustments and indemnities. The transaction was initially funded with proceeds from the sale of the Company’s remaining oil and gas properties in the Barnett as disclosed above. For additional information see “Note 10. Related Party Transactions.”
	Sales of Non-Core Marcellus and East Texas Properties
	During the second half of 2013, the Company sold certain non-core proved producing oil and gas properties in East Texas and its interests in unevaluated acreage in non-core areas of Marcellus. Net proceeds received from the two transactions were $29.5 million, which represents an aggregate agreed upon price of $30.5 million less net purchase price adjustments. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.
	Sale of Gulf Coast Properties
	During the third quarter of 2012, the Company completed the sale of substantially all of its legacy proved producing oil and gas properties along the onshore Gulf of Mexico located primarily in Texas and Louisiana. Net proceeds received from the sale were approximately $17.6 million, which represents an agreed upon price of $19.3 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, 2012 and the closing date of September 27, 2012. The proceeds from such sale were recognized as a reduction of proved oil and gas properties, net.
	Niobrara Joint Ventures
	OIL India (USA) Inc. and IOCL (USA) Inc. In October 2012, the Company completed the sale of 30% of substantially all of its interests in oil and gas properties in the Niobrara to OIL India (USA) Inc. and IOCL (USA) Inc., subsidiaries of OIL India Ltd. and Indian Oil Corporation Ltd., respectively, effective October 1, 2012. For convenience, in these Notes to Consolidated Financial Statements the term “OIL JV Partners” is used to refer collectively to OIL India (USA) Inc. and IOCL (USA) Inc. Under the purchase and participation agreement for this transaction, the Company received approximately $41.25 million in cash and the OIL JV Partners committed to pay a “development carry” of 50% of certain of the Company’s future development costs up to an aggregate of approximately $41.25 million. The development carry was fully utilized in 2013. The proceeds from such sale was recognized as a reduction of proved oil and gas properties. The agreement also provides for an ongoing joint venture between the Company and the OIL JV Partners with respect to the interests purchased. The Niobrara assets conveyed to the OIL JV Partners under the terms of the agreement are located primarily in Weld and Adams counties, Colorado.
	Haimo Oil & Gas LLC. In December 2012, the Company completed the sale of a portion of its remaining interest in the same oil and gas properties sold to the OIL JV Partners in the transaction described above to Haimo Oil & Gas LLC (“Haimo”), a subsidiary of Lanzhou Haimo Technologies Co. Ltd., effective October 1, 2012, for a cash payment of $27.5 million. The proceeds from such sale were recognized as a reduction of proved oil and gas properties. The purchase and participation agreement for this transaction provides for an ongoing joint venture between the Company and Haimo, with respect to the interests purchased. The Company will operate the joint venture properties. Following the closing of the Haimo transaction late in the fourth quarter of 2012, the Company, the OIL JV Partners and Haimo owned 60%, 30% and 10% of the joint venture acreage, respectively.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	5. Income Taxes
	The components of income tax expense from continuing operations were as follows:


			Year Ended December 31,
			2013				2012			2011
							(In thousands)
	Current income tax (expense) benefit
	U.S. Federal		$	411			$	(411	)	$	(404	)

	State		(141		)		(403		)	(661		)
	Total current income tax (expense) benefit		270				(814		)	(1,065		)

	Deferred income tax expense
	U.S. Federal		(12,404		)		(28,723		)	(23,254		)
	State		(769		)		(1,419		)	(1,292		)
	Total deferred income tax expense		(13,173		)		(30,142		)	(24,546		)
	Total income tax expense from continuing operations		$	(12,903	)		$	(30,956	)	$	(25,611	)
	The Company’s income tax expense from continuing operations differs from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of 35% to income from continuing operations before income taxes as follows:


			Year Ended December 31,
			2013				2012			2011
							(In thousands)
	Income from continuing operations before income taxes		$	34,761			$	82,133		$	58,145

	Income tax expense at the statutory rate		(12,166		)		(28,747		)	(20,350		)
	State income taxes, net of U.S. federal income tax benefit		(859		)		(1,681		)	(1,722		)
	Adjustment to prior period state income taxes, net of U.S. federal income tax benefit		—				—			(4,735		)

	Previously unbenefitted capital loss associated with investment						—			1,171

	Nondeductible expenses		—				(93		)	25

	Other		122				(435		)	—

	Total income tax expense from continuing operations		$	(12,903	)		$	(30,956	)	$	(25,611	)
	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. At December 31, 2013 and 2012, deferred tax assets and liabilities are comprised of the following:


			December 31,
			2013				2012
			(In thousands)
	Deferred income tax assets
	Net operating loss carryforward - U.S. Federal and State		$	52,499			$	53,648

	Stock-based compensation		7,563				4,245

	Allowance for doubtful accounts		170				476

	Fair value of derivative instruments		3,222				—

	Other		2,471				1,755

	Deferred income tax assets		65,925				60,124

	Valuation allowance		(1,084		)		(1,188		)
	Net deferred income tax assets		64,841				58,936

	Deferred income tax liabilities
	Unamortized discount on 4.375% Convertible Senior Notes		—				(382		)

	Oil and gas properties		(74,247		)		(34,985		)
Fair value of derivative instruments		(3,249		)		(10,222		)
		(77,496		)		(45,589		)
Net deferred income tax asset (liability)		$	(12,655	)		$	13,347

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 on 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, 2013 and 2012, the net deferred income tax asset (liability) is classified as follows:


		December 31,
		2013				2012
		(In thousands)
Noncurrent deferred income tax asset (liability)		$	(16,856	)		$	21,272

Current deferred income tax asset (liability)		4,201				(7,925		)

Net deferred income tax asset (liability)		$	(12,655	)		$	13,347

As of December 31, 2013, the Company had U.S. federal net operating loss carryforwards of approximately $174.4 million. If not utilized in earlier periods, the U.S. federal net operating loss will expire between 2019 and 2033. The realization of the deferred tax assets related to loss carryforwards is dependent on the Company’s ability to generate sufficient future taxable income in the U.S. within the applicable carryforward periods. During 2011 and 2012, the Company determined it was more likely than not that some of its state loss carryforwards would not be realized and accordingly, established valuation allowances totaling approximately $1.1 million. The Company believes it will be able to generate sufficient future taxable income in the U.S. within the carryforward periods. As such, the Company believes that it is more likely than not that its net deferred income tax assets will be fully realized except for those state loss carryforwards for which a valuation allowance has been established.
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, 2013, 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, 2013. 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 $174.4 million but not reflected in the associated deferred tax asset were $29.2 million at December 31, 2013. The Company expects to recognize the $10.2 million deferred tax asset associated with these stock-based compensation tax deductions when all other components of the U.S. loss carryforward deferred tax asset have been fully 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.
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 statues of limitations. The 1999 through 2013 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 2012 and 2013 tax years through 2014. At December 31, 2013, 2012 and 2011, the Company had no material uncertain tax positions.

Debt

Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt	'
	6. Long-Term Debt
	At December 31, 2013 and 2012, long-term debt consisted of the following:


		December 31,
		2013			2012
		(In thousands)
	8.625% Senior Notes	$	600,000		$	600,000

	Unamortized discount for 8.625% Senior Notes	(4,178		)	(4,849		)
	7.50% Senior Notes	300,000			300,000

	4.375% Convertible Senior Notes	4,425			73,750

	Unamortized discount for 4.375% Convertible Senior Notes	—			(1,093		)

	Senior Secured Revolving Credit Facility	—			—

		$	900,247		$	967,808

	8.625% *Senior Notes and* *7.50%* *Senior Notes*
	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.
	Except in certain circumstances described below, the Company may not redeem the 8.625% Senior Notes prior to October 15, 2014. On and after October 15, 2014, the Company may redeem all or a part of the 8.625% Senior Notes, at redemption prices decreasing from 104.313% of the principal amount to 100% of the principal amount on October 15, 2017, plus accrued and unpaid interest. Prior to October 15, 2014, the Company may redeem all or part of the 8.625% 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 8.625% Senior Notes). If a Change of Control (as defined in the indenture governing the 8.625% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.625% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus any accrued but unpaid interest.
	On September 10, 2012, the Company issued in a public offering $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020. Except in certain circumstances described below, the Company may not redeem the 7.50% Senior Notes prior to September 15, 2016. On and after September 15, 2016, the Company may redeem all or a part of the 7.50% Senior Notes, at redemption prices decreasing from 103.750% of the principal amount to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest. In connection with certain equity offerings by the Company, the Company may at any time prior to September 15, 2015, subject to certain conditions, on one or more occasions, redeem up to 35% of the aggregate principal amount of the 7.50% Senior Notes at a redemption price of 107.500% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date using the net cash proceeds of such equity offerings. 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 7.50% Senior Notes). If a Change of Control (as defined in the indenture governing the 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 aggregate principal amount, plus any accrued but unpaid interest.
	The indentures governing the 8.625% Senior Notes and the 7.50% 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. At December 31, 2013, the 8.625% Senior Notes and the 7.50% 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).
	Convertible Senior Notes
	In May 2008, the Company issued $373.8 million aggregate principal amount of 4.375% Convertible Senior Notes due 2028. In November 2010, the Company completed a tender offer to repurchase $300.0 million aggregate principal amount outstanding of its convertible senior notes. After the Company’s repurchase of $300.0 million aggregate principal amount of convertible senior notes, $73.8 million aggregate principal amount of convertible senior notes remained outstanding. In June 2013, the Company completed a tender offer to repurchase $69.3 million aggregate principal amount outstanding of its convertible senior notes. After completion of the June 2013 tender offer, $4.4 million aggregate principal amount of convertible senior notes remain outstanding. Each holder as of the date of each tender offer received $1,000 for each $1,000 principal amount of convertible senior notes purchased in such tender offer, plus accrued and unpaid interest.
	The convertible senior notes are subject to customary non-financial covenants and events of default, including certain cross defaults of other indebtedness and mortgages, the occurrence and continuation of which could result in the acceleration of amounts due under the convertible senior notes. The convertible senior notes are unsecured obligations of the Company and rank equal to the Company’s senior notes and all future senior unsecured debt of the Company but rank second in priority to the senior secured revolving credit facility.
	The Company’s convertible senior notes are convertible, using a net share settlement process, into a combination of cash and Company common stock that entitles holders of the convertible senior notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of the Company’s conversion obligation in excess of such principal amount. The initial conversion rate of the notes into the Company’s common stock is 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of the Company’s common stock exceeds 130% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of the Company’s common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028.
	The holders of the convertible senior notes may require the Company to repurchase the notes on June 1, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100% of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time at a redemption price equal to 100% of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.
	Senior Secured Revolving Credit Facility
	The Company is party to a senior secured revolving credit facility with Wells Fargo Bank, National Association as the administrative agent. The revolving credit facility provides for a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the senior credit agreement governing the revolving credit facility) and (ii) $1.0 billion. The revolving credit facility matures on July 2, 2018. The revolving credit facility is secured by substantially all of the Company’s U.S. assets and is guaranteed by all of the Company’s existing Material Domestic Subsidiaries (as defined in the credit agreement governing the revolving credit facility).
	The current borrowing base is $470.0 million. The borrowing base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, with the next redetermination expected in the Spring of 2014. 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.
	The annual interest rate on each base rate borrowing is (a) the greatest of the Agent’s Prime Rate, the Federal Funds Effective Rate plus 0.5% and the adjusted LIBO rate for a three-month interest period on such day plus 1.00%, plus (b) a margin between 0.50% and 1.50% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted LIBO rate for the applicable interest period plus a margin between 1.50% to 2.50% (depending on the then-current level of borrowing base usage).
	On March 26, 2012, the revolving credit facility was amended to, among other things, (1) extend by two quarters the dates on which the maximum ratio of Total Debt to EBITDA (each as defined in the credit agreement governing the revolving credit facility) steps down and (2) increase the basket available for redemptions of the Company’s convertible senior notes. On September 4, 2012 the revolving credit facility was further amended to increase the basket available for issuances of additional senior notes, including those issued in the September 2012 notes offering. On September 27, 2012, the revolving credit facility was again amended to, among other things, extend the maximum permitted duration of hedge agreements entered into by the Company and its restricted subsidiaries and to reflect the Fall 2012 borrowing base redetermination. On October 9, 2013, a fourth amendment to the senior secured revolving credit facility was executed. The fourth amendment (i) extended the maturity date of the credit facility from January 27, 2016 to July 2, 2018, (ii) increased the aggregate maximum credit commitments of the lenders from $750.0 million to $1.0 billion, (iii) approved a borrowing base of $530.0 million until the closing of the sale of the Company’s remaining oil and gas properties in the Barnett, at which time the approved borrowing base was automatically reduced to $470.0 million and such reduced borrowing base will remain in effect until redetermined or adjusted in accordance with the credit agreement governing the Company’s revolving credit facility and (iv) eliminated covenants requiring the Company’s maintenance of a specified Senior Debt to EBITDA ratio and a specified EBITDA to Interest Expense ratio.
	The Company is subject to certain covenants under the terms of the revolving credit facility which include the maintenance of the following financial covenants: (1) a ratio of Total Debt to EBITDA of not more than 4.00; (2) a Current Ratio of not less than 1.00 to 1.00; (each of the capitalized terms used in the foregoing clauses (1) and (2) being as defined in the credit agreement governing the revolving credit facility). At December 31, 2013, the ratio of Total Debt to EBITDA was 1.94 to 1.00 and the Current Ratio was 2.57 to 1.00. As defined in the credit agreement governing the revolving credit facility, Total Debt is net of cash and cash equivalents and the Current Ratio includes an add back of the available borrowing capacity. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the revolving credit facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.
	The revolving credit facility 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 revolving credit facility is subject to customary events of default, including a change in control (as defined in the credit agreement governing the revolving credit facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the credit agreement governing the revolving credit facility) may accelerate amounts due under the revolving credit facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).
	At December 31, 2013 and 2012, the Company had no borrowings outstanding under the revolving credit facility. At December 31, 2013, the Company also had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. The revolving credit facility is generally used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	7. Asset Retirement Obligations
	The following table sets forth asset retirement obligations for the years ended December 31, 2013 and 2012:


		Year Ended December 31,
		2013			2012
		(In thousands)
	Asset retirement obligations at beginning of period	$	6,159		$	8,324

	Liabilities incurred	3,348			1,573

	Liabilities settled	(498		)	(1,666		)
	Reduction due to sales of oil and gas properties	(2,473		)	(3,272		)
	Accretion expense	471			372

	Revisions of previous estimates	349			828

	Asset retirement obligations at end of period	7,356			6,159

	Asset retirement obligations due within one year included in “Other accrued liabilities”	(780		)	(1,670		)
	Long-term asset retirement obligations	$	6,576		$	4,489

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments And Contingencies	'
	8. Commitments and Contingencies
	From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
	The results of operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural 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, 2013, 2012 and 2011 was $1.9 million, $1.8 million, and $1.7 million, respectively, and includes rent expense primarily for the Company’s corporate office and field offices. At December 31, 2013, total minimum commitments from long-term, non-cancelable operating leases, drilling rigs, completion services and pipeline volume commitments are as shown in the table below. The total minimum commitments related to the drilling rigs, completion services, and pipeline volume commitments 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.


		Amount
		(In thousands)
	2014	$	51,840

	2015	19,429

	2016	7,404

	2017	4,711

	2018	4,686

	2019 and thereafter	16,128

	Total	$	104,198

Shareholders_Equity_And_Stock_

Shareholders' Equity And Stock Incentive Plan	12 Months Ended
	Dec. 31, 2013
Shareholders' Equity And Stock Incentive Plan [Abstract]	'
Shareholders' Equity And Stock Incentive Plan	'
	9. Shareholders’ Equity and Stock Incentive Plans
	Shareholders’ Equity
	Common Stock. In November 2013, the Company sold 4.5 million shares of its common stock in an underwritten public offering at a price to the underwriter of $42.24 per share. The Company used the proceeds of approximately $189.7 million, net of offering costs, to fund in part its increased capital expenditure plan that took into account its recently completed Utica Shale acreage acquisition, the second half of the 2013 development of its expanded position in the Utica Shale and the accelerated fracking of a portion of its existing inventory of Eagle Ford wells and for other general corporate purposes.
	Warrants. On November 24, 2009, the Company entered into a land agreement with an unrelated third party and its affiliate. The land agreement expired pursuant to its terms on May 31, 2011. Under the land agreement, the Company issued warrants to purchase 31,983 and 28,576 shares of common stock in 2012 and 2011 respectively. In 2013, the Company issued no warrants to purchase shares of common stock. The final issuance of warrants under the land agreement was granted in April 2012. The warrants have an expiration date of August 21, 2017, an exercise price of $22.09, which may be exercised on a “cashless” basis, and are subject to anti-dilution adjustments.
	Stock Incentive 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 and restricted stock units to directors, employees and independent contractors. The Company may grant awards of up to 7,245,000 shares (subject to certain limitations on restricted stock and restricted stock units) under the Incentive Plan and through December 31, 2013, has issued stock options, restricted stock awards and restricted stock units covering 5,931,933 shares, net of forfeitures and excluding SARs the Company has elected to settle in cash.
	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 that may only be settled in cash to employees and independent contractors.
	Stock Options. No stock options were granted under the Incentive Plan during 2013, 2012 or 2011. The table below summarizes the activity for stock options for the three years ended December 31, 2013, 2012 and 2011:


			Shares			Weighted-		Weighted-	Aggregate
						Average		Average	Intrinsic Value
						Exercise		Remaining Life	(In millions)
						Prices		(In years)
	For the Year Ended December 31, 2011
	Outstanding, beginning of period		414,854			$6.10

	Granted		—			—

	Exercised		(151,500	)		$4.36
	Forfeited		—			—

	Outstanding, end of period		263,354			$7.11

	Exercisable, end of period		263,354			$7.11

	For the Year Ended December 31, 2012
	Outstanding, beginning of period		263,354			$7.11

	Granted		—			—

	Exercised		(20,500	)		$5.50
	Forfeited		—			—

	Outstanding, end of period		242,854			$7.24

	Exercisable, end of period		242,854			$7.24

	For the Year Ended December 31, 2013
	Outstanding, beginning of period		242,854			$7.24

	Granted		—			—

	Exercised		(206,501	)		$6.07
	Forfeited		—			—

	Outstanding, end of period		36,353			$13.91		1.1	$1.10

	Exercisable, end of period		36,353			$13.91		1.1	$1.10

	At December 31, 2013, all stock options were vested and accordingly, the Company had no unrecognized compensation costs related to outstanding stock options. The total intrinsic value (market price at date of exercise less the exercise price) of stock options exercised during the years ended December 31, 2013, 2012 and 2011 was $4.4 million, $0.4 million, and $3.6 million, respectively, and the Company received $1.3 million, $0.1 million, and $0.1 million in cash in connection with stock option exercises for the years ended December 31, 2013, 2012 and 2011, respectively.
	Stock Appreciation Rights. During the years ended December 31, 2013, 2012 and 2011, the Company granted 282,296, 193,336 and 153,801, respectively of SARs under the Cash SAR Plan and SARs under the Incentive Plan that can only be settled in cash. All SARs that have been granted by the Company contain performance and service conditions. The performance conditions have been met for all awards. The table below summarizes the activity for SARs for the three years ended December 31, 2013, 2012 and 2011:


			Shares			Weighted-		Weighted-		Aggregate
						Average		Average		Intrinsic Value
						Exercise		Remaining Life		(In millions)
						Prices		(In years)
	For the Year Ended December 31, 2011
	Outstanding, beginning of period		700,749			$18.50

	Granted		153,801			$37.99

Exercised		(4,768	)		$20.22
Forfeited		—			—

Outstanding, end of period		849,782			$22.02

Exercisable, end of period		326,128			$18.99

For the Year Ended December 31, 2012
Outstanding, beginning of period		849,782			$22.02

Granted		193,336			$25.56

Exercised		(7,295	)		$20.22
Forfeited		—			—

Outstanding, end of period		1,035,823			$22.69

Exercisable, end of period		613,934			$20.70

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
Forfeited		(24,704	)		$27.77
Outstanding, end of period		1,086,231			$24.78		2.8	21.12	$21.10

Exercisable, end of period		681,867			$22.55		2.7	14.78	$14.80

At December 31, 2013, the liability for SARs outstanding was $20.6 million, of which, $19.3 million is classified as other accrued liabilities representing the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder of $1.3 million classified as long-term other liabilities, respectively. At December 31, 2012, the liability for SARs outstanding was $7.2 million, of which $6.5 million is classified as other accrued liabilities representing the portion of the awards that are vested or are expected to vest within the next 12 months with the remainder of $0.7 million classified as long-term other liabilities, respectively. The Company paid $3.9 million, $0.1 million and $0.1 million, in connection with SARs exercised during the years ended December 31, 2013, 2012 and 2011, respectively. The following table summarizes the weighted-average assumptions used in the Black-Scholes-Merton option pricing model to calculate the fair value of the SARs granted during 2013, 2012 and 2011:


		31-Dec-13			31-Dec-12		31-Dec-11
Grant date fair value		$13.36			$12.23		$18.50
Volatility factor		44.5	%		48.2	%	61.6	%
Dividend yield		—	%		—	%	—	%
Risk-free interest rate		1	%		0.4	%	0.4	%
Expected term (in years)		3.5			3		2.9

As of December 31, 2013, unrecognized compensation costs related to unvested SARs was $4.5 million and will be recognized as stock-based compensation expense, net of amounts capitalized over a weighted-average period of 2.2 years.
Restricted Stock Awards and Units. The Company began issuing restricted stock awards in 2005 and restricted stock units in 2009. Although shares of common stock are not released to the employee until vesting, restricted stock awards have the right to vote and accordingly, restricted stock awards are considered issued and outstanding at the date of grant. Restricted stock units do not have the right to vote and are not considered issued and outstanding until converted into common shares and released to the employee upon vesting. The table below summarizes restricted stock award and unit activity for the years ended December 31, 2013, 2012 and 2011:


		Shares/			Weighted-Average Grant Date
		Units			Fair Value
For the Year Ended December 31, 2011
Unvested restricted stock awards and units, beginning of period		710,955			$20.26

Granted		567,901			$35.27

Vested		(452,585	)		$25.29
Forfeited		(25,773	)		$23.30
Unvested restricted stock awards and units, end of period		800,498			$27.96

For the Year Ended December 31, 2012
Unvested restricted stock awards and units, beginning of period		800,498			$27.96

Granted		854,292			$25.25

Vested		(488,992	)		$25.63
Forfeited		(19,524	)		$27.61
Unvested restricted stock awards and units, end of period		1,146,274			$26.95

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

As of December 31, 2013, unrecognized compensation costs related to unvested restricted stock awards and units was $25.2 million and will be recognized as stock-based compensation expense, net of amounts capitalized over a weighted-average period of 2.1 years. The 2013, 2012 and 2011 grants of certain restricted stock units contained performance and service conditions. The performance conditions have been met for all awards.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	10. Related Party Transactions
	Avista Utica Joint Venture. Effective September 2011, the Company’s wholly-owned subsidiary, Carrizo (Utica) LLC, entered into a joint venture in the Utica Shale with ACP II Marcellus LLC (“ACP II”), which is also one of our joint venture partners in the Marcellus Shale, and ACP III Utica LLC (“ACP III”), both affiliates of Avista Capital Partners, LP, a private equity fund (collectively with ACP II and ACP III, “Avista”). During the term of the Avista Utica joint venture, the joint venture partners acquired and sold acreage and we exercised options under the Avista Utica joint venture agreements to acquire acreage from Avista. The Avista Utica joint venture agreements were terminated on October 31, 2013 in connection with our purchase of certain ACP III assets discussed below.
	In October 2012, the Company sold substantially all of its interests in oil and gas properties dedicated to the Avista Utica joint venture in the northern portion of the Utica play to an unrelated third party. Simultaneously with the closing of this Utica transaction, Avista sold substantially all of its interests in the same oil and gas properties. In connection with these sale transactions, the Company elected to exercise its option to increase its participating interest in the same oil and gas properties on a “net proceeds basis” so that the Company received net proceeds with respect to 50% of the properties subject to the sale rather than the 10% the Company initially held. Pursuant to the terms of the Avista Utica joint venture agreement, as amended, the Company paid $24.0 million for the 40% additional interest in the acreage subject to the sale and certain other Avista Utica joint venture properties. Therefore, effective as of the closing, both parties owned the joint venture properties equally and both parties shared equally in their right to receive the proceeds from the purchaser. As a result of the reduction required for the $24.0 million option exercise price due from the Company and the repayment of other amounts owed between the two joint venture parties, the net proceeds received by the Company from the sale was $51.7 million and the net proceeds received by Avista from the sale was $74.9 million. Concurrently with the exercise and closing of the Company’s option to increase its participating interest in such oil and gas properties, its right to receive distributions associated with properties owned by ACP II in the Avista Utica joint venture through “B Units” interest in ACP II was terminated.
	Following the sale transactions described above, on October 24, 2012, the Company and Avista amended the Avista Utica joint venture agreements to provide that the expiration date of the Company’s remaining option to increase its participating interest in the Avista Utica joint venture properties was accelerated from March 2013 to January 15, 2013. The Company exercised this option on January 15, 2013 by paying $63.1 million for an additional 40% in the remaining Avista Utica joint venture properties. The Company and Avista also agreed that after the option was exercised, the Company’s participating interest in subsequently acquired properties within the then existing area of mutual interest continued to be 10% and Avista’s participating interest continued to be 90%, and the Company was granted an additional option to increase its 10% ownership in such subsequently acquired properties to 50% at 8.625% above acreage cost and associated improvements (compounded monthly following Avista’s contribution of purchase proceeds). Instead of exercising this option, the Company and Avista agreed that the Company could instead elect to acquire additional properties on an equal basis with Avista. In connection with the January 2013 exercise of the Company’s option to increase its participating interest in the Avista Utica joint venture properties, its right to receive distributions associated with properties owned by ACP III through “B Units” interest in ACP III that the Company acquired at the formation of the Utica joint venture was terminated.
	On October 31, 2013, the Company completed the acquisition of acreage located primarily in Guernsey and Noble counties, Ohio from Avista. This transaction had an effective date of July 1, 2013, and the Company paid Avista approximately $78.6 million in cash, subject to post-closing adjustments. Prior to the Company’s acquisition from ACP III, the properties in the Avista Utica joint venture were held on an equal basis by the Company and Avista. This transaction was initially funded with proceeds from the sale of the Company’s remaining oil and gas properties in the Barnett to EnerVest. After giving effect to this 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 agreement with Avista provide for limited areas of mutual interest around properties jointly owned by the Company and Avista.
	Avista Marcellus Joint Venture. Effective August 2008, Carrizo (Marcellus) LLC, a wholly owned subsidiary of the Company, entered into a joint venture arrangement with ACP II, an affiliate of Avista. In September 2010, the Company completed the sale of 20% of its interests in substantially all of its oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance. Simultaneously with the closing of this transaction, ACP II closed the sale of its entire interest in the same properties to Reliance for a purchase price of approximately $327.0 million. At the time of entering into the agreements for these transactions, the Company and Avista agreed that B Unit distributions to the Company with respect to Avista’s sale of properties to Reliance would be principally based upon Avista’s internal rates-of-return and return-on-investment thresholds associated with such properties, subject to amounts withheld from distribution by ACP II’s board. In connection with these sales transactions, the Company and Avista amended the participation agreement and other joint venture agreements with Avista to provide that the properties that the Company and Avista sold to Reliance, as well as the properties the Company committed to the new joint venture with Reliance, were no longer subject to the terms of the Avista Marcellus joint venture, and that the Avista Marcellus joint venture’s area of mutual interest would generally not include Pennsylvania, the state in which those properties were located. The Company’s joint venture with Avista continues, primarily in New York and West Virginia. Pursuant to the terms of the amended participation agreement, the areas of mutual interest with Avista have been reduced to specified halos around existing properties in New York and West Virginia.
	On November 16, 2010, Carrizo Marcellus assigned, via distribution and subsequent contribution, its interests in the Avista Marcellus joint venture to Carrizo (Marcellus) WV LLC (“Carrizo WV”), also a wholly owned subsidiary of the Company. In connection with the assignment, Carrizo Marcellus assigned to Carrizo WV its rights and obligations under the participation agreement, as well as the related joint operating agreement, pursuant to which operatorship of the Avista Marcellus joint venture was assumed by Carrizo WV. In addition, Carrizo WV and the other parties thereto amended and restated the participation agreement on November 16, 2010, effective as of October 1, 2010. This amended and restated participation agreement amends the participation agreement by, among other things, (i) providing fixed percentages and thresholds for sharing net cash flow from hydrocarbon production and proceeds from the sales of underlying joint venture properties and (ii) eliminating provisions that have been performed and are inapplicable going forward.
	The Company serves as operator of the properties covered by the Avista Marcellus joint venture under a joint operating agreement with Avista and also performs specified management services for ACP II. An operating committee composed of one representative of each party provides overall supervision and direction of joint operations. Avista or its designee has the right to become a co-operator of the properties if all of its membership interests or substantially all of its assets are sold to an unaffiliated third party or if the Company defaults under the terms of any pledge of its interest in the properties.
	Each party now has ability to transfer its interest in the Avista Marcellus joint venture to third parties subject in most instances to preferential purchase rights for transfers of less than 10% of a party’s interest in joint venture properties, and to “tag along” rights for most other transfers.
	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 as well as the Avista Transaction and the other acquisition transactions described above with Avista 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 in the Avista Transaction and generally in other transactions since the beginning of the last fiscal year, determined whether the transaction is desirable and in the best interest of the Company. In transactions prior to the recent Avista Transaction, the special committee has evaluated whether transactions are fair to the Company and its shareholders on the same basis as comparable arm’s length transactions. The committee has applied in the Avista Transaction, and may in other transactions also apply, standards under relevant debt agreements if required.
	Advances to and from Avista and Affiliates. At December 31, 2013, related party receivable and related party payable on the consolidated balance sheets included $6.6 million and $2.8 million, respectively, representing the net amount ACP II owes the Company related to activity within the Avista Marcellus joint venture and the net amount the Company owes ACP III related to activity within the Avista Utica joint venture, respectively. At December 31, 2012, related party receivable on the consolidated balance sheets included $9.8 million, representing the net amounts ACP II and ACP III owed the Company related to activity within the Avista Marcellus and Avista Utica joint ventures.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments	'
	11. Derivative Instruments
	The Company uses commodity derivative instruments, primarily fixed price swaps and costless collars, to reduce its exposure to commodity price volatility for a substantial, but varying, portion of its forecasted oil and gas production up to 60 months and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not enter into derivative contracts for speculative or trading purposes.
	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 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 at December 31, 2013 and 2012 totaled $9.3 million and $29.2 million, respectively and is summarized by counterparty in the table below:


	Counterparty	December 31, 2013			December 31, 2012
	Credit Suisse	46	%		40	%
	Societe Generale	31	%		22	%
	Wells Fargo	23	%		2	%
	BNP Paribas	—	%		33	%
	BBVA Compass	—	%		3	%
	Total	100	%		100	%
	Because the counterparties to the Company’s derivative instruments are high credit quality financial institutions that are lenders under the Company’s credit agreement, the Company believes it has minimal 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 financial viability of its counterparties. The fair value of derivative instruments where the Company is in a net liability position with its counterparties at December 31, 2013 and 2012 totaled $10.1 million and $0, respectively. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of the Company’s bank debt, which eliminates the potential need to post collateral when the Company is in a net derivative liability position.
	For the years ended December 31, 2013, 2012 and 2011, the Company recorded in the consolidated statements of income a loss on derivative instruments, net of $18.4 million and gains on derivative instruments, net of $31.4 million and $48.4 million, respectively.
	The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of December 31, 2013.


	Period	Type of Contract		Volume			Weighted		Weighted		Weighted Average		Weighted Average
				(in Bbls/d)			Average		Average		Short Put Price		Put Spread
							Floor Price		Ceiling Price		($/Bbl)		($/Bbl)
							($/Bbls)		($/Bbls)
	FY 2014	Swaps		7,500			$	92.59

		Collars		3,000			$	88.33	$	104.26

		Three-way collars		500			$	85	$	107.75	$	65	$	20

	FY 2015	Swaps		4,250			$	91.3

		Collars		700			$	90	$	100.65

		Three-way collars		1,000			$	85	$	105	$	65	$	20

	FY 2016	Three-way collars		667			$	85	$	104	$	65	$	20

	The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of December 31, 2013.


	Period	Type of Contract		Volume			Weighted		Weighted
				(in MMBtu/d)			Average		Average
							Floor Price		Ceiling Price
							($/MMBtu)		($/MMBtu)
	FY 2014	Swaps		45,000			$	4.09

		Collars		10,000					$	5.5

	FY 2015	Swaps		10,000			$	4.33

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	12. Fair Value Measurements
	Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
	Level 1 — Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
	Level 2 — Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
	Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012. All items included in the tables below are Level 2 inputs within the fair value hierarchy:



		31-Dec-13
		Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
		(In thousands)
	Derivative Assets
	Fair value of derivative instruments (current assets)	$	2,389		$	(2,389	)	$	—

	Fair value of derivative instruments (noncurrent asset)	11,709			(2,425		)	9,284

	Derivative Liabilities
	Fair value of derivative instruments (current liabilities)	(12,336		)	2,389			(9,947		)

	Fair value of derivative instruments (included in noncurrent other liabilities)	(2,613		)	2,425			(188		)

	Total	$	(851	)	$	—		$	(851	)



		December 31, 2012
		Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
		(In thousands)
	Derivative Assets
	Fair value of derivative instruments (current asset)	$	24,014		$	(33	)	$	23,981

	Fair value of derivative instruments (noncurrent asset)	6,778			(1,598		)	5,180

	Derivative Liabilities
	Fair value of derivative instruments (current liabilities)	(33		)	33			—

	Fair value of derivative instruments (included in noncurrent other liabilities)	(1,598		)	1,598			—

	Total	29,161			—			29,161

	The fair values of the Company’s derivative instruments are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including (a) quoted forward prices for oil and gas, (b) discount rates and (c) volatility factors. The estimates of fair value are also compared to the values provided by the counterparty 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 fair values reported in the consolidated balance sheets 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. 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 in the consolidated balance sheets. 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 Company had no transfers in or out of Levels 1 or 2 for the years ended December 31, 2013 and 2012.
	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. 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 following table presents the carrying amounts and fair values of the Company’s senior notes and convertible senior notes, based on quoted market prices, as of December 31, 2013 and 2012.


		December 31, 2013						December 31, 2012
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
		(In thousands)
	8.625% Senior Notes	$	595,822		$	644,978		$	595,151		$	645,000

	7.50% Senior Notes	300,000			327,000			300,000			308,250

	4.375% Convertible Senior Notes	4,425			4,115			72,657			73,842

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Condensed Consolidating Financial Information	'
	13. Condensed Consolidating Financial Information
	The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information as of December 31, 2013 and December 31, 2012, and for the three years ended December 31, 2013, 2012 and 2011 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


			31-Dec-13
			Parent			Combined			Combined				Eliminations				Consolidated
			Company			Guarantor			Non-
						Subsidiaries			Guarantor
									Subsidiaries
			(In thousands)
	ASSETS
	Current assets		$	1,820,069		$	168,718		$	—			$	(1,709,026	)		$	279,761

	Current assets held for sale		—			—			—				—				—

	Assets of discontinued operations		—			—			—				—				—

	Property and equipment, net		2,797			1,768,553			2,058				20,807				1,794,215

	Investment in subsidiaries		61,619			—			—				(61,619		)		—

	Long-term assets held for sale		—			—			—				—				—

	Other assets		69,686			—			—				(32,902		)		36,784

	Total assets		$	1,954,171		$	1,937,271		$	2,058			$	(1,782,740	)		$	2,110,760


	LIABILITIES AND SHAREHOLDERS’ EQUITY
	Current liabilities		$	190,550		$	1,828,314		$	2,061			$	(1,709,026	)		$	311,899

	Current liabilities associated with assets held for sale		—			—			—				—				—

	Current liabilities of discontinued operations		10,936			—			—				—				10,936

	Long-term liabilities		905,235			47,335			—				(23,585		)		928,985

	Long-term liabilities associated with assets held for sale		—			—			—				—				—

	Long-term liabilities of discontinued operations		17,336			—			—				—				17,336

	Shareholders’ equity		830,114			61,622			(3		)		(50,129		)		841,604

	Total liabilities and shareholders’ equity		$	1,954,171		$	1,937,271		$	2,058			$	(1,782,740	)		$	2,110,760



			December 31, 2012
			Parent			Combined			Combined				Eliminations				Consolidated
			Company			Guarantor			Non-
						Subsidiaries			Guarantor
									Subsidiaries
			(In thousands)
	ASSETS
	Current assets		$	1,689,430		$	130,487		$	—			$	(1,613,094	)		$	206,823

	Current assets held for sale		—			—			1,882				—				1,882

	Property and equipment, net		23,041			1,443,064			—				21,569				1,487,674

Investment in subsidiaries		14,588			—			—				(14,588		)		—

Long-term assets held for sale		12,670			—			119,956				—				132,626

Other assets		46,913			16,928			—				(8,850		)		54,991

Total assets		$	1,786,642		$	1,590,479		$	121,838			$	(1,614,963	)		$	1,883,996


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities		$	179,221		$	1,631,887		$	—			$	(1,560,853	)		$	250,255

Current liabilities associated with assets held for sale		9,880			—			38,783				—				48,663

Long-term liabilities		973,003			3,512			—				—				976,515

Long-term liabilities associated with assets held for sale		—			—			23,547				—				23,547

Shareholders’ equity		624,538			(44,920		)	59,508				(54,110		)		585,016

Total liabilities and shareholders’ equity		$	1,786,642		$	1,590,479		$	121,838			$	(1,614,963	)		$	1,883,996

CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME


		For the Year Ended December 31, 2013
		Parent			Combined			Combined				Eliminations				Consolidated
		Company			Guarantor			Non-
					Subsidiaries			Guarantor
								Subsidiaries
		(In thousands)
Oil and gas revenues		$	6,490		$	513,692		$	—			$	—			$	520,182

Costs and expenses		82,282			284,076			3				762				367,123

Loss on sale of oil and gas properties		—			45,377			—				—				45,377

Operating income (loss)		(75,792		)	184,239			(3		)		(762		)		107,682

Other income (expense), net		(52,592		)	(20,329		)	—				—				(72,921		)

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 (loss) of subsidiaries		106,538			—			—				(106,538		)		—

Net income (loss) from continuing operations		23,088			106,541			(3		)		(107,768		)		21,858

Net income from discontinued operations, net of income taxes		21,825			—			—				—				21,825

Net income (loss)		$	44,913		$	106,541		$	(3	)		$	(107,768	)		$	43,683



		For the Year Ended December 31, 2012
		Parent			Combined			Combined				Eliminations				Consolidated
		Company			Guarantor			Non-
					Subsidiaries			Guarantor
								Subsidiaries
		(In thousands)
Oil and gas revenues		$	20,195		$	347,985		$	—			$	—			$	368,180

Costs and expenses		76,839			205,341			—				(12,653		)		269,527

Operating income (loss)		(56,644		)	142,644			—				12,653				98,653

Other income (expense), net		20,022			(36,542		)	—				—				(16,520		)

Income (loss) from continuing operations before income taxes		(36,622		)	106,102			—				12,653				82,133

Income tax (expense) benefit		12,658			(37,136		)	—				(6,478		)		(30,956		)

Equity in income (loss) of subsidiaries		73,150			—			—				(73,150		)		—

Net income (loss) from continuing operations		49,186			68,966			—				(66,975		)		51,177

Net income from discontinued operations, net of income taxes		126			—			4,184				—				4,310

Net income (loss)		$	49,312		$	68,966		$	4,184			$	(66,975	)		$	55,487



		For the Year Ended December 31, 2011
		Parent			Combined			Combined				Eliminations				Consolidated
		Company			Guarantor			Non-
					Subsidiaries			Guarantor
								Subsidiaries
		(In thousands)
Oil and gas revenues		$	31,875		$	170,292		$	—			$	—			$	202,167

Costs and expenses		68,652			100,255			—				(4,891		)		164,016

Operating income (loss)		(36,777		)	70,037			—				4,891				38,151

Other income (expense), net		41,182			(21,188		)	—				—				19,994

Income (loss) from continuing operations before income taxes		4,405			48,849			—				4,891				58,145

Income tax (expense) benefit		(1,209		)	(22,612		)	—				(1,790		)		(25,611		)

Equity in income (loss) of subsidiaries		29,319			—			—				(29,319		)		—

Net income (loss) from continuing operations		32,515			26,237			—				(26,218		)		32,534

Net loss from discontinued operations, net of income taxes		1,013			—			3,082				—				4,095

Net income (loss)		$	33,528		$	26,237		$	3,082			$	(26,218	)		$	36,629

CARRIZO OIL & GAS, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


		For the Year Ended December 31, 2013
		Parent			Combined			Combined				Eliminations				Consolidated
		Company			Guarantor			Non-
					Subsidiaries			Guarantor
								Subsidiaries
		(In thousands)
Net cash provided by operating activities - continuing operations		$	(55,888	)	$	423,366		$	(4	)		$	—			$	367,474

Net cash used in investing activities - continuing operations		(86,322		)	(513,710		)	(2,057		)		92,204				(509,885		)

Net cash provided by financing activities - 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



		For the Year Ended December 31, 2012
		Parent			Combined			Combined				Eliminations				Consolidated
		Company			Guarantor			Non-
					Subsidiaries			Guarantor
								Subsidiaries
		(In thousands)
Net cash provided by operating activities - continuing operations		$	75,546		$	177,525		$	—			$	—			$	253,071

Net cash provided by (used in) investing activities - continuing operations		(280,564		)	(493,145		)	—				308,558				(465,151		)

Net cash provided by (used in) financing activities - continuing operations		237,778			308,558			—				(308,558		)		237,778

Net cash used in discontinued operations		—			—			(1,196		)		—				(1,196		)

Net increase (decrease) in cash and cash equivalents		32,760			(7,062		)	(1,196		)		—				24,502

Cash and cash equivalents, beginning of year		19,134			7,263			1,715				—				28,112

Cash and cash equivalents, end of year		$	51,894		$	201		$	519			$	—			$	52,614



		For the Year Ended December 31, 2011
		Parent			Combined			Combined				Eliminations				Consolidated
		Company			Guarantor			Non-
					Subsidiaries			Guarantor
								Subsidiaries
		(In thousands)
Net cash provided by operating activities - continuing operations		$	56,563		$	98,948		$	—			$	—			$	155,511

Net cash provided by (used in) investing activities - continuing operations		(194,689		)	(356,168		)	—				300,789				(250,068		)

Net cash provided by (used in) financing activities - continuing operations		155,842			261,773			—				(300,789		)		116,826

Net cash provided by discontinued operations		—			—			1,715				—				1,715

Net increase in cash and cash equivalents		17,716			4,553			1,715				—				23,984

Cash and cash equivalents, beginning of year		1,418			2,710			—				—				4,128

Cash and cash equivalents, end of year		$	19,134		$	7,263		$	1,715			$	—			$	28,112

Supplemental_Disclosures_About

Supplemental Disclosures About Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Supplemental Disclosures About Oil And Gas Producing Activities	'
	14. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited)
	At December 31, 2013, the Company’s oil and gas properties are located in the U.S. At December 31, 2012 and 2011, the Company’s oil and gas properties were located in the U.S. and U.K. North Sea. All information presented as “U.K.” in this footnote relates to the U.K. North Sea 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:


			Year Ended December 31,
			2013				2012				2011
			(In thousands)
	U.S.
	Unproved property acquisition costs		$	254,099			$	139,344			$	108,212

	Exploration costs		106,329				211,289				270,688

	Development costs		423,871				374,391				126,816

	Total costs incurred		$	784,299			$	725,024			$	505,716

	U.K.
	Unproved property acquisition costs		$	—			$	11,135			$	1,004

	Exploration costs		—				—				—

	Development costs		—				36,261				41,424

	Total costs incurred		$	—			$	47,396			$	42,428

	Total Worldwide
	Unproved property acquisition costs		$	254,099			$	150,479			$	109,216

	Exploration costs		106,329				211,289				270,688

	Development costs		423,871				410,652				168,240

	Total costs incurred		$	784,299			$	772,420			$	548,144

	Costs incurred excludes capitalized interest on U.S. unproved properties of $29.9 million, $24.8 million, and $23.4 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company, L.P. Proved oil and gas reserve quantities at December 31, 2012 and 2011, and the related discounted future net cash flows before income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd., Ryder Scott Company, L.P., and Fairchild and Wells, Inc. 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, 2011		10,631			5,263			15,894			12,579			—		12,579

	Extensions and discoveries		16,978			—			16,978			426			—		426

	Revisions of previous estimates		103			174			277			(174	)		—		(174	)

	Sales of reserves in place		(1,809	)		—			(1,809	)		(8,501	)		—		(8,501	)

	Production		(802	)		—			(802	)		(209	)		—		(209	)

	31-Dec-11		25,101			5,437			30,538			4,121			—		4,121

	Extensions and discoveries		15,403			—			15,403			1,750			—		1,750

	Revisions of previous estimates		1,760			(196	)		1,564			740			—		740

	Sales of reserves in place		(327	)		—			(327	)		(923	)		—		(923	)

Production		(2,862	)		—			(2,862	)		(305	)		—		(305	)

31-Dec-12		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	)

31-Dec-13		62,041			—			62,041			8,152			—		8,152


Proved developed reserves:
31-Dec-11		6,803			2,719			9,522			1,186			—		1,186

31-Dec-12		12,675			5,241			17,916			1,620			—		1,620

31-Dec-13		18,321			—			18,321			2,779			—		2,779


Proved undeveloped reserves:
31-Dec-11		18,298			2,718			21,016			2,935			—		2,935

31-Dec-12		26,400			—			26,400			3,763			—		3,763

31-Dec-13		43,720			—			43,720			5,373			—		5,373

Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following:


2013	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation; Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.
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.
2011	Sales of U.S. properties to KKR during the second quarter and GAIL during 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, 2011		665,167			4,684			669,851			134,071			6,044		140,115

Extensions and discoveries		221,544			—			221,544			54,328			—		54,328

Revisions of previous estimates		(41,990	)		154			(41,836	)		(7,069	)		199		(6,870	)

Sales of reserves in place		(82,884	)		—			(82,884	)		(24,124	)		—		(24,124	)

Production		(38,990	)		—			(38,990	)		(7,509	)		—		(7,509	)

31-Dec-11		722,847			4,838			727,685			149,697			6,243		155,940

Extensions and discoveries		72,916			—			72,916			29,305			—		29,305

Revisions of previous estimates		(20,996	)		(174	)		(21,170	)		(999	)		(225	)	(1,224	)
Sales of reserves in place		(313,483	)		—			(313,483	)		(53,497	)		—		(53,497	)

Production		(37,612	)		—			(37,612	)		(9,436	)		—		(9,436	)

31-Dec-12		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	)

31-Dec-13		187,957			—			187,957			101,519			—		101,519


Proved developed reserves:
31-Dec-11		389,795			2,419			392,214			72,955			3,122		76,077

31-Dec-12		229,539			4,664			234,203			52,552			6,018		58,570

31-Dec-13		106,976			—			106,976			38,929			—		38,929


Proved undeveloped reserves:
31-Dec-11		333,052			2,419			335,471			76,742			3,121		79,863

31-Dec-12		194,134			—			194,134			62,519			—		62,519

31-Dec-13		80,981			—			80,981			62,590			—		62,590

Natural gas extensions and discoveries are primarily attributable to the following:


2013	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford.
2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford.
2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford. Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.
Natural gas revisions of previous estimates are primarily attributable to the following:


2013	Positive price revisions in the U.S. primarily in the Barnett and Marcellus.
2012	Negative price revisions in the U.S. primarily in the Barnett.
2011	Negative price revisions in the U.S. primarily in the Barnett.
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.
2012	Sales of properties to Atlas during the second quarter and sale of Gulf Coast properties during the third quarter.
2011	Sales of properties to KKR during the second quarter and GAIL during the third quarter.
Standardized Measure
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:


		U.S.				U.K.				Worldwide
		(In thousands)
2011
Future cash inflows		$	4,834,725			$	617,667			$	5,452,392

Future production costs		(1,212,722		)		(95,229		)		(1,307,951		)
Future development costs		(1,163,377		)		(43,954		)		(1,207,331		)
Future income taxes		(477,824		)		(246,273		)		(724,097		)
Future net cash flows		1,980,802				232,211				2,213,013

Less 10% annual discount to reflect timing of cash flows		(1,124,339		)		(47,638		)		(1,171,977		)
Standard measure of discounted future net cash flows		$	856,463			$	184,573			$	1,041,036

2012
Future cash inflows		$	4,960,687			$	623,678			$	5,584,365

Future production costs		(1,009,850		)		(87,727		)		(1,097,577		)
Future development costs		(982,101		)		(11,194		)		(993,295		)
Future income taxes		(511,790		)		(252,493		)		(764,283		)
Future net cash flows		2,456,946				272,264				2,729,210

Less 10% annual discount to reflect timing of cash flows		(1,277,463		)		(33,352		)		(1,310,815		)
Standard measure of discounted future net cash flows		$	1,179,483			$	238,912			$	1,418,395

2013
Future cash inflows		$	6,936,276			$	—			$	6,936,276

Future production costs		(1,629,663		)		—				(1,629,663		)

Future development costs		(1,340,722		)		—				(1,340,722		)

Future income taxes		(835,840		)		—				(835,840		)

Future net cash flows		3,130,051				—				3,130,051

Less 10% annual discount to reflect timing of cash flows		(1,508,640		)		—				(1,508,640		)

Standard measure of discounted future net cash flows		$	1,621,411			$	—			$	1,621,411

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 2013, 2012 and 2011 were $99.44, $102.03, and $95.28 per barrel, respectively, for crude oil and condensate, $25.60, $32.12 and $44.90 per barrel, respectively, for natural gas liquids, and $2.97, $2.08 and $3.24 per Mcf, respectively, for natural gas.
Future operating expenses 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, 2011		$	654,684			$	94,102			$	748,786

Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		134,952				128,525				263,477

Net change in estimated future development costs		(509		)		(4,144		)		(4,653		)
Net change due to revisions in quantity estimates		(64,860		)		13,078				(51,782		)

Accretion of discount		81,225				19,399				100,624

Changes in production rates (timing) and other		(78,199		)		(16,094		)		(94,293		)
Total revisions		72,609				140,764				213,373

Net change due to extensions and discoveries, net of estimated future development and production costs		508,558				—				508,558

Net change due to sales of minerals in place		(150,437		)		—				(150,437		)

Sales of oil and gas produced, net of production costs		(173,853		)		—				(173,853		)

Previously estimated development costs incurred		5,381				39,779				45,160

Net change in income taxes		(60,479		)		(90,072		)		(150,551		)
Net change in standardized measure of discounted future net cash flows		201,779				90,471				292,250

Standardized measure — December 31, 2011		$	856,463			$	184,573			$	1,041,036

Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		(55,249		)		49,719				(5,530		)

Net change in estimated future development costs		91,404				—				91,404

Net change due to revisions in quantity estimates		(77,919		)		(46,803		)		(124,722		)
Accretion of discount		107,451				37,453				144,904

Changes in production rates (timing) and other		(3,369		)		(6,061		)		(9,430		)
Total revisions		62,318				34,308				96,626

Net change due to extensions and discoveries, net of estimated future development and production costs		599,544				—				599,544

Net change due to sales of minerals in place		(212,910		)		—				(212,910		)

Sales of oil and gas produced, net of production costs		(313,354		)		—				(313,354		)

Previously estimated development costs incurred		202,187				32,760				234,947

Net change in income taxes		(14,765		)		(12,729		)		(27,494		)
Net change in standardized measure of discounted future net cash flows		323,020				54,339				377,359

Standardized measure — December 31, 2012		$	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

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Selected Quarterly Financial Data	'
	15. Selected Quarterly Financial Data (Unaudited)
	The following table presents selected quarterly financial data for the years ended December 31, 2013 and 2012:


	2013	First			Second		Third			Fourth
		(In thousands, except per share amounts)
	Oil and gas revenues	$	111,901		$	134,224	$	144,329		$	129,728

	Operating income (loss)	33,463			46,618		48,603			(21,002		)	-2

	Net income (loss) from continuing operations	2,524			35,837		5,712			(22,215		)

	Net income (loss)	$	26,182	-1	$	36,969	$	4,521		$	(23,989	)	-2


	Net income (loss) per share - basic
	Net income (loss) from continuing operations	$	0.06		$	0.89	$	0.14		$	(0.52	)	-2

	Net income (loss) per share	0.66		-1	0.92		0.11			(0.56		)	-2


	Net income (loss) per share - diluted
	Net income (loss) from continuing operations	$	0.06		$	0.88	$	0.14		$	(0.52	)	-2

	Net income (loss) per share	0.65		-1	0.91		0.11			(0.56		)	-2



	2012	First			Second		Third			Fourth
		(In thousands, except per share amounts)
	Oil and gas revenues	$	80,715		$	83,818	$	96,197		$	107,450

	Operating income	22,380			14,806		24,318			37,151

	Net income (loss) from continuing operations	10,676			25,683		(1,945		)	16,763

	Net income (loss)	$	9,423		$	28,504	$	(930	)	$	18,490


	Net income (loss) per share - basic
	Net income (loss) from continuing operations	$	0.27		$	0.65	$	(0.05	)	$	0.42

	Net income (loss) per share	0.24			0.72		(0.02		)	0.47


	Net income (loss) per share - diluted
	Net income (loss) from continuing operations	$	0.27		$	0.64	$	(0.05	)	$	0.42

	Net income (loss) per share	0.24			0.71		(0.02		)	0.46





	-1	First quarter 2013 results include the impact of pre-tax gain of $37.3 million related to the sale of the Company’s U.K. North Sea assets which were reported as discontinued operations.

	-2	Fourth quarter 2013 results include the impact of a pre-tax loss of $45.4 million related to the sale of the Company’s remaining oil and gas properties in the Barnett.
	The sum of the quarterly net income (loss) per common share may not agree with the total year net income (loss) per common share as each quarterly computation is based on the net income (loss) for each period and the weighted average common shares outstanding during each period. Previously reported amounts have been reclassified to conform to the presentation of the U.K. North Sea assets as discontinued operations.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2013

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 all significant 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. These reclassifications had no effect on total assets, total liabilities, total shareholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.

Discontinued Operations

On December 27, 2012, the Company agreed to sell Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all of its interest in the Huntington Field discovery, where Carrizo UK owned a 15% non-operated working interest and certain overriding royalty interests. The sale closed on February 22, 2013. Accordingly, the Company classified the U.K. North Sea assets and associated liabilities as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in the consolidated balance sheets as of December 31, 2012. As of December 31, 2013, the Company classified the remaining liabilities associated with the U.K. North Sea as current and long-term liabilities of discontinued operations in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations in the consolidated statements of income, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relates to the Company’s continuing operations. Information related to discontinued operations is included in “Note 3. Discontinued Operations”, “Note 13. Condensed Consolidating Financial Information” and “Note 14. 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 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 the amortization 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 impairments of unevaluated leasehold costs, fair values of derivative instruments, stock-based compensation expense attributable to stock appreciation rights, 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 and cash equivalents include highly liquid investments with original maturities of three months or less.

Accounts Receivable And Allowance For Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

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. At December 31, 2013 and 2012, the Company’s allowance for doubtful accounts was $0.6 million and $1.4 million, respectively.

Concentration Of Credit Risk

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third-party working interest owners in the oil and gas industry or development advances to third-party operators for drilling and completion costs of wells in progress. This concentration of customers and joint interest owners 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. The Company generally has the right to offset revenue against related billings to joint interest owners.

Derivative instruments subject the Company to a concentration of credit risk. See “Note 11. Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments.

Major Customers

In 2013, two customers accounted for approximately 47% and 23% of the Company’s oil and gas revenues. In 2012, two customers accounted for approximately 53% and 10% of the Company’s oil and gas revenues. In 2011, one customer accounted for approximately 43% of the Company’s oil and gas revenues.

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. Internal costs, consisting of compensation and benefits, including stock-based compensation, associated with employees directly associated with acquisition, exploration and development activities are capitalized and totaled $15.0 million, $11.8 million and $9.6 million for the years ended December 31, 2013, 2012 and 2011, 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 rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter then applying such amount 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 depreciation, depletion and amortization (“DD&A”) per Boe was $21.38, $17.55 and $11.26 for the years ended December 31, 2013, 2012 and 2011, 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. Significant costs of unevaluated properties and exploratory wells in progress are assessed individually 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 unproved properties within the next five years and exploratory wells in progress within the next year. The costs of individually insignificant unevaluated leaseholds are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease term of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs and exploratory wells in progress of $29.9 million, $24.8 million and $23.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated leasehold and seismic costs and the average balance of exploratory wells in progress using a weighted-average interest rate based on outstanding borrowings.

Proceeds from the sale of proved oil and gas properties or unevaluated leasehold costs 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. 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 income. 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 income in the fourth quarter of 2013. Other than the sales noted above, the Company has not had any sales that significantly altered the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center through December 31, 2013.

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 increase the cost center ceiling applicable to the subsequent period.

The estimated future net revenues used in the ceiling test 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 used in the ceiling test computation 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.

Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from five to ten years.

Deferred Financing Costs

Deferred financing costs, net were $22.9 million and $23.9 million as of December 31, 2013 and 2012, respectively and include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of debt securities and costs associated with the revolving credit facility. The capitalized costs are amortized to interest expense using the effective interest method over the terms of the debt securities or credit facility.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative instruments 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 instruments are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including (a) quoted forward prices for oil and gas, (b) discount rates and (c) volatility factors. The carrying amounts of long-term debt under the Company’s revolving credit facility approximate fair value as the borrowings bear interest at variable rates of interest. The carrying amounts of the Company’s senior notes and convertible senior notes may not approximate fair value because the notes bear interest at fixed rates of interest. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.”

Asset Retirement Obligations

The Company’s asset retirement obligations represent the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of production equipment and facilities and restoring the surface of the land in accordance with the terms of the oil and gas lease 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 the oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. The asset retirement obligation is 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 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 an interim 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 obligation 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 the abandonment of oil and gas wells.

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.

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 oil and gas 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, 2013 and 2012, the Company did not have any material production imbalances.

Derivative Instruments

The Company uses commodity derivative instruments, primarily fixed price swaps and costless collars, to manage its exposure to commodity price risk. 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. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company 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 derivative instruments, net in the consolidated statements of income 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 in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes.

The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. 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. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. See “Note 11. Derivative Instruments” for further discussion of the Company’s derivative instruments.

Stock-Based Compensation

The Company has granted stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock at the option of the Company, SARs that may only be settled in cash, restricted stock awards and units to directors, employees and independent contractors. The Company recognized the following stock-based compensation expense, net of amounts capitalized for the periods indicated which is reflected as general and administrative expense in the consolidated statements of income:

Year Ended December 31,

2013

2012

2011

(In thousands)

Stock appreciation rights

17,303

(2,116

)

1,546

Restricted stock awards and units

18,997

17,049

13,965

36,300

14,933

15,511

Less: amounts capitalized

(6,927

)

(3,244

)

(3,647

)

Stock-based compensation expense, net of amounts capitalized

29,373

11,689

11,864

Income Tax Benefit

10,281

4,449

4,342

Stock Options and SARs. For stock options and for SARs that the Company may elect to settle in cash or common stock, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally three years). For SARs that the Company has elected to settle in cash or SARs that may only be settled in cash, stock-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as other accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as long-term other liabilities. Subsequent to vesting, the liability for SARs that the Company expects to settle in cash is remeasured in earnings at each reporting period based on the fair value until the awards are settled. The Company recognizes stock-based compensation expense over the vesting period for stock options and SARs using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Stock options typically expire ten years after the date of grant. SARs typically expire between four and seven years after the date of grant.

The Company uses the Black-Scholes-Merton option pricing model to compute the fair value of stock options and SARs, which requires 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.

•

The expected term is based on historical exercises for various groups of directors, employees and independent contractors.

Restricted Stock Awards and Units. For restricted stock awards and units, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally one to three years) using the straight-line method, except for award or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted stock awards and units is based on the price of the Company’s common stock on the grant date. 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.

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. The Company classifies interest and penalties associated with income taxes as interest expense.

Net Income (Loss) Per Common Share

Net Income From Continuing Operations Per Common Share

Supplemental net income from continuing operations per common share information is provided below:

Year Ended December 31,

2013

2012

2011

(In thousands, except per share amounts)

Net income from continuing operations

21,858

51,177

32,534

Basic weighted average common shares outstanding

40,781

39,591

39,077

Effect of dilutive instruments

574

435

591

Diluted weighted average shares outstanding

41,355

40,026

39,668

Net income from continuing operations per common share

Basic

0.54

1.29

0.83

Diluted

0.53

1.28

0.82

Basic net income from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted net income 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 period which include restricted stock awards and units, stock options, SARs that the Company may elect to settle in cash or common stock, SARs the Company has elected to settle in common stock, warrants and convertible debt. The Company excludes the number of shares, units, options, rights 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 corresponding period as the effect would be antidilutive to the computation. The number of shares, units, options, rights and warrants excluded for the years ended December 31, 2013, 2012 and 2011 were not significant. Shares of common stock subject to issuance upon the conversion of the Company’s convertible senior notes did not have an effect on the calculation of dilutive shares for the years ended December 31, 2013, 2012 and 2011 because the conversion price was in excess of the market price of the common stock for those periods

Recently Adopted Accounting Pronouncements

Effective January 1, 2013, the Company adopted the provisions of ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, and began providing enhanced disclosures regarding the effect or potential effect of netting arrangements on an entity’s financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The Company adopted this new disclosure requirement effective January 1, 2013. The adoption did not have a material effect on the Company’s consolidated financial statements.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Schedule Of Stock-Based Compensation Expense	'
	The Company recognized the following stock-based compensation expense, net of amounts capitalized for the periods indicated which is reflected as general and administrative expense in the consolidated statements of income:


		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Stock appreciation rights	$	17,303		$	(2,116	)	$	1,546

	Restricted stock awards and units	18,997			17,049			13,965

		36,300			14,933			15,511

	Less: amounts capitalized	(6,927		)	(3,244		)	(3,647		)
	Stock-based compensation expense, net of amounts capitalized	$	29,373		$	11,689		$	11,864

	Income Tax Benefit	$	10,281		$	4,449		$	4,342

Schedule Of Supplemental Net Income Per Common Share	'
	Supplemental net income from continuing operations per common share information is provided below:


		Year Ended December 31,
		2013			2012			2011
		(In thousands, except per share amounts)
	Net income from continuing operations	$	21,858		$	51,177		$	32,534

	Basic weighted average common shares outstanding	40,781			39,591			39,077

	Effect of dilutive instruments	574			435			591

	Diluted weighted average shares outstanding	41,355			40,026			39,668

	Net income from continuing operations per common share
	Basic	$	0.54		$	1.29		$	0.83

	Diluted	$	0.53		$	1.28		$	0.82

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
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 net income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of income for the years ended December 31, 2013, 2012 and 2011:


		For the Years Ended December 31,
		2013			2012			2011
		(In thousands)
	OIL AND GAS REVENUES	$	—		$	—		$	—

	COSTS AND EXPENSES
	General and administrative	916			62			242

	Accretion related to asset retirement obligations	36			363			76

	TOTAL COST AND EXPENSES	952			425			318

	OPERATING LOSS	(952		)	(425		)	(318		)
	OTHER INCOME AND EXPENSES
	Gain on sale of discontinued operations	37,294			—			—

	Adjustment of estimated future obligations	(44		)	—			—

	Gain (loss) on derivative instruments, net	(109		)	258			(1,432		)

	Interest expense	(253		)	(3,556		)	(1,805		)
	Capitalized interest	253			3,556			—

	Other income (expense), net	438			(591		)	259

	INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	36,627			(758		)	(3,296		)

	DEFERRED INCOME TAX (EXPENSE) BENEFIT	(14,802		)	5,068			7,391

	NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	21,825		$	4,310		$	4,095

Property_And_Equipment_Net_Tab

Property And Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Schedule Of Property And Equipment	'
	At December 31, 2013 and 2012, property and equipment, net consisted of the following:


		December 31,
		2013			2012
		(In thousands)
	Proved oil and gas properties	$	2,182,226		$	1,713,827

	Accumulated depreciation, depletion and amortization	(773,742		)	(561,279		)
	Proved oil and gas properties, net	1,408,484			1,152,548

	Unproved properties, not being amortized
	Unevaluated leasehold and seismic costs	302,232			238,833

	Exploratory wells in progress	30,196			43,803

	Capitalized interest	45,009			41,052

	Total unproved properties, not being amortized	377,437			323,688

	Other property and equipment	15,260			17,079

	Accumulated depreciation	(6,966		)	(5,641		)
	Other property and equipment, net	8,294			11,438

	Total property and equipment, net	$	1,794,215		$	1,487,674

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule Of Components Of Income Tax (Expense) Benefit	'
	The components of income tax expense from continuing operations were as follows:


		Year Ended December 31,
		2013			2012			2011
					(In thousands)
	Current income tax (expense) benefit
	U.S. Federal	$	411		$	(411	)	$	(404	)

	State	(141		)	(403		)	(661		)
	Total current income tax (expense) benefit	270			(814		)	(1,065		)

	Deferred income tax expense
	U.S. Federal	(12,404		)	(28,723		)	(23,254		)
	State	(769		)	(1,419		)	(1,292		)
	Total deferred income tax expense	(13,173		)	(30,142		)	(24,546		)
	Total income tax expense from continuing operations	$	(12,903	)	$	(30,956	)	$	(25,611	)
Schedule Of Effective Income Tax Rate Reconciliation	'
	The Company’s income tax expense from continuing operations differs from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of 35% to income from continuing operations before income taxes as follows:


		Year Ended December 31,
		2013			2012			2011
					(In thousands)
	Income from continuing operations before income taxes	$	34,761		$	82,133		$	58,145

	Income tax expense at the statutory rate	(12,166		)	(28,747		)	(20,350		)
	State income taxes, net of U.S. federal income tax benefit	(859		)	(1,681		)	(1,722		)
	Adjustment to prior period state income taxes, net of U.S. federal income tax benefit	—			—			(4,735		)

	Previously unbenefitted capital loss associated with investment				—			1,171

	Nondeductible expenses	—			(93		)	25

	Other	122			(435		)	—

	Total income tax expense from continuing operations	$	(12,903	)	$	(30,956	)	$	(25,611	)
Schedule Of Deferred Tax Assets And Liabilities	'
	At December 31, 2013 and 2012, deferred tax assets and liabilities are comprised of the following:


		December 31,
		2013			2012
		(In thousands)
	Deferred income tax assets
	Net operating loss carryforward - U.S. Federal and State	$	52,499		$	53,648

	Stock-based compensation	7,563			4,245

	Allowance for doubtful accounts	170			476

	Fair value of derivative instruments	3,222			—

	Other	2,471			1,755

	Deferred income tax assets	65,925			60,124

	Valuation allowance	(1,084		)	(1,188		)
	Net deferred income tax assets	64,841			58,936

	Deferred income tax liabilities
	Unamortized discount on 4.375% Convertible Senior Notes	—			(382		)

	Oil and gas properties	(74,247		)	(34,985		)
	Fair value of derivative instruments	(3,249		)	(10,222		)
		(77,496		)	(45,589		)
	Net deferred income tax asset (liability)	$	(12,655	)	$	13,347

Schedule Of Net Deferred Income Assets And Liabilities	'
	At December 31, 2013 and 2012, the net deferred income tax asset (liability) is classified as follows:


		December 31,
		2013			2012
		(In thousands)
	Noncurrent deferred income tax asset (liability)	$	(16,856	)	$	21,272

	Current deferred income tax asset (liability)	4,201			(7,925		)

	Net deferred income tax asset (liability)	$	(12,655	)	$	13,347

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule Of Debt	'
	At December 31, 2013 and 2012, long-term debt consisted of the following:


		December 31,
		2013			2012
		(In thousands)
	8.625% Senior Notes	$	600,000		$	600,000

	Unamortized discount for 8.625% Senior Notes	(4,178		)	(4,849		)
	7.50% Senior Notes	300,000			300,000

	4.375% Convertible Senior Notes	4,425			73,750

	Unamortized discount for 4.375% Convertible Senior Notes	—			(1,093		)

	Senior Secured Revolving Credit Facility	—			—

		$	900,247		$	967,808

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012:


		Year Ended December 31,
		2013			2012
		(In thousands)
	Asset retirement obligations at beginning of period	$	6,159		$	8,324

	Liabilities incurred	3,348			1,573

	Liabilities settled	(498		)	(1,666		)
	Reduction due to sales of oil and gas properties	(2,473		)	(3,272		)
	Accretion expense	471			372

	Revisions of previous estimates	349			828

	Asset retirement obligations at end of period	7,356			6,159

	Asset retirement obligations due within one year included in “Other accrued liabilities”	(780		)	(1,670		)
	Long-term asset retirement obligations	$	6,576		$	4,489

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013, total minimum commitments from long-term, non-cancelable operating leases, drilling rigs, completion services and pipeline volume commitments are as shown in the table below. The total minimum commitments related to the drilling rigs, completion services, and pipeline volume commitments 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.


		Amount
		(In thousands)
	2014	$	51,840

	2015	19,429

	2016	7,404

	2017	4,711

	2018	4,686

	2019 and thereafter	16,128

	Total	$	104,198

Shareholders_Equity_And_Stock_1

Shareholders' Equity And Stock Incentive Plan Shareholders' Equity And Stock Incentive Plan (Tables)	12 Months Ended
	Dec. 31, 2013
Shareholders' Equity And Stock Incentive Plan [Abstract]	'
Summary Of Stock Options Activity	'
	Stock Options. No stock options were granted under the Incentive Plan during 2013, 2012 or 2011. The table below summarizes the activity for stock options for the three years ended December 31, 2013, 2012 and 2011:


		Shares		Weighted-		Weighted-		Aggregate
				Average		Average		Intrinsic Value
				Exercise		Remaining Life		(In millions)
				Prices		(In years)
	For the Year Ended December 31, 2011
	Outstanding, beginning of period	414,854		$6.10

	Granted	—		—

	Exercised	(151,500	)	$4.36
	Forfeited	—		—

	Outstanding, end of period	263,354		$7.11

	Exercisable, end of period	263,354		$7.11

	For the Year Ended December 31, 2012
	Outstanding, beginning of period	263,354		$7.11

	Granted	—		—

	Exercised	(20,500	)	$5.50
	Forfeited	—		—

	Outstanding, end of period	242,854		$7.24

	Exercisable, end of period	242,854		$7.24

	For the Year Ended December 31, 2013
	Outstanding, beginning of period	242,854		$7.24

	Granted	—		—

	Exercised	(206,501	)	$6.07
	Forfeited	—		—

	Outstanding, end of period	36,353		$13.91		1.1		$1.10

	Exercisable, end of period	36,353		$13.91		1.1		$1.10

Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity	'
	The table below summarizes the activity for SARs for the three years ended December 31, 2013, 2012 and 2011:


		Shares		Weighted-		Weighted-			Aggregate
				Average		Average			Intrinsic Value
				Exercise		Remaining Life			(In millions)
				Prices		(In years)
	For the Year Ended December 31, 2011
	Outstanding, beginning of period	700,749		$18.50

	Granted	153,801		$37.99

	Exercised	(4,768	)	$20.22
	Forfeited	—		—

	Outstanding, end of period	849,782		$22.02

	Exercisable, end of period	326,128		$18.99

	For the Year Ended December 31, 2012
	Outstanding, beginning of period	849,782		$22.02

	Granted	193,336		$25.56

	Exercised	(7,295	)	$20.22
	Forfeited	—		—

	Outstanding, end of period	1,035,823		$22.69

	Exercisable, end of period	613,934		$20.70

	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
	Forfeited	(24,704	)	$27.77
	Outstanding, end of period	1,086,231		$24.78		2.8	21.12		$21.10

	Exercisable, end of period	681,867		$22.55		2.7	14.78		$14.80

Schedule of Share-based Payment Award, Non-Options, Valuation Assumptions	'
	The following table summarizes the weighted-average assumptions used in the Black-Scholes-Merton option pricing model to calculate the fair value of the SARs granted during 2013, 2012 and 2011:


		31-Dec-13		31-Dec-12		31-Dec-11
	Grant date fair value	$13.36		$12.23		$18.50
	Volatility factor	44.5	%	48.2	%	61.6	%
	Dividend yield	—	%	—	%	—	%
	Risk-free interest rate	1	%	0.4	%	0.4	%
	Expected term (in years)	3.5		3		2.9

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, 2013, 2012 and 2011:


		Shares/		Weighted-Average Grant Date
		Units		Fair Value
	For the Year Ended December 31, 2011
	Unvested restricted stock awards and units, beginning of period	710,955		$20.26

	Granted	567,901		$35.27

	Vested	(452,585	)	$25.29
	Forfeited	(25,773	)	$23.30
	Unvested restricted stock awards and units, end of period	800,498		$27.96

	For the Year Ended December 31, 2012
	Unvested restricted stock awards and units, beginning of period	800,498		$27.96

	Granted	854,292		$25.25

	Vested	(488,992	)	$25.63
	Forfeited	(19,524	)	$27.61
	Unvested restricted stock awards and units, end of period	1,146,274		$26.95

	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

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Derivative Instruments in Statement of Financial Position Fair Value	'


	Counterparty	December 31, 2013			December 31, 2012
	Credit Suisse	46	%		40	%
	Societe Generale	31	%		22	%
	Wells Fargo	23	%		2	%
	BNP Paribas	—	%		33	%
	BBVA Compass	—	%		3	%
	Total	100	%		100	%
Schedule Of U.S. Crude Oil Derivative Positions	'
	The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of December 31, 2013.


	Period	Type of Contract		Volume			Weighted		Weighted		Weighted Average		Weighted Average
				(in Bbls/d)			Average		Average		Short Put Price		Put Spread
							Floor Price		Ceiling Price		($/Bbl)		($/Bbl)
							($/Bbls)		($/Bbls)
	FY 2014	Swaps		7,500			$	92.59

		Collars		3,000			$	88.33	$	104.26

		Three-way collars		500			$	85	$	107.75	$	65	$	20

	FY 2015	Swaps		4,250			$	91.3

		Collars		700			$	90	$	100.65

		Three-way collars		1,000			$	85	$	105	$	65	$	20

	FY 2016	Three-way collars		667			$	85	$	104	$	65	$	20

Schedule Of U.S. Natural Gas Derivative Positions	'
	The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of December 31, 2013.


	Period	Type of Contract		Volume			Weighted		Weighted
				(in MMBtu/d)			Average		Average
							Floor Price		Ceiling Price
							($/MMBtu)		($/MMBtu)
	FY 2014	Swaps		45,000			$	4.09

		Collars		10,000					$	5.5

	FY 2015	Swaps		10,000			$	4.33

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Assets And Liabilities Measured At Fair Value On A Recurring Basis	'
	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012. All items included in the tables below are Level 2 inputs within the fair value hierarchy:



		31-Dec-13
		Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
		(In thousands)
	Derivative Assets
	Fair value of derivative instruments (current assets)	$	2,389		$	(2,389	)	$	—

	Fair value of derivative instruments (noncurrent asset)	11,709			(2,425		)	9,284

	Derivative Liabilities
	Fair value of derivative instruments (current liabilities)	(12,336		)	2,389			(9,947		)

	Fair value of derivative instruments (included in noncurrent other liabilities)	(2,613		)	2,425			(188		)

	Total	$	(851	)	$	—		$	(851	)



		December 31, 2012
		Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
		(In thousands)
	Derivative Assets
	Fair value of derivative instruments (current asset)	$	24,014		$	(33	)	$	23,981

	Fair value of derivative instruments (noncurrent asset)	6,778			(1,598		)	5,180

	Derivative Liabilities
	Fair value of derivative instruments (current liabilities)	(33		)	33			—

	Fair value of derivative instruments (included in noncurrent other liabilities)	(1,598		)	1,598			—

	Total	29,161			—			29,161

Schedule of Fair Value of Debt Instruments	'
	The following table presents the carrying amounts and fair values of the Company’s senior notes and convertible senior notes, based on quoted market prices, as of December 31, 2013 and 2012.


		December 31, 2013						December 31, 2012
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
		(In thousands)
	8.625% Senior Notes	$	595,822		$	644,978		$	595,151		$	645,000

	7.50% Senior Notes	300,000			327,000			300,000			308,250

	4.375% Convertible Senior Notes	4,425			4,115			72,657			73,842

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Schedule Of Condensed Consolidating Balance Sheets	'


			31-Dec-13
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	ASSETS
	Current assets		$	1,820,069			$	168,718			$	—			$	(1,709,026	)		$	279,761

	Current assets held for sale		—				—				—				—				—

	Assets of discontinued operations		—				—				—				—				—

	Property and equipment, net		2,797				1,768,553				2,058				20,807				1,794,215

	Investment in subsidiaries		61,619				—				—				(61,619		)		—

	Long-term assets held for sale		—				—				—				—				—

	Other assets		69,686				—				—				(32,902		)		36,784

	Total assets		$	1,954,171			$	1,937,271			$	2,058			$	(1,782,740	)		$	2,110,760


	LIABILITIES AND SHAREHOLDERS’ EQUITY
	Current liabilities		$	190,550			$	1,828,314			$	2,061			$	(1,709,026	)		$	311,899

	Current liabilities associated with assets held for sale		—				—				—				—				—

	Current liabilities of discontinued operations		10,936				—				—				—				10,936

	Long-term liabilities		905,235				47,335				—				(23,585		)		928,985

	Long-term liabilities associated with assets held for sale		—				—				—				—				—

	Long-term liabilities of discontinued operations		17,336				—				—				—				17,336

	Shareholders’ equity		830,114				61,622				(3		)		(50,129		)		841,604

	Total liabilities and shareholders’ equity		$	1,954,171			$	1,937,271			$	2,058			$	(1,782,740	)		$	2,110,760



			December 31, 2012
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	ASSETS
	Current assets		$	1,689,430			$	130,487			$	—			$	(1,613,094	)		$	206,823

	Current assets held for sale		—				—				1,882				—				1,882

	Property and equipment, net		23,041				1,443,064				—				21,569				1,487,674

	Investment in subsidiaries		14,588				—				—				(14,588		)		—

	Long-term assets held for sale		12,670				—				119,956				—				132,626

	Other assets		46,913				16,928				—				(8,850		)		54,991

Total assets		$	1,786,642			$	1,590,479			$	121,838			$	(1,614,963	)		$	1,883,996


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities		$	179,221			$	1,631,887			$	—			$	(1,560,853	)		$	250,255

Current liabilities associated with assets held for sale		9,880				—				38,783				—				48,663

Long-term liabilities		973,003				3,512				—				—				976,515

Long-term liabilities associated with assets held for sale		—				—				23,547				—				23,547

Shareholders’ equity		624,538				(44,920		)		59,508				(54,110		)		585,016

Total liabilities and shareholders’ equity		$	1,786,642			$	1,590,479			$	121,838			$	(1,614,963	)		$	1,883,996

Schedule Of Condensed Consolidating Statements Of Operations	'


			For the Year Ended December 31, 2013
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	Oil and gas revenues		$	6,490			$	513,692			$	—			$	—			$	520,182

	Costs and expenses		82,282				284,076				3				762				367,123

	Loss on sale of oil and gas properties		—				45,377				—				—				45,377

	Operating income (loss)		(75,792		)		184,239				(3		)		(762		)		107,682

	Other income (expense), net		(52,592		)		(20,329		)		—				—				(72,921		)

	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 (loss) of subsidiaries		106,538				—				—				(106,538		)		—

	Net income (loss) from continuing operations		23,088				106,541				(3		)		(107,768		)		21,858

	Net income from discontinued operations, net of income taxes		21,825				—				—				—				21,825

	Net income (loss)		$	44,913			$	106,541			$	(3	)		$	(107,768	)		$	43,683



			For the Year Ended December 31, 2012
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	Oil and gas revenues		$	20,195			$	347,985			$	—			$	—			$	368,180

	Costs and expenses		76,839				205,341				—				(12,653		)		269,527

	Operating income (loss)		(56,644		)		142,644				—				12,653				98,653

	Other income (expense), net		20,022				(36,542		)		—				—				(16,520		)

	Income (loss) from continuing operations before income taxes		(36,622		)		106,102				—				12,653				82,133

	Income tax (expense) benefit		12,658				(37,136		)		—				(6,478		)		(30,956		)

	Equity in income (loss) of subsidiaries		73,150				—				—				(73,150		)		—

	Net income (loss) from continuing operations		49,186				68,966				—				(66,975		)		51,177

	Net income from discontinued operations, net of income taxes		126				—				4,184				—				4,310

	Net income (loss)		$	49,312			$	68,966			$	4,184			$	(66,975	)		$	55,487



			For the Year Ended December 31, 2011
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
			Subsidiaries				Guarantor
							Subsidiaries
				(In thousands)
Oil and gas revenues				$	31,875			$	170,292			$	—			$	—			$	202,167

Costs and expenses		68,652				100,255				—				(4,891		)		164,016

Operating income (loss)		(36,777		)		70,037				—				4,891				38,151

Other income (expense), net		41,182				(21,188		)		—				—				19,994

Income (loss) from continuing operations before income taxes		4,405				48,849				—				4,891				58,145

Income tax (expense) benefit		(1,209		)		(22,612		)		—				(1,790		)		(25,611		)

Equity in income (loss) of subsidiaries		29,319				—				—				(29,319		)		—

Net income (loss) from continuing operations		32,515				26,237				—				(26,218		)		32,534

Net loss from discontinued operations, net of income taxes		1,013				—				3,082				—				4,095

Net income (loss)		$	33,528			$	26,237			$	3,082			$	(26,218	)		$	36,629

Schedule Of Condensed Consolidating Statements Of Cash Flows	'


			For the Year Ended December 31, 2013
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	Net cash provided by operating activities - continuing operations		$	(55,888	)		$	423,366			$	(4	)		$	—			$	367,474

	Net cash used in investing activities - continuing operations		(86,322		)		(513,710		)		(2,057		)		92,204				(509,885		)

	Net cash provided by financing activities - 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



			For the Year Ended December 31, 2012
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	Net cash provided by operating activities - continuing operations		$	75,546			$	177,525			$	—			$	—			$	253,071

	Net cash provided by (used in) investing activities - continuing operations		(280,564		)		(493,145		)		—				308,558				(465,151		)

	Net cash provided by (used in) financing activities - continuing operations		237,778				308,558				—				(308,558		)		237,778

	Net cash used in discontinued operations		—				—				(1,196		)		—				(1,196		)

	Net increase (decrease) in cash and cash equivalents		32,760				(7,062		)		(1,196		)		—				24,502

	Cash and cash equivalents, beginning of year		19,134				7,263				1,715				—				28,112

	Cash and cash equivalents, end of year		$	51,894			$	201			$	519			$	—			$	52,614



			For the Year Ended December 31, 2011
			Parent				Combined				Combined				Eliminations				Consolidated
			Company				Guarantor				Non-
							Subsidiaries				Guarantor
											Subsidiaries
			(In thousands)
	Net cash provided by operating activities - continuing operations		$	56,563			$	98,948			$	—			$	—			$	155,511

	Net cash provided by (used in) investing activities - continuing operations		(194,689		)		(356,168		)		—				300,789				(250,068		)

	Net cash provided by (used in) financing activities - continuing operations		155,842				261,773				—				(300,789		)		116,826

	Net cash provided by discontinued operations		—				—				1,715				—				1,715

	Net increase in cash and cash equivalents		17,716				4,553				1,715				—				23,984

	Cash and cash equivalents, beginning of year		1,418				2,710				—				—				4,128

Cash and cash equivalents, end of year		$	19,134			$	7,263			$	1,715			$	—			$	28,112

Supplemental_Disclosures_About1

Supplemental Disclosures About Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
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:


			Year Ended December 31,
			2013				2012				2011
			(In thousands)
	U.S.
	Unproved property acquisition costs		$	254,099			$	139,344			$	108,212

	Exploration costs		106,329				211,289				270,688

	Development costs		423,871				374,391				126,816

	Total costs incurred		$	784,299			$	725,024			$	505,716

	U.K.
	Unproved property acquisition costs		$	—			$	11,135			$	1,004

	Exploration costs		—				—				—

	Development costs		—				36,261				41,424

	Total costs incurred		$	—			$	47,396			$	42,428

	Total Worldwide
	Unproved property acquisition costs		$	254,099			$	150,479			$	109,216

	Exploration costs		106,329				211,289				270,688

	Development costs		423,871				410,652				168,240

	Total costs incurred		$	784,299			$	772,420			$	548,144

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, 2011		10,631			5,263			15,894			12,579			—		12,579

	Extensions and discoveries		16,978			—			16,978			426			—		426

	Revisions of previous estimates		103			174			277			(174	)		—		(174	)

	Sales of reserves in place		(1,809	)		—			(1,809	)		(8,501	)		—		(8,501	)

	Production		(802	)		—			(802	)		(209	)		—		(209	)

	31-Dec-11		25,101			5,437			30,538			4,121			—		4,121

	Extensions and discoveries		15,403			—			15,403			1,750			—		1,750

	Revisions of previous estimates		1,760			(196	)		1,564			740			—		740

	Sales of reserves in place		(327	)		—			(327	)		(923	)		—		(923	)

	Production		(2,862	)		—			(2,862	)		(305	)		—		(305	)

	31-Dec-12		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	)

	31-Dec-13		62,041			—			62,041			8,152			—		8,152


	Proved developed reserves:
	31-Dec-11		6,803			2,719			9,522			1,186			—		1,186

	31-Dec-12		12,675			5,241			17,916			1,620			—		1,620

	31-Dec-13		18,321			—			18,321			2,779			—		2,779


	Proved undeveloped reserves:
	31-Dec-11		18,298			2,718			21,016			2,935			—		2,935

	31-Dec-12		26,400			—			26,400			3,763			—		3,763

	31-Dec-13		43,720			—			43,720			5,373			—		5,373

	Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following:


	2013	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
	2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
	2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation; Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.
	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.
2011	Sales of U.S. properties to KKR during the second quarter and GAIL during 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, 2011		665,167			4,684			669,851			134,071			6,044		140,115

Extensions and discoveries		221,544			—			221,544			54,328			—		54,328

Revisions of previous estimates		(41,990	)		154			(41,836	)		(7,069	)		199		(6,870	)

Sales of reserves in place		(82,884	)		—			(82,884	)		(24,124	)		—		(24,124	)

Production		(38,990	)		—			(38,990	)		(7,509	)		—		(7,509	)

31-Dec-11		722,847			4,838			727,685			149,697			6,243		155,940

Extensions and discoveries		72,916			—			72,916			29,305			—		29,305

Revisions of previous estimates		(20,996	)		(174	)		(21,170	)		(999	)		(225	)	(1,224	)
Sales of reserves in place		(313,483	)		—			(313,483	)		(53,497	)		—		(53,497	)

Production		(37,612	)		—			(37,612	)		(9,436	)		—		(9,436	)

31-Dec-12		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	)

31-Dec-13		187,957			—			187,957			101,519			—		101,519


Proved developed reserves:
31-Dec-11		389,795			2,419			392,214			72,955			3,122		76,077

31-Dec-12		229,539			4,664			234,203			52,552			6,018		58,570

31-Dec-13		106,976			—			106,976			38,929			—		38,929


Proved undeveloped reserves:
31-Dec-11		333,052			2,419			335,471			76,742			3,121		79,863

31-Dec-12		194,134			—			194,134			62,519			—		62,519

31-Dec-13		80,981			—			80,981			62,590			—		62,590

Natural gas extensions and discoveries are primarily attributable to the following:


2013	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford.
2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford.
2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford. Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.
Natural gas revisions of previous estimates are primarily attributable to the following:


2013	Positive price revisions in the U.S. primarily in the Barnett and Marcellus.
2012	Negative price revisions in the U.S. primarily in the Barnett.
2011	Negative price revisions in the U.S. primarily in the Barnett.
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.
2012	Sales of properties to Atlas during the second quarter and sale of Gulf Coast properties during the third quarter.
2011	Sales of properties to KKR during the second quarter and GAIL during the third quarter.
Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	'
	The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:


			U.S.				U.K.				Worldwide
			(In thousands)
	2011
	Future cash inflows		$	4,834,725			$	617,667			$	5,452,392

	Future production costs		(1,212,722		)		(95,229		)		(1,307,951		)
	Future development costs		(1,163,377		)		(43,954		)		(1,207,331		)
	Future income taxes		(477,824		)		(246,273		)		(724,097		)
	Future net cash flows		1,980,802				232,211				2,213,013

	Less 10% annual discount to reflect timing of cash flows		(1,124,339		)		(47,638		)		(1,171,977		)
	Standard measure of discounted future net cash flows		$	856,463			$	184,573			$	1,041,036

	2012
	Future cash inflows		$	4,960,687			$	623,678			$	5,584,365

	Future production costs		(1,009,850		)		(87,727		)		(1,097,577		)
	Future development costs		(982,101		)		(11,194		)		(993,295		)
	Future income taxes		(511,790		)		(252,493		)		(764,283		)
	Future net cash flows		2,456,946				272,264				2,729,210

	Less 10% annual discount to reflect timing of cash flows		(1,277,463		)		(33,352		)		(1,310,815		)
	Standard measure of discounted future net cash flows		$	1,179,483			$	238,912			$	1,418,395

	2013
	Future cash inflows		$	6,936,276			$	—			$	6,936,276

	Future production costs		(1,629,663		)		—				(1,629,663		)

	Future development costs		(1,340,722		)		—				(1,340,722		)

	Future income taxes		(835,840		)		—				(835,840		)

	Future net cash flows		3,130,051				—				3,130,051

	Less 10% annual discount to reflect timing of cash flows		(1,508,640		)		—				(1,508,640		)

	Standard measure of discounted future net cash flows		$	1,621,411			$	—			$	1,621,411

Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	'
	Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below:


			U.S.				U.K.				Worldwide
			(In thousands)
	Standardized measure — January 1, 2011		$	654,684			$	94,102			$	748,786

	Revisions to reserves proved in prior years:
	Net change in sales prices and production costs related to future production		134,952				128,525				263,477

	Net change in estimated future development costs		(509		)		(4,144		)		(4,653		)
	Net change due to revisions in quantity estimates		(64,860		)		13,078				(51,782		)

	Accretion of discount		81,225				19,399				100,624

	Changes in production rates (timing) and other		(78,199		)		(16,094		)		(94,293		)
	Total revisions		72,609				140,764				213,373

	Net change due to extensions and discoveries, net of estimated future development and production costs		508,558				—				508,558

	Net change due to sales of minerals in place		(150,437		)		—				(150,437		)

	Sales of oil and gas produced, net of production costs		(173,853		)		—				(173,853		)

	Previously estimated development costs incurred		5,381				39,779				45,160

	Net change in income taxes		(60,479		)		(90,072		)		(150,551		)
	Net change in standardized measure of discounted future net cash flows		201,779				90,471				292,250

	Standardized measure — December 31, 2011		$	856,463			$	184,573			$	1,041,036

	Revisions to reserves proved in prior years:
	Net change in sales prices and production costs related to future production		(55,249		)		49,719				(5,530		)

	Net change in estimated future development costs		91,404				—				91,404

	Net change due to revisions in quantity estimates		(77,919		)		(46,803		)		(124,722		)
	Accretion of discount		107,451				37,453				144,904

	Changes in production rates (timing) and other		(3,369		)		(6,061		)		(9,430		)
	Total revisions		62,318				34,308				96,626

	Net change due to extensions and discoveries, net of estimated future development and production costs		599,544				—				599,544

	Net change due to sales of minerals in place		(212,910		)		—				(212,910		)

	Sales of oil and gas produced, net of production costs		(313,354		)		—				(313,354		)

	Previously estimated development costs incurred		202,187				32,760				234,947

	Net change in income taxes		(14,765		)		(12,729		)		(27,494		)
	Net change in standardized measure of discounted future net cash flows		323,020				54,339				377,359

	Standardized measure — December 31, 2012		$	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

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule Of Quarterly Financial Information	'
	The following table presents selected quarterly financial data for the years ended December 31, 2013 and 2012:


	2013	First			Second		Third			Fourth
		(In thousands, except per share amounts)
	Oil and gas revenues	$	111,901		$	134,224	$	144,329		$	129,728

	Operating income (loss)	33,463			46,618		48,603			(21,002		)	-2

	Net income (loss) from continuing operations	2,524			35,837		5,712			(22,215		)

	Net income (loss)	$	26,182	-1	$	36,969	$	4,521		$	(23,989	)	-2


	Net income (loss) per share - basic
	Net income (loss) from continuing operations	$	0.06		$	0.89	$	0.14		$	(0.52	)	-2

	Net income (loss) per share	0.66		-1	0.92		0.11			(0.56		)	-2


	Net income (loss) per share - diluted
	Net income (loss) from continuing operations	$	0.06		$	0.88	$	0.14		$	(0.52	)	-2

	Net income (loss) per share	0.65		-1	0.91		0.11			(0.56		)	-2



	2012	First			Second		Third			Fourth
		(In thousands, except per share amounts)
	Oil and gas revenues	$	80,715		$	83,818	$	96,197		$	107,450

	Operating income	22,380			14,806		24,318			37,151

	Net income (loss) from continuing operations	10,676			25,683		(1,945		)	16,763

	Net income (loss)	$	9,423		$	28,504	$	(930	)	$	18,490


	Net income (loss) per share - basic
	Net income (loss) from continuing operations	$	0.27		$	0.65	$	(0.05	)	$	0.42

	Net income (loss) per share	0.24			0.72		(0.02		)	0.47


	Net income (loss) per share - diluted
	Net income (loss) from continuing operations	$	0.27		$	0.64	$	(0.05	)	$	0.42

	Net income (loss) per share	0.24			0.71		(0.02		)	0.46

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2013

Dec. 27, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Minimum [Member]

Maximum [Member]

Stock Options And SARs [Member]

Stock Options [Member]

Stock Appreciation Rights (SARs) [Member]

Restricted Stock Awards And Units [Member]

Restricted Stock Granted To Contractors [Member]

Carrizo United Kingdom [Member]

Customer One [Member]

Customer Two [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Summary Of Significant Accounting Policies [Line Items]

Percentage of non-operating working interest overriding royalty interests

15.00%

Allowance for doubtful accounts receivable

$600,000

$1,400,000

Customer percentage of total revenue

47.00%

53.00%

43.00%

23.00%

10.00%

Internal costs capitalized, Oil and Gas Producing Activities

15,000,000

11,800,000

9,600,000

Average DD&A Per Boe (in USD per BOE)

21.38

17.55

11.26

Capitalized interest

29,889,000

24,848,000

23,369,000

Gain on sale of discontinued operations

37,294,000

Percent of total proved reserves that were sold

40.00%

Loss on sale of oil and gas properties

45,377,000

Reserves discount factor

10.00%

Estimated useful life, minimum, years

'5 years

'10 years

Deferred financing costs, net

22,900,000

23,900,000

Derivative asset, fair value, net

$29,200,000

Vesting period, in years

'3 years

'1 year

'3 years

Expiration period after date of grant, in years

'10 years

'4 years

'7 years

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Schedule Of Stock-Based Compensation Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Allocated Share-based Compensation Expense	$36,300	$14,933	$15,511
Less: amounts capitalized	-6,927	-3,244	-3,647
Stock-based compensation expense, net of amounts capitalized	29,373	11,689	11,864
Income Tax Benefit	10,281	4,449	4,342
Stock Options And SARs [Member]	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Allocated Share-based Compensation Expense	17,303	-2,116	1,546
Restricted Stock Awards And Units [Member]	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Allocated Share-based Compensation Expense	$18,997	$17,049	$13,965

Summary_Of_Significant_Account5

Summary Of Significant Accounting Policies (Schedule Of Supplemental Net Income Per Common Share) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations	($22,215)	$5,712	$35,837	$2,524	$16,763	($1,945)	$25,683	$10,676	$21,858	$51,177	$32,534
Basic weighted average common shares outstanding (in shares)	'	'	'	'	'	'	'	'	40,781	39,591	39,077
Effect of dilutive instruments (in shares)	'	'	'	'	'	'	'	'	574	435	591
Diluted weighted average common shares outstanding (in shares)	'	'	'	'	'	'	'	'	41,355	40,026	39,668
Net income from continuing operations per common share	'	'	'	'	'	'	'	'	'	'	'
Net income from continued operations (in dollars per share)	($0.52)	$0.14	$0.89	$0.06	$0.42	($0.05)	$0.65	$0.27	$0.54	$1.29	$0.83
Net income from continuing operations (in dollars per share)	($0.52)	$0.14	$0.88	$0.06	$0.42	($0.05)	$0.64	$0.27	$0.53	$1.28	$0.82

Discontinued_Operations_Narrat

Discontinued Operations (Narrative) (Details) (USD $)	12 Months Ended				0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 22, 2013	Feb. 22, 2013	Dec. 27, 2012	Feb. 22, 2013
					Carrizo United Kingdom [Member]	Carrizo United Kingdom [Member]	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]	'	'	'	'	'	'	'
Percentage of non-operating working interest overriding royalty interests	'	'	'	'	'	15.00%	'
Cash consideration and retirement of debt aggregate amount	'	'	'	'	$144,100,000	'	'
Sale price	'	'	'	'	184,000,000	'	'
Current availability of term loan facility	'	'	'	'	'	'	55,000,000
Gain on sale of discontinued operations	37,294,000	0	0	'	'	'	'
Liabilities of Disposal Group, Including Discontinued Operation	'	'	'	30,500,000	'	'	'
Deferred compensation expected to be received	'	'	'	'	18,500,000	'	'
Current liabilities of discontinued operations	10,936,000	0	'	'	'	'	'
LONG-TERM LIABILITIES OF DISCONTINUED OPERATIONS	$17,336,000	$0	'	'	'	'	'

Discontinued_Operations_Discon

Discontinued Operations Discontinued Operations (Statements of Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]	'	'	'
OIL AND GAS REVENUES	$0	$0	$0
General and administrative	916	62	242
Accretion related to asset retirement obligations	36	363	76
TOTAL COST AND EXPENSES	952	425	318
OPERATING LOSS	-952	-425	-318
Gain on sale of discontinued operations	37,294	0	0
Adjustment of estimated future obligations	-44	0	0
Gain (loss) on derivative instruments, net	-109	258	-1,432
Interest expense	-253	-3,556	-1,805
Capitalized interest	253	3,556	0
Other income (expense), net	438	-591	259
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	36,627	-758	-3,296
DEFERRED INCOME TAX (EXPENSE) BENEFIT	-14,802	5,068	7,391
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$21,825	$4,310	$4,095

Property_And_Equipment_Net_Nar

Property And Equipment, Net (Narrative) (Details) (USD $)

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

1 Months Ended

Oct. 31, 2013

Oct. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Jan. 15, 2013

Oct. 31, 2012

Utica [Member]

Niobrara Formation - OIL India Ltd And Indian Oil Corporation Ltd [Member]

Niobrara Formation - Haimo Oil And Gas LLC [Member]

Carrizo [Member]

Avista Joint Venture [Member]

Property, Plant and Equipment [Line Items]

Costs not subject to amortization

$377,437,000

$323,688,000

Capitalized costs of unproved properties

265,000,000

112,400,000

Proceeds from sale of property

51,700,000

17,600,000

187,100,000

29,500,000

238,470,000

341,597,000

167,265,000

51,700,000

41,250,000

27,500,000

Sale price of oil and gas property and equipment

218,000,000

19,300,000

190,000,000

30,500,000

Net proceeds from sale of properties

191,800,000

Percent of total proved reserves that were sold

40.00%

Loss on sale of oil and gas properties

-45,377,000

Joint venture investment, original ownership percentage

10.00%

Joint venture investment, net proceeds ownership percentage

50.00%

Payments to Acquire Oil and Gas Property

78,600,000

63,100,000

Joint venture investment, ownership percentage

30.00%

10.00%

60.00%

Future development costs payment percentage

50.00%

Maximum future development costs receivable

$41,250,000

Property_And_Equipment_Net_Sch

Property And Equipment, Net (Schedule Of Property And Equipment) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]	'	'
Proved oil and gas properties	$2,182,226	$1,713,827
Accumulated depreciation, depletion and amortization	-773,742	-561,279
Proved oil and gas properties, net	1,408,484	1,152,548
Unproved properties, not being amortized	'	'
Unevaluated leasehold and seismic costs	302,232	238,833
Exploratory wells in progress	30,196	43,803
Capitalized interest	45,009	41,052
Total unproved properties, not being amortized	377,437	323,688
Other property and equipment	15,260	17,079
Accumulated depreciation	-6,966	-5,641
Other property and equipment, net	8,294	11,438
TOTAL PROPERTY AND EQUIPMENT, NET	$1,794,215	$1,487,674

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]	'	'
U.S. federal statutory corporate pretax rate	35.00%	'
State NOL carryforwards, valuation allowance	'	$1.10
Ownership percentage change	'	5.00%
Change in beneficial ownership, percentage	'	50.00%
Annual limitation on net operating loss carryforwards	'	12.6
Pre-change in net operating loss	'	9.8
Stock-based compensation deductions not reflected in deferred tax assets	'	29.2
Recognized deferred tax assets associated with stock based compensation tax deductions	'	10.2
United States Of America [Member]	'	'
Income Taxes [Line Items]	'	'
Operating loss carry forwards subject to expiration	$174.40	'

Income_Taxes_Schedule_Of_Compo

Income Taxes (Schedule Of Components Of Income Tax (Expense) Benefit (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current income tax (expense) benefit	'	'	'
U.S. Federal	$411	($411)	($404)
State	-141	-403	-661
Total current income tax (expense) benefit	270	-814	-1,065
Deferred income tax expense	'	'	'
U.S. Federal	-12,404	-28,723	-23,254
State	-769	-1,419	-1,292
Total deferred income tax expense	-13,173	-30,142	-24,546
Total income tax expense from continuing operations	($12,903)	($30,956)	($25,611)

Income_Taxes_Schedule_Of_Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income from continuing operations before income taxes	'	'	'
Income from continuing operations before income taxes	$34,761	$82,133	$58,145
Income tax expense at the statutory rate	-12,166	-28,747	-20,350
State income taxes, net of U.S. federal income tax benefit	-859	-1,681	-1,722
Adjustment to prior period state income taxes, net of U.S. federal income tax benefit	0	0	-4,735
Previously unbenefitted capital loss associated with investment	'	0	1,171
Nondeductible expenses	0	-93	25
Other	122	-435	0
Total income tax expense from continuing operations	-12,903	-30,956	-25,611
United States [Member]	'	'	'
Income from continuing operations before income taxes	'	'	'
Income from continuing operations before income taxes	$34,761	$82,133	$58,145

Income_Taxes_Schedule_Of_Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred income tax assets	'	'
Net operating loss carryforward - U.S. Federal and State	$52,499	$53,648
Stock-based compensation	7,563	4,245
Allowance for doubtful accounts	170	476
Fair value of derivative instruments	3,222	0
Other	2,471	1,755
Deferred income tax assets	65,925	60,124
Valuation allowance	-1,084	-1,188
Net deferred income tax assets	64,841	58,936
Deferred income tax liabilities	'	'
Unamortized discount on 4.375% Convertible Senior Notes	0	-382
Oil and gas properties	-74,247	-34,985
Fair value of derivative instruments	-3,249	-10,222
Deferred income tax liabilities	-77,496	-45,589
Net deferred income tax asset (liability)	($12,655)	$13,347

Income_Taxes_Schedule_Of_Net_D

Income Taxes (Schedule Of Net Deferred Income Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Noncurrent deferred income tax asset (liability)	($16,856)	$0
Noncurrent deferred income tax asset (liability)	0	21,272
Current deferred income tax asset (liability)	4,201	0
Current deferred income tax asset (liability)	0	-7,925
Net deferred income tax asset (liability)	($12,655)	$13,347

Debt_Narrative_Details

Debt (Narrative) (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

21-May-08

Dec. 31, 2013

Oct. 30, 2013

Sep. 30, 2013

Jun. 01, 2013

Nov. 30, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Nov. 17, 2011

Nov. 02, 2010

Dec. 31, 2013

Sep. 10, 2012

Dec. 31, 2013

21-May-08

Nov. 30, 2010

Dec. 31, 2013

Dec. 31, 2012

21-May-08

Senior Secured Revolving Credit Facility [Member]

Minimum [Member]

Maximum [Member]

Prior to September 15, 2015 [Member]

8.625% Senior Notes [Member]

7.50% Senior Notes [Member]

4.375% Convertible Senior Notes [Member]

Convertible Senior Notes [Member]

On and after October 15, 2014 [Member]

Prior to October 15, 2014 [Member]

On and after September 15, 2016 [Member]

October Fifteen Two Thousand And Thirteen [Member]

Prior to September 15, 2016 [Member]

Rate

Minimum [Member]

Maximum [Member]

Debt Instrument [Line Items]

Debt instrument interest rate

8.63%

7.50%

4.38%

Aggregate principal amount

$200,000,000

$400,000,000

$300,000,000

$373,800,000

Redemption price, percentage of principal amount

107.50%

104.31%

100.00%

103.75%

100.00%

Change of control repurchase price percentage

101.00%

Debt instrument redemption, percentage of principal

35.00%

Tender Offer Amount For Convertible Senior Notes

300,000,000

Convertible Debt

4,425,000

73,750,000

Consideration Paid For Repurchase Of Convertible Notes

69,300,000

Principal amount per note

1,000

Debt Instrument, Convertible, Conversion Ratio

9.9936

Debt Instrument, Convertible, Conversion Price

$100.06

Convert If Stock Price Exceeds Percentage

130.00%

Convert if trading price equal to or less than percentage

97.00%

Repurchase Price, Percentage Of Principal Amount

100.00%

Line of credit facility, maximum borrowing capacity

1,000,000,000

750,000,000

Line of credit facility current borrowing base

470,000,000

Federal funds rate plus percentage

0.50%

Adjusted LIBO rate plus percentage

1.00%

Additional margin, percent

0.50%

1.50%

Additional margin for Eurodollar loans, percent

1.50%

2.50%

Line of Credit Facility, Previous Borrowing Capacity

530,000,000

Ratio of total debt to EBITDA

1.94

Current ratio

2.57

Line of credit facility amount outstanding

Letters of credit outstanding amount

$900,000

Debt_Schedule_Of_Debt_Details

Debt (Schedule Of Debt) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Long-term Debt	$900,247	$967,808
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]	'	'
Senior Notes	600,000	600,000
Unamortized discount	-4,178	-4,849
7.50% Senior Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	300,000	300,000
Convertible Senior Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Unamortized discount	0	-1,093
4.375% Convertible Senior Notes	$4,425	$73,750

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Asset retirement obligations at beginning of period	$6,159	$8,324	'
Liabilities incurred	3,348	1,573	'
Liabilities settled	-498	-1,666	'
Reduction due to sales of oil and gas properties	-2,473	-3,272	'
Accretion expense	471	372	235
Revisions of previous estimates	349	828	'
Asset retirement obligations at end of period	7,356	6,159	8,324
Asset retirement obligations due within one year included in â€œOther accrued liabilitiesâ€	-780	-1,670	'
Long-term asset retirement obligations	$6,576	$4,489	'

Commitments_And_Contingencies_1

Commitments And Contingencies (Details) (USD $)	12 Months Ended
Commitments And Contingencies (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Abstract]	'	'	'
Rent expense	$1,900,000	$1,800,000	$1,700,000
2014	51,840,000	'	'
2015	19,429,000	'	'
2016	7,404,000	'	'
2017	4,711,000	'	'
2018	4,686,000	'	'
2019 and thereafter	16,128,000	'	'
Total	$104,198,000	'	'

Shareholders_Equity_And_Stock_2

Shareholders' Equity And Stock Incentive Plan (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Shares, Granted	'	0	0	0	'
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	$0	$0	'	'	'
Sale of common stock in an underwritten public offering, value	'	189,686,000	'	'	'
Proceeds from common stock offerings, net of offering costs	189,700,000	189,686,000	0	0	'
Issuance of warrants to purchase of common stock	'	0	31,983	28,576	'
Investment warrants, exercise price	'	'	$22.09	'	'
Number of stock options, restricted stock and restricted stock units granted, covering, shares, net of forfeitures	36,353	36,353	242,854	263,354	414,854
Share-based compensation arrangement by share-based payment award, Options, exercises in period, total intrinsic value	'	4,400,000	400,000	3,600,000	'
Employee service share-based compensation, cash received from exercise of stock options	'	1,300,000	100,000	100,000	'
Stock Incentive Plans [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Maximum issuance of grant awards under Incentive Plan	7,245,000	7,245,000	'	'	'
Number of stock options, restricted stock and restricted stock units granted, covering, shares, net of forfeitures	5,931,933	5,931,933	'	'	'
Restricted Stock Award And Units [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Employee service share-based compensation, nonvested awards, total compensation cost not yet recognized	25,200,000	25,200,000	'	'	'
Employee service share-based compensation, nonvested awards, total compensation cost not yet recognized, period for recognition	'	'2 years 1 month 17 days	'	'	'
Cash Settled Stock Appreciation Rights Plan [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Employee service share-based compensation, nonvested awards, total compensation cost not yet recognized	4,500,000	4,500,000	'	'	'
Issuance of cash stock appreciation rights	'	282,296	193,336	153,801	'
Liability for cash stock appreciation rights	'	20,600,000	7,200,000	'	'
Liability for cash stock appreciation rights, classified as other accrued liabilities	'	19,300,000	6,500,000	'	'
Liability for cash stock appreciation rights remainder, classified as other long term liabilities	'	1,300,000	700,000	'	'
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards	'	$3,900,000	$100,000	$100,000	'
Employee service share-based compensation, nonvested awards, total compensation cost not yet recognized, period for recognition	'	'2 years 2 months 22 days	'	'	'
Underwriter [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Common stock offerings, net of offering costs, shares	4,500,000	'	'	'	'
Underwritten public offering price	$42.24	'	'	'	'

Shareholders_Equity_And_Stock_3

Shareholders' Equity And Stock Incentive Plan (Summary Of Stock Options Activity) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'	'
Shares, Outstanding, beginning of period	242,854	263,354	414,854
Shares, Granted	0	0	0
Shares, Exercised	-206,501	-20,500	-151,500
Shares, Forfeited	0	0	0
Shares, Outstanding, end of period	36,353	242,854	263,354
Shares, Exercisable, end of period	36,353	242,854	263,354
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]	'	'	'
Weighted-Average Exercise Prices, Outstanding, beginning period	$7.24	$7.11	$6.10
Weighted-Average Exercise Prices, Granted	$0	$0	$0
Weighted-Average Exercise Prices, Exercised	$6.07	$5.50	$4.36
Weighted-Average Exercise Prices, Forfeited	$0	$0	$0
Weighted-Average Exercise Prices, Outstanding, end of period	$13.91	$7.24	$7.11
Weighted-Average Exercise Prices, Exercisable, end of period	$13.91	$7.24	$7.11
Weighted-Average Remaining Life, Outstanding, end of period	'1 year 25 days	'	'
Weighted - Average Remaining Life, Exercisable, end of period	'1 year 25 days	'	'
Aggregate Intrinsic Value, Outstanding, end of period	$1.10	'	'
Aggregate Intrinsic Value, Exercisable, end of period	$1.10	'	'

Shareholders_Equity_And_Stock_4

Shareholders' Equity And Stock Incentive Plan (Summary of SARs Activity) (Details) (Cash Settled Stock Appreciation Rights Plan [Member], USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Settled Stock Appreciation Rights Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]	'	'	'
SARs, Outstanding, beginning of period	1,035,823	849,782	700,749
SARs, Granted	282,296	193,336	153,801
SARs, Exercised	-207,184	-7,295	-4,768
SARs, Forfeitures	-24,704	0	0
SARs, Outstanding, end of period	1,086,231	1,035,823	849,782
SARs, Exercisable, End of Period	681,867	613,934	326,128
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	$22.69	$22.02	$18.50
Weighted Average Exercise Prices, Granted	$28.68	$25.56	$37.99
Weighted Average Exercise Prices, Exercised	$19.30	$20.22	$20.22
Weighted Average Exercise Prices, Forfeitures	$27.77	$0	$0
Weighted Average Exercise Prices, Outstanding, End of Period	$24.78	$22.69	$22.02
Weighted Average Exercise Prices, Exercisable, End of Period	$22.55	$20.70	$18.99
Weighted Average Remaining Life, Outstanding, End of Period	'2 years 10 months 4 days	'	'
Weighted Average Remaining Life, Exercisable, End of Period	'2 years 8 months 25 days	'	'
Aggregate Intrinsic Value, Outstanding, End of Period	$21.10	'	'
Aggregate Intrinsic Value, Exercisable, End of Period	$14.80	'	'

Shareholders_Equity_And_Stock_5

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	Dec. 31, 2012	Dec. 31, 2011
Cash Settled Stock Appreciation Rights Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Non-Options, Grants in Period, Weighted Average Grant Date Fair Value	13.36	12.23	18.5
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	44.54%	48.20%	61.60%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%	0.00%	0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.00%	0.40%	0.40%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'3 years 6 months	'3 years	'2 years 10 months 24 days

Shareholders_Equity_And_Stock_6

Shareholders' Equity And Stock Incentive Plan (Summary Of Restricted Stock Award And Unit Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'
Unvested restricted stock, Shares/Units, Beginning of Period	1,146,274	800,498	710,955
Unvested restricted stock, Granted, Shares/Units	932,763	854,292	567,901
Unvested restricted stock, Vested Shares/Units	-557,136	-488,992	-452,585
Unvested restricted stock, Forfeited Shares/Units	-77,034	-19,524	-25,773
Unvested restricted stock, Shares/Units, End of Period	1,444,867	1,146,274	800,498
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'	'	'
Unvested restricted stock, Grant-date Fair Value, Beginning of Period	$26.95	$27.96	$20.26
Unvested restricted stock, Granted, Grant-date Fair Value	$28.16	$25.25	$35.27
Unvested restricted stock, Vested, Grant-date Fair Value	$25.98	$25.63	$25.29
Unvested restricted stock, Forfeited, Grant-date Fair Value	$26.03	$27.61	$23.30
Unvested restricted stock, Grant-date Fair Value, End of Period	$28.03	$26.95	$27.96

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Oct. 31, 2012

Sep. 30, 2010

Sep. 30, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2010

Jun. 30, 2011

Jan. 15, 2013

Oct. 31, 2012

Dec. 31, 2012

Oct. 31, 2012

Dec. 31, 2012

Avista Joint Venture [Member]

ACP II [Member]

Utica [Member]

Avista Joint Venture [Member]

Avista Capital Partners II, L.P. [Member]

Related Party Transaction [Line Items]

Joint venture investment, net proceeds ownership percentage

50.00%

Joint venture investment, original ownership percentage

10.00%

Payments to acquire interest in joint venture

$63,100,000

$24,000,000

Proceeds from sale of property

51,700,000

17,600,000

187,100,000

29,500,000

238,470,000

341,597,000

167,265,000

51,700,000

74,900,000

Joint venture, percentage of ownership increase (decrease)

40.00%

Initial ownership interest of joint interest partner

90.00%

Cost to increase ownership percentage

8.63%

Proceeds of cash distributions recognized as reductions of capitalized oil and gas property costs

78,600,000

Percentage of ownership interest sold

20.00%

Proceeds from sale of interests in joint venture

327,000,000

Percentage of interest in joint venture transferable by each party after initial cash contributions

10.00%

Due from Related Parties, Current

6,600,000

Advances for joint operations from affiliates

$2,800,000

$9,800,000

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	12 Months Ended
Derivative Instruments (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'	'
Current long-term derivative instrument strategy	'60 months	'	'
Derivative liability, fair value of derivative instrument in a net liability position	$10,135,000	$0	'
Gain (loss) on derivative instruments, net	($18,400,000)	$31,400,000	$48,400,000

Derivative_Instruments_Schedul

Derivative Instruments (Schedule of Fair Value Holding Percentage) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative asset, fair value, net	'	$29.20
Derivative Instrument Holding Percentage	100.00%	100.00%
Credit Suisse [Member]	'	'
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative Instrument Holding Percentage	46.00%	40.00%
Societe Generale [Member]	'	'
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative Instrument Holding Percentage	31.00%	22.00%
Bnp Paribas [Member]	'	'
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative Instrument Holding Percentage	0.00%	33.00%
Bbva Compass [Member]	'	'
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative Instrument Holding Percentage	0.00%	3.00%
Wells Fargo [Member]	'	'
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative Instrument Holding Percentage	23.00%	2.00%
Level 2 [Member] \| Level 2 [Member]	'	'
Derivative Instruments, Fair Value [Line Items]	'	'
Derivative asset, fair value, net	$9.30	'

Derivative_Instruments_Schedul1

Derivative Instruments (Schedule Of U.S. Crude Oil Derivative Positions) (Details) (U.S. Crude Oil Derivative Positions [Member])	Dec. 31, 2013
2014 [Member]	'
Derivative [Line Items]	'
Weighted Average Ceiling Price ($/Bbls)	'
Swaps [Member] \| 2014 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	7,500
Weighted Average Floor Price ($/Bbls)	92.59
Swaps [Member] \| 2015 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	4,250
Weighted Average Floor Price ($/Bbls)	91.3
Weighted Average Ceiling Price ($/Bbls)	'
Collars [Member] \| 2014 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	3,000
Weighted Average Floor Price ($/Bbls)	88.33
Weighted Average Ceiling Price ($/Bbls)	104.26
Collars [Member] \| 2015 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	700
Weighted Average Floor Price ($/Bbls)	90
Weighted Average Ceiling Price ($/Bbls)	100.65
Three-way Collars [Member] \| 2014 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	500
Weighted Average Floor Price ($/Bbls)	85
Weighted Average Ceiling Price ($/Bbls)	107.75
Weighted Average Short Put Price ($/Bbl)	65
Weighted Average Put Spread ($/Bbl)	20
Three-way Collars [Member] \| 2015 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	1,000
Weighted Average Floor Price ($/Bbls)	85
Weighted Average Ceiling Price ($/Bbls)	105
Weighted Average Short Put Price ($/Bbl)	65
Weighted Average Put Spread ($/Bbl)	20
Three-way Collars [Member] \| 2016 [Member]	'
Derivative [Line Items]	'
Volumes (in Bbls)	667
Weighted Average Floor Price ($/Bbls)	85
Weighted Average Ceiling Price ($/Bbls)	104
Weighted Average Short Put Price ($/Bbl)	65
Weighted Average Put Spread ($/Bbl)	20

Derivative_Instruments_Schedul2

Derivative Instruments (Schedule Of U.S. Natural Gas Derivative Positions) (Details) (Natural Gas Derivative Positions [Member])	Dec. 31, 2013
	MMBTU
2014 [Member] \| Swaps [Member]	'
Derivative [Line Items]	'
Volume (in MMBtu/d)	45,000
Weighted Average Floor Price ($/MMBtu)	4.09
Weighted Average Ceiling Price ($/MMBtu)	'
2014 [Member] \| Calls [Member]	'
Derivative [Line Items]	'
Volume (in MMBtu/d)	10,000
Weighted Average Ceiling Price ($/MMBtu)	5.5
2015 [Member] \| Swaps [Member]	'
Derivative [Line Items]	'
Volume (in MMBtu/d)	10,000
Weighted Average Floor Price ($/MMBtu)	4.33

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Fair value amount of transfers in or out of Levels 1 or 2	$0	$0
Level 2 [Member] \| Portion at Fair Value Measurement [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative current assets, gross amount recognized	2,389,000	24,014,000
Derivative current assets, gross amounts offset in the consolidated balance sheets	-2,389,000	-33,000
Derivative current assets, net amounts presented in the consolidated balance sheets	0	23,981,000
Derivative non-current assets, gross amount recognized	11,709,000	6,778,000
Derivative non-current assets, gross amounts offset in the consolidated balance sheets	-2,425,000	-1,598,000
Derivative non-current assets, net amounts presented in the consolidated balance sheets	9,284,000	5,180,000
Derivative current liabilities, gross amount recognized	-12,336,000	-33,000
Derivative current liabilities, gross amounts offset in the consolidated balance sheets	2,389,000	33,000
Derivative current liabilities, net amounts presented in the consolidated balance sheets	-9,947,000	0
Derivative non-current liabilities, gross amount recognized	-2,613,000	-1,598,000
Derivative non-current liabilities, gross amounts offset in the consolidated balance sheets	2,425,000	1,598,000
Derivative non-current liabilities, net amounts presented in the consolidated balance sheets	-188,000	0
Derivative asset (liabilities), gross amount recognized	-851,000	29,161,000
Derivative liabilities (assets), gross amounts offset in the consolidated balance sheets	0	0
Total, net amounts presented in the consolidated balance sheets	($851,000)	$29,161,000

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
8.625% Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Senior Notes	$600,000	$600,000
7.50% Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Senior Notes	300,000	300,000
Four Point Three Seven Five Percent Convertible Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Convertible Debt	4,425	73,750
Portion at Fair Value Measurement [Member] \| 8.625% Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Fair value of Senior Notes	644,978	645,000
Portion at Fair Value Measurement [Member] \| 7.50% Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Fair value of Senior Notes	327,000	308,250
Portion at Fair Value Measurement [Member] \| Four Point Three Seven Five Percent Convertible Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Fair Value of Convertible Senior Notes	4,115	73,842
Carrying (Reported) Amount, Fair Value Disclosure [Member] \| 8.625% Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Senior Notes	595,822	595,151
Carrying (Reported) Amount, Fair Value Disclosure [Member] \| 7.50% Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Senior Notes	300,000	300,000
Carrying (Reported) Amount, Fair Value Disclosure [Member] \| Four Point Three Seven Five Percent Convertible Senior Notes [Member]	'	'
Schedule of Fair Value of Debt Instruments [Line Items]	'	'
Convertible Debt	$4,425	$72,657

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information (Narrative) (Details)	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Voting interest of the subsidiary owned by the registrant	100.00%

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets	$279,761	$206,823	'	'
Current assets held for sale	0	1,882	'	'
Assets of discontinued operations	0	'	'	'
Property and equipment, net	1,794,215	1,487,674	'	'
Investment in subsidiaries	0	0	'	'
Long-term assets held for sale	0	132,626	'	'
Other assets	36,784	54,991	'	'
TOTAL ASSETS	2,110,760	1,883,996	'	'
Current liabilities	311,899	250,255	'	'
Current liabilities associated with assets held for sale	0	48,663	'	'
Current liabilities of discontinued operations	10,936	0	'	'
Long-term liabilities	928,985	976,515	'	'
Long-term liabilities associated with assets held for sale	0	23,547	'	'
Long-term liabilities of discontinued operations	17,336	0	'	'
Shareholdersâ€™ equity	841,604	585,016	509,855	456,636
TOTAL LIABILITIES AND SHAREHOLDERSâ€™ EQUITY	2,110,760	1,883,996	'	'
Parent Company [Member]	'	'	'	'
Current assets	1,820,069	1,689,430	'	'
Current assets held for sale	0	0	'	'
Assets of discontinued operations	0	'	'	'
Property and equipment, net	2,797	23,041	'	'
Investment in subsidiaries	61,619	14,588	'	'
Long-term assets held for sale	0	12,670	'	'
Other assets	69,686	46,913	'	'
TOTAL ASSETS	1,954,171	1,786,642	'	'
Current liabilities	190,550	179,221	'	'
Current liabilities associated with assets held for sale	0	9,880	'	'
Current liabilities of discontinued operations	10,936	'	'	'
Long-term liabilities	905,235	973,003	'	'
Long-term liabilities associated with assets held for sale	0	0	'	'
Long-term liabilities of discontinued operations	17,336	'	'	'
Shareholdersâ€™ equity	830,114	624,538	'	'
TOTAL LIABILITIES AND SHAREHOLDERSâ€™ EQUITY	1,954,171	1,786,642	'	'
Combined Guarantor Subsidiaries [Member]	'	'	'	'
Current assets	168,718	130,487	'	'
Current assets held for sale	0	0	'	'
Assets of discontinued operations	0	'	'	'
Property and equipment, net	1,768,553	1,443,064	'	'
Investment in subsidiaries	0	0	'	'
Long-term assets held for sale	0	0	'	'
Other assets	0	16,928	'	'
TOTAL ASSETS	1,937,271	1,590,479	'	'
Current liabilities	1,828,314	1,631,887	'	'
Current liabilities associated with assets held for sale	0	0	'	'
Current liabilities of discontinued operations	0	'	'	'
Long-term liabilities	47,335	3,512	'	'
Long-term liabilities associated with assets held for sale	0	0	'	'
Long-term liabilities of discontinued operations	0	'	'	'
Shareholdersâ€™ equity	61,622	-44,920	'	'
TOTAL LIABILITIES AND SHAREHOLDERSâ€™ EQUITY	1,937,271	1,590,479	'	'
Combined Non-Guarantor Subsidiaries [Member]	'	'	'	'
Current assets	0	0	'	'
Current assets held for sale	0	1,882	'	'
Assets of discontinued operations	0	'	'	'
Property and equipment, net	2,058	0	'	'
Investment in subsidiaries	0	0	'	'
Long-term assets held for sale	0	119,956	'	'
Other assets	0	0	'	'
TOTAL ASSETS	2,058	121,838	'	'
Current liabilities	2,061	0	'	'
Current liabilities associated with assets held for sale	0	38,783	'	'
Current liabilities of discontinued operations	0	'	'	'
Long-term liabilities	0	0	'	'
Long-term liabilities associated with assets held for sale	0	23,547	'	'
Long-term liabilities of discontinued operations	0	'	'	'
Shareholdersâ€™ equity	-3	59,508	'	'
TOTAL LIABILITIES AND SHAREHOLDERSâ€™ EQUITY	2,058	121,838	'	'
Eliminations [Member]	'	'	'	'
Current assets	-1,709,026	-1,613,094	'	'
Current assets held for sale	0	0	'	'
Assets of discontinued operations	0	'	'	'
Property and equipment, net	20,807	21,569	'	'
Investment in subsidiaries	-61,619	-14,588	'	'
Long-term assets held for sale	0	0	'	'
Other assets	-32,902	-8,850	'	'
TOTAL ASSETS	-1,782,740	-1,614,963	'	'
Current liabilities	-1,709,026	-1,560,853	'	'
Current liabilities associated with assets held for sale	0	0	'	'
Current liabilities of discontinued operations	0	'	'	'
Long-term liabilities	-23,585	0	'	'
Long-term liabilities associated with assets held for sale	0	0	'	'
Long-term liabilities of discontinued operations	0	'	'	'
Shareholdersâ€™ equity	-50,129	-54,110	'	'
TOTAL LIABILITIES AND SHAREHOLDERSâ€™ EQUITY	($1,782,740)	($1,614,963)	'	'

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and gas revenues	$129,728	$144,329	$134,224	$111,901	$107,450	$96,197	$83,818	$80,715	$520,182	$368,180	$202,167
Costs and expenses	'	'	'	'	'	'	'	'	367,123	269,527	164,016
Loss on sale of oil and gas properties	'	'	'	'	'	'	'	'	45,377	0	0
Operating income (loss)	-21,002	48,603	46,618	33,463	37,151	24,318	14,806	22,380	107,682	98,653	38,151
Other income (expense), net	'	'	'	'	'	'	'	'	-72,921	-16,520	19,994
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	34,761	82,133	58,145
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-12,903	-30,956	-25,611
Equity in income (loss) of subsidiaries	'	'	'	'	'	'	'	'	0	0	0
Net income from continuing operations	-22,215	5,712	35,837	2,524	16,763	-1,945	25,683	10,676	21,858	51,177	32,534
Net income from discontinued operations, net of income taxes	'	'	'	'	'	'	'	'	21,825	4,310	4,095
NET INCOME	-23,989	4,521	36,969	26,182	18,490	-930	28,504	9,423	43,683	55,487	36,629
Parent Company [Member]	'	'	'	'	'	'	'	'	'	'	'
Oil and gas revenues	'	'	'	'	'	'	'	'	6,490	20,195	31,875
Costs and expenses	'	'	'	'	'	'	'	'	82,282	76,839	68,652
Loss on sale of oil and gas properties	'	'	'	'	'	'	'	'	0	'	'
Operating income (loss)	'	'	'	'	'	'	'	'	-75,792	-56,644	-36,777
Other income (expense), net	'	'	'	'	'	'	'	'	-52,592	20,022	41,182
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	-128,384	-36,622	4,405
Income tax (expense) benefit	'	'	'	'	'	'	'	'	44,934	12,658	-1,209
Equity in income (loss) of subsidiaries	'	'	'	'	'	'	'	'	106,538	73,150	29,319
Net income from continuing operations	'	'	'	'	'	'	'	'	23,088	49,186	32,515
Net income from discontinued operations, net of income taxes	'	'	'	'	'	'	'	'	21,825	126	1,013
NET INCOME	'	'	'	'	'	'	'	'	44,913	49,312	33,528
Combined Guarantor Subsidiaries [Member]	'	'	'	'	'	'	'	'	'	'	'
Oil and gas revenues	'	'	'	'	'	'	'	'	513,692	347,985	170,292
Costs and expenses	'	'	'	'	'	'	'	'	284,076	205,341	100,255
Loss on sale of oil and gas properties	'	'	'	'	'	'	'	'	45,377	'	'
Operating income (loss)	'	'	'	'	'	'	'	'	184,239	142,644	70,037
Other income (expense), net	'	'	'	'	'	'	'	'	-20,329	-36,542	-21,188
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	163,910	106,102	48,849
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-57,369	-37,136	-22,612
Equity in income (loss) of subsidiaries	'	'	'	'	'	'	'	'	0	0	0
Net income from continuing operations	'	'	'	'	'	'	'	'	106,541	68,966	26,237
Net income from discontinued operations, net of income taxes	'	'	'	'	'	'	'	'	0	0	0
NET INCOME	'	'	'	'	'	'	'	'	106,541	68,966	26,237
Combined Non-Guarantor Subsidiaries [Member]	'	'	'	'	'	'	'	'	'	'	'
Oil and gas revenues	'	'	'	'	'	'	'	'	0	0	0
Costs and expenses	'	'	'	'	'	'	'	'	3	0	0
Loss on sale of oil and gas properties	'	'	'	'	'	'	'	'	0	'	'
Operating income (loss)	'	'	'	'	'	'	'	'	-3	0	0
Other income (expense), net	'	'	'	'	'	'	'	'	0	0	0
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	-3	0	0
Income tax (expense) benefit	'	'	'	'	'	'	'	'	0	0	0
Equity in income (loss) of subsidiaries	'	'	'	'	'	'	'	'	0	0	0
Net income from continuing operations	'	'	'	'	'	'	'	'	-3	0	0
Net income from discontinued operations, net of income taxes	'	'	'	'	'	'	'	'	0	4,184	3,082
NET INCOME	'	'	'	'	'	'	'	'	-3	4,184	3,082
Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
Oil and gas revenues	'	'	'	'	'	'	'	'	0	0	0
Costs and expenses	'	'	'	'	'	'	'	'	762	-12,653	-4,891
Loss on sale of oil and gas properties	'	'	'	'	'	'	'	'	0	'	'
Operating income (loss)	'	'	'	'	'	'	'	'	-762	12,653	4,891
Other income (expense), net	'	'	'	'	'	'	'	'	0	0	0
Income (loss) from continuing operations before income taxes	'	'	'	'	'	'	'	'	-762	12,653	4,891
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-468	-6,478	-1,790
Equity in income (loss) of subsidiaries	'	'	'	'	'	'	'	'	-106,538	-73,150	-29,319
Net income from continuing operations	'	'	'	'	'	'	'	'	-107,768	-66,975	-26,218
Net income from discontinued operations, net of income taxes	'	'	'	'	'	'	'	'	0	0	0
NET INCOME	'	'	'	'	'	'	'	'	($107,768)	($66,975)	($26,218)

Condensed_Consolidating_Financ5

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net cash provided by operating activities - continuing operations	$367,474	$253,071	$155,511
Net cash used in investing activities - continuing operations	-509,885	-465,151	-250,068
Net cash provided by financing activities - continuing operations	120,326	237,778	116,826
Net cash provided by (used in) discontinued operations	126,910	-1,196	1,715
Net increase (decrease) in cash and cash equivalents	104,825	24,502	23,984
Cash and cash equivalents, beginning of year	52,614	28,112	4,128
Cash and cash equivalents, end of year	157,439	52,614	28,112
Parent Company [Member]	'	'	'
Net cash provided by operating activities - continuing operations	-55,888	75,546	56,563
Net cash used in investing activities - continuing operations	-86,322	-280,564	-194,689
Net cash provided by financing activities - continuing operations	120,326	237,778	155,842
Net cash provided by (used in) discontinued operations	127,429	0	0
Net increase (decrease) in cash and cash equivalents	105,545	32,760	17,716
Cash and cash equivalents, beginning of year	51,894	19,134	1,418
Cash and cash equivalents, end of year	157,439	51,894	19,134
Combined Guarantor Subsidiaries [Member]	'	'	'
Net cash provided by operating activities - continuing operations	423,366	177,525	98,948
Net cash used in investing activities - continuing operations	-513,710	-493,145	-356,168
Net cash provided by financing activities - continuing operations	90,143	308,558	261,773
Net cash provided by (used in) discontinued operations	0	0	0
Net increase (decrease) in cash and cash equivalents	-201	-7,062	4,553
Cash and cash equivalents, beginning of year	201	7,263	2,710
Cash and cash equivalents, end of year	0	201	7,263
Combined Non-Guarantor Subsidiaries [Member]	'	'	'
Net cash provided by operating activities - continuing operations	-4	0	0
Net cash used in investing activities - continuing operations	-2,057	0	0
Net cash provided by financing activities - continuing operations	2,061	0	0
Net cash provided by (used in) discontinued operations	-519	-1,196	1,715
Net increase (decrease) in cash and cash equivalents	-519	-1,196	1,715
Cash and cash equivalents, beginning of year	519	1,715	0
Cash and cash equivalents, end of year	0	519	1,715
Eliminations [Member]	'	'	'
Net cash provided by operating activities - continuing operations	0	0	0
Net cash used in investing activities - continuing operations	92,204	308,558	300,789
Net cash provided by financing activities - continuing operations	-92,204	-308,558	-300,789
Net cash provided by (used in) discontinued operations	0	0	0
Net increase (decrease) 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

Supplemental_Disclosures_About2

Supplemental Disclosures About Oil And Gas Producing Activities (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Capitalized interest	$29,889	$24,848	$23,369
Reserves discount factor	10.00%	'	'
Crude Oil And Condensate, Per Barrel [Member]	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average market prices used in reserves estimates	99.44	102.03	95.28
Natural Gas Liquids (Bbls) [Member]	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average market prices used in reserves estimates	25.6	32.12	44.9
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	2.97	2.08	3.24

Supplemental_Disclosures_About3

Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property acquisition costs	$254,099	$150,479	$109,216
Exploration costs	106,329	211,289	270,688
Development costs	423,871	410,652	168,240
Total costs incurred	784,299	772,420	548,144
U.S. [Member]	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property acquisition costs	254,099	139,344	108,212
Exploration costs	106,329	211,289	270,688
Development costs	423,871	374,391	126,816
Total costs incurred	784,299	725,024	505,716
U.K.	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property acquisition costs	0	11,135	1,004
Exploration costs	0	0	0
Development costs	0	36,261	41,424
Total costs incurred	$0	$47,396	$42,428

Supplemental_Disclosures_About4

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)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBbls	MBbls	MBbls
Crude Oil (Bbls) [Member]	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	44,316,000	30,538,000	15,894,000
Extensions and discoveries	27,295,000	15,403,000	16,978,000
Revisions of previous estimates	778,000	1,564,000	277,000
Sales of reserves in place	-6,117,000	-327,000	-1,809,000
Production	-4,231,000	-2,862,000	-802,000
Proved developed and undeveloped reserves end of year	62,041,000	44,316,000	30,538,000
Proved developed reserves (volume)	18,321,000	17,916,000	9,522,000
Proved undeveloped reserve (volume)	43,720,000	26,400,000	21,016,000
Crude Oil (Bbls) [Member] \| U.S. [Member]	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	39,075,000	25,101,000	10,631,000
Extensions and discoveries	27,295,000	15,403,000	16,978,000
Revisions of previous estimates	778,000	1,760,000	103,000
Sales of reserves in place	-876,000	-327,000	-1,809,000
Production	-4,231,000	-2,862,000	-802,000
Proved developed and undeveloped reserves end of year	62,041,000	39,075,000	25,101,000
Proved developed reserves (volume)	18,321,000	12,675,000	6,803,000
Proved undeveloped reserve (volume)	43,720,000	26,400,000	18,298,000
Crude Oil (Bbls) [Member] \| U.K.	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	5,241,000	5,437,000	5,263,000
Extensions and discoveries	0	0	0
Revisions of previous estimates	0	-196,000	174,000
Sales of reserves in place	-5,241,000	0	0
Production	0	0	0
Proved developed and undeveloped reserves end of year	0	5,241,000	5,437,000
Proved developed reserves (volume)	0	5,241,000	2,719,000
Proved undeveloped reserve (volume)	0	0	2,718,000
Natural Gas Liquids (Bbls) [Member]	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	5,383,000	4,121,000	12,579,000
Extensions and discoveries	2,992,000	1,750,000	426,000
Revisions of previous estimates	308,000	740,000	-174,000
Sales of reserves in place	0	-923,000	-8,501,000
Production	-531,000	-305,000	-209,000
Proved developed and undeveloped reserves end of year	8,152,000	5,383,000	4,121,000
Proved developed reserves (volume)	2,779,000	1,620,000	1,186,000
Proved undeveloped reserve (volume)	5,373,000	3,763,000	2,935,000
Natural Gas Liquids (Bbls) [Member] \| U.S. [Member]	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	5,383,000	4,121,000	12,579,000
Extensions and discoveries	2,992,000	1,750,000	426,000
Revisions of previous estimates	308,000	740,000	-174,000
Sales of reserves in place	0	-923,000	-8,501,000
Production	-531,000	-305,000	-209,000
Proved developed and undeveloped reserves end of year	8,152,000	5,383,000	4,121,000
Proved developed reserves (volume)	2,779,000	1,620,000	1,186,000
Proved undeveloped reserve (volume)	5,373,000	3,763,000	2,935,000
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	0	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	428,336,000	727,685,000	669,851,000
Extensions and discoveries	73,360,000	72,916,000	221,544,000
Revisions of previous estimates	29,819,000	-21,170,000	-41,836,000
Sales of reserves in place	-312,136,000	-313,483,000	-82,884,000
Production	-31,422,000	-37,612,000	-38,990,000
Proved developed and undeveloped reserves end of year	187,957,000	428,336,000	727,685,000
Proved developed reserves (volume)	106,976,000	234,203,000	392,214,000
Proved undeveloped reserve (volume)	80,981,000	194,134,000	335,471,000
Natural Gas (Mcf) [Member] \| U.S. [Member]	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	423,672,000	722,847,000	665,167,000
Extensions and discoveries	73,360,000	72,916,000	221,544,000
Revisions of previous estimates	29,819,000	-20,996,000	-41,990,000
Sales of reserves in place	-307,472,000	-313,483,000	-82,884,000
Production	-31,422,000	-37,612,000	-38,990,000
Proved developed and undeveloped reserves end of year	187,957,000	423,672,000	722,847,000
Proved developed reserves (volume)	106,976,000	229,539,000	389,795,000
Proved undeveloped reserve (volume)	80,981,000	194,134,000	333,052,000
Natural Gas (Mcf) [Member] \| U.K.	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves beginning of year	4,664,000	4,838,000	4,684,000
Extensions and discoveries	0	0	0
Revisions of previous estimates	0	-174,000	154,000
Sales of reserves in place	-4,664,000	0	0
Production	0	0	0
Proved developed and undeveloped reserves end of year	0	4,664,000	4,838,000
Proved developed reserves (volume)	0	4,664,000	2,419,000
Proved undeveloped reserve (volume)	0	0	2,419,000
Barrel of Oil Equivalent (Boe) [Domain]	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves, net Boe, beginning of year	121,088,000	155,940,000	140,115,000
Extensions and discoveries	42,514,000	29,305,000	54,328,000
Revisions of previous estimates	6,055,000	-1,224,000	-6,870,000
Sales of reserves in place	-58,139,000	-53,497,000	-24,124,000
Production	-9,999,000	-9,436,000	-7,509,000
Proved developed and undeveloped reserves, net Boe, end of year	101,519,000	121,088,000	155,940,000
Proved developed reserves (energy)	38,929,000	58,570,000	76,077,000
Proved undeveloped reserves (energy)	62,590,000	62,519,000	79,863,000
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	115,070,000	149,697,000	134,071,000
Extensions and discoveries	42,514,000	29,305,000	54,328,000
Revisions of previous estimates	6,055,000	-999,000	-7,069,000
Sales of reserves in place	-52,121,000	-53,497,000	-24,124,000
Production	-9,999,000	-9,436,000	-7,509,000
Proved developed and undeveloped reserves, net Boe, end of year	101,519,000	115,070,000	149,697,000
Proved developed reserves (energy)	38,929,000	52,552,000	72,955,000
Proved undeveloped reserves (energy)	62,590,000	62,519,000	76,742,000
Barrel of Oil Equivalent (Boe) [Domain] \| U.K.	'	'	'
Proved Developed and Undeveloped Reserves [Abstract]	'	'	'
Proved developed and undeveloped reserves, net Boe, beginning of year	6,018,000	6,243,000	6,044,000
Extensions and discoveries	0	0	0
Revisions of previous estimates	0	-225,000	199,000
Sales of reserves in place	-6,018,000	0	0
Production	0	0	0
Proved developed and undeveloped reserves, net Boe, end of year	0	6,018,000	6,243,000
Proved developed reserves (energy)	0	6,018,000	3,122,000
Proved undeveloped reserves (energy)	0	0	3,121,000

Supplemental_Disclosures_About5

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 $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	$6,936,276,000	$5,584,365,000	$5,452,392,000
Future production costs	-1,629,663,000	-1,097,577,000	-1,307,951,000
Future development costs	-1,340,722,000	-993,295,000	-1,207,331,000
Future income taxes	-835,840,000	-764,283,000	-724,097,000
Future net cash flows	3,130,051,000	2,729,210,000	2,213,013,000
Less 10% annual discount to reflect timing of cash flows	-1,508,640,000	-1,310,815,000	-1,171,977,000
Standard measure of discounted future net cash flows	1,621,411,000	1,418,395,000	1,041,036,000
U.S. [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	6,936,276,000	4,960,687,000	4,834,725,000
Future production costs	-1,629,663,000	-1,009,850,000	-1,212,722,000
Future development costs	-1,340,722,000	-982,101,000	-1,163,377,000
Future income taxes	-835,840,000	-511,790,000	-477,824,000
Future net cash flows	3,130,051,000	2,456,946,000	1,980,802,000
Less 10% annual discount to reflect timing of cash flows	-1,508,640,000	-1,277,463,000	-1,124,339,000
Standard measure of discounted future net cash flows	1,621,411,000	1,179,483,000	856,463,000
U.K.	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	0	623,678,000	617,667,000
Future production costs	0	-87,727,000	-95,229,000
Future development costs	0	-11,194,000	-43,954,000
Future income taxes	0	-252,493,000	-246,273,000
Future net cash flows	0	272,264,000	232,211,000
Less 10% annual discount to reflect timing of cash flows	0	-33,352,000	-47,638,000
Standard measure of discounted future net cash flows	$0	$238,912,000	$184,573,000

Supplemental_Disclosures_About6

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 $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Standardized measure â€” beginning of period	$1,418,395,000	$1,041,036,000	$748,786,000
Net change in sales prices and production costs related to future production	-232,361,000	-5,530,000	263,477,000
Net change in estimated future development costs	-10,602,000	91,404,000	-4,653,000
Net change due to revisions in quantity estimates	205,686,000	-124,722,000	-51,782,000
Accretion of discount	185,389,000	144,904,000	100,624,000
Changes in production rates (timing) and other	11,892,000	-9,430,000	-94,293,000
Total revisions	160,004,000	96,626,000	213,373,000
Net change due to extensions and discoveries, net of estimated future development and production costs	873,028,000	599,544,000	508,558,000
Net change due to sales of minerals in place	-632,752,000	-212,910,000	-150,437,000
Sales of oil and gas produced, net of production costs	-444,841,000	-313,354,000	-173,853,000
Previously estimated development costs incurred	217,395,000	234,947,000	45,160,000
Net change in income taxes	30,182,000	-27,494,000	-150,551,000
Net change in standardized measure of discounted future net cash flows	203,016,000	377,359,000	292,250,000
Standardized measure â€” end of period	1,621,411,000	1,418,395,000	1,041,036,000
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 â€” beginning of period	1,179,483,000	856,463,000	654,684,000
Net change in sales prices and production costs related to future production	-232,361,000	-55,249,000	134,952,000
Net change in estimated future development costs	-10,602,000	91,404,000	-509,000
Net change due to revisions in quantity estimates	205,686,000	-77,919,000	-64,860,000
Accretion of discount	141,229,000	107,451,000	81,225,000
Changes in production rates (timing) and other	56,052,000	-3,369,000	-78,199,000
Total revisions	160,004,000	62,318,000	72,609,000
Net change due to extensions and discoveries, net of estimated future development and production costs	873,028,000	599,544,000	508,558,000
Net change due to sales of minerals in place	-191,155,000	-212,910,000	-150,437,000
Sales of oil and gas produced, net of production costs	-444,841,000	-313,354,000	-173,853,000
Previously estimated development costs incurred	217,395,000	202,187,000	5,381,000
Net change in income taxes	-172,503,000	-14,765,000	-60,479,000
Net change in standardized measure of discounted future net cash flows	441,928,000	323,020,000	201,779,000
Standardized measure â€” end of period	1,621,411,000	1,179,483,000	856,463,000
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 â€” beginning of period	238,912,000	184,573,000	94,102,000
Net change in sales prices and production costs related to future production	0	49,719,000	128,525,000
Net change in estimated future development costs	0	0	-4,144,000
Net change due to revisions in quantity estimates	0	-46,803,000	13,078,000
Accretion of discount	44,160,000	37,453,000	19,399,000
Changes in production rates (timing) and other	-44,160,000	-6,061,000	-16,094,000
Total revisions	0	34,308,000	140,764,000
Net change due to extensions and discoveries, net of estimated future development and production costs	0	0	0
Net change due to sales of minerals in place	-441,597,000	0	0
Sales of oil and gas produced, net of production costs	0	0	0
Previously estimated development costs incurred	0	32,760,000	39,779,000
Net change in income taxes	202,685,000	-12,729,000	-90,072,000
Net change in standardized measure of discounted future net cash flows	-238,912,000	54,339,000	90,471,000
Standardized measure â€” end of period	$0	$238,912,000	$184,573,000

Selected_Quarterly_Financial_D2

Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Oil and gas revenues	$129,728	$144,329	$134,224	$111,901	$107,450	$96,197	$83,818	$80,715	$520,182	$368,180	$202,167
Operating income (loss)	-21,002	48,603	46,618	33,463	37,151	24,318	14,806	22,380	107,682	98,653	38,151
Net income from continuing operations	-22,215	5,712	35,837	2,524	16,763	-1,945	25,683	10,676	21,858	51,177	32,534
Net income (loss)	($23,989)	$4,521	$36,969	$26,182	$18,490	($930)	$28,504	$9,423	$43,683	$55,487	$36,629
Net income from continued operations basic (in dollars per share)	($0.52)	$0.14	$0.89	$0.06	$0.42	($0.05)	$0.65	$0.27	$0.54	$1.29	$0.83
Net income per share basic (in dollars per share)	($0.56)	$0.11	$0.92	$0.66	$0.47	($0.02)	$0.72	$0.24	$1.07	$1.40	$0.94
Net income from continuing operations diluted (in dollars per share)	($0.52)	$0.14	$0.88	$0.06	$0.42	($0.05)	$0.64	$0.27	$0.53	$1.28	$0.82
Net income per share, diluted (in dollars per share)	($0.56)	$0.11	$0.91	$0.65	$0.46	($0.02)	$0.71	$0.24	$1.06	$1.39	$0.92

Selected_Quarterly_Financial_D3

Selected Quarterly Financial Data Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'
Gain on sale of discontinued operations	$37,294	$0	$0
Loss on sale of oil and gas properties	($45,377)	$0	$0