10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________

FORM 10-Q

_________________________________________________

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to             

Commission File Number: 000-29187-87

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CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

_________________________________________________

Texas	76-0415919
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
500 Dallas Street, Suite 2300, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 328-1000

(Registrant’s telephone number)

 ____________________________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    YES  x    NO  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    YES  x    NO  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of October 31, 2013 was 40,921,395.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013

INDEX

		PAGE
PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements	2
	Consolidated Balance Sheets (Unaudited) as of September 30, 2013 and December 31, 2012	2
	Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2013 and 2012	3
	Consolidated Statements of Cash Flows (Unaudited) for the nine months ended September 30, 2013 and 2012	4
	Notes to Consolidated Financial Statements (Unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	37
SIGNATURES		38

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (Unaudited)
	September 30, 2013			December 31, 2012
	(In thousands, except per  share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,728		$	52,095
Accounts receivable, net	114,901			112,821
Accounts receivable - related party	5,930			9,815
Current assets held for sale	—			1,882
Fair value of derivative instruments	—			23,981
Deferred income taxes	5,209			—
Prepaids and other current assets	5,397			8,111
Total current assets	137,165			208,705
PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full cost method of accounting
Proved oil and gas properties, net	1,495,981			1,152,548
Unproved properties, not being amortized	395,291			323,688
Other property and equipment, net	9,800			11,438
TOTAL PROPERTY AND EQUIPMENT, NET	1,901,072			1,487,674
LONG-TERM ASSETS HELD FOR SALE	—			132,626
DEFERRED FINANCING COSTS, NET	21,728			23,914
FAIR VALUE OF DERIVATIVE INSTRUMENTS	7,410			5,180
DEFERRED INCOME TAXES	—			21,272
OTHER ASSETS	4,620			4,625
TOTAL ASSETS	$	2,071,995		$	1,883,996
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	77,876		$	44,775
Revenue and royalties payable	103,250			82,300
Accrued drilling costs	57,161			60,729
Accrued interest	24,847			18,012
Other accrued liabilities	45,732			28,445
Advances for joint operations	34,528			8,069
Deferred income taxes	—			7,925
Current liabilities associated with assets held for sale	—			48,663
Liabilities of discontinued operations	10,670			—
Total current liabilities	354,064			298,918
LONG-TERM DEBT, NET OF DEBT DISCOUNT	987,074			967,808
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE	—			23,547
LIABILITIES OF DISCONTINUED OPERATIONS	17,742			—
ASSET RETIREMENT OBLIGATIONS	6,341			4,489
DEFERRED INCOME TAXES	32,796			—
OTHER LIABILITIES	5,900			4,218
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value (90,000 shares authorized, 40,879 and 40,165 shares issued and outstanding as of September 30, 2013 and December 31, 2012, respectively)	409			402
Additional paid-in capital	682,479			667,096
Accumulated deficit	(14,810		)	(82,482		)
Total shareholders’ equity	668,078			585,016
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,071,995		$	1,883,996

The accompanying notes are an integral part of these consolidated financial statements.

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands, except per share amounts)
OIL AND GAS REVENUES	$	144,329		$	96,197		$	390,454		$	260,730
COSTS AND EXPENSES
Lease operating	12,934			7,145			34,926			22,599
Production tax	5,590			3,449			14,687			9,676
Ad valorem tax	2,125			2,327			6,848			8,238
Depreciation, depletion and amortization	55,234			46,518			151,232			121,459
General and administrative (inclusive of stock-based compensation expense of $9,872 and $5,091 for the three months ended September 30, 2013 and 2012, respectively, and $19,338 and $10,622 for the nine months ended September 30, 2013 and 2012, respectively)	19,715			12,354			53,722			36,974
Accretion related to asset retirement obligations	128			86			355			280
TOTAL COSTS AND EXPENSES	95,726			71,879			261,770			199,226
OPERATING INCOME	48,603			24,318			128,684			61,504
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net	(27,658		)	(14,718		)	(16,486		)	26,975
Interest expense	(20,887		)	(18,074		)	(64,158		)	(51,298		)
Capitalized interest	7,485			5,917			21,791			17,951
Other income, net	28			20			95			254
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	7,571			(2,537		)	69,926			55,386
INCOME TAX (EXPENSE) BENEFIT	(1,859		)	592			(25,853		)	(20,972		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	$	5,712		$	(1,945	)	$	44,073		$	34,414
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	(1,191		)	1,015			23,599			2,583
NET INCOME (LOSS)	$	4,521		$	(930	)	$	67,672		$	36,997
NET INCOME (LOSS) PER COMMON SHARE - BASIC
Net income (loss) from continuing operations	$	0.14		$	(0.05	)	$	1.10		$	0.87
Net income (loss) from discontinued operations	(0.03		)	0.03			0.59			0.07
Net income (loss)	$	0.11		$	(0.02	)	$	1.69		$	0.94
NET INCOME (LOSS) PER COMMON SHARE - DILUTED
Net income (loss) from continuing operations	$	0.14		$	(0.05	)	$	1.09		$	0.86
Net income (loss) from discontinued operations	(0.03		)	0.03			0.58			0.07
Net income (loss)	$	0.11		$	(0.02	)	$	1.67		$	0.93
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	40,386			39,634			40,083			39,559
Diluted	40,927			39,634			40,601			39,992

The accompanying notes are an integral part of these consolidated financial statements.

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For The Nine Months Ended September 30,
	2013			2012
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	67,672		$	36,997
Net income from discontinued operations, net of income taxes	(23,599		)	(2,583		)
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities-
Depreciation, depletion and amortization	151,232			121,459
Unrealized loss on derivative instruments, net	25,806			3,569
Accretion related to asset retirement obligations	355			280
Stock-based compensation, net of amounts capitalized	19,338			10,622
Allowance for doubtful accounts	(105		)	(391		)
Deferred income taxes	25,853			20,972
Amortization of debt discount and deferred financing costs, net of amounts capitalized	3,217			3,236
Other, net	1,894			2,646
Changes in operating assets and liabilities-
Accounts receivable	1,910			(71,215		)
Accounts payable	38,843			31,699
Accrued liabilities	2,049			23,325
Other, net	(4,212		)	(3,977		)
Net cash provided by operating activities - continuing operations	310,253			176,639
Net cash used in operating activities - discontinued operations	(400		)	(402		)
Net cash provided by operating activities	309,853			176,237
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures - oil and gas properties	(571,069		)	(575,971		)
Capital expenditures - other property and equipment	(687		)	(3,689		)
Increase (decrease) in capital expenditure payables and accruals	23,020			(14,583		)
Proceeds from sales of oil and gas properties, net	20,753			207,250
Advances to operators	1,537			(852		)
Advances for joint operations	26,459			(42,986		)
Other, net	(3,414		)	(5,389		)
Net cash used in investing activities - continuing operations	(503,401		)	(436,220		)
Net cash provided by (used in) investing activities - discontinued operations	126,223			(29,442		)
Net cash used in investing activities	(377,178		)	(465,662		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings and issuances	437,000			1,036,000
Debt repayments	(419,325		)	(783,000		)
Payments of costs associated with revolving credit facility and debt issuance	(1,075		)	(6,005		)
Proceeds from stock options exercised	839			74
Net cash provided by financing activities - continuing operations	17,439			247,069
Net cash provided by financing activities - discontinued operations	3,000			28,532
Net cash provided by financing activities	20,439			275,601
NET DECREASE IN CASH AND CASH EQUIVALENTS	(46,886		)	(13,824		)
CASH AND CASH EQUIVALENTS, beginning of period	52,614			28,112
CASH AND CASH EQUIVALENTS, end of period	$	5,728		$	14,288

The accompanying notes are an integral part of these consolidated financial statements.

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, the Barnett Shale in North Texas, and the Utica Shale in Ohio.

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. The consolidated financial statements reflect all necessary adjustments, all of which were of a normal recurring nature and are in the opinion of management necessary for a fair presentation of the Company’s interim financial position, results of operations and cash flows. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The operating results for the three and nine months ended September 30,2013 are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

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. Beginning March 31, 2013, the Company classified the remaining assets and liabilities associated with the U.K. North Sea as assets of discontinued operations and liabilities of discontinued operations in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations, net of income taxes, in the consolidated statements of operations, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to assets held for sale and discontinued operations is included in “Note 3. Discontinued Operations” and “Note 10. Condensed Consolidating Financial Information.”

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating 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 timing of 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

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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 include impairments of unproved properties, fair values of derivative instruments, stock-based compensation, collectability of receivables, disputed claims, interpretation of 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, 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 September 30, 2013 and December 31, 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 8. Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments.

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 costs centers established on a country-by-country basis. Internal costs, including payroll and stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized and totaled $3.8 million and $2.5 million for the three months ended September 30,2013 and 2012, respectively, and $10.1 million and $9.5 million for the nine months ended September 30,2013 and 2012, 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 $20.01 and $19.76 for the three months ended September 30,2013 and 2012, respectively, and $19.59 and $17.21 for the nine months ended September 30,2013 and 2012, 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 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 capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved leasehold within the next five years and exploratory wells in progress within the next year. Individually insignificant costs of unevaluated properties 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 $7.5 million and $5.9 million for the three months ended September 30,2013 and 2012, respectively, and $21.8 million and $18.0 million for the nine months ended September 30,2013 and 2012, respectively. Interest is capitalized on

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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 oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. On February 22, 2013, the Company closed on 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 gain in “net income (loss) from discontinued operations, net of income taxes” in the consolidated statements of operations. Other than the sale of Carrizo UK noted above, the Company has not had any sales of oil and gas properties that significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center through September 30, 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 market 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 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, net of amounts capitalized 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 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 9. Fair Value Measurements.”

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells and restore the surface after the reserves have been depleted. The asset retirement obligation is recognized as a liability at its fair value when the well is drilled with an associated increase in oil and gas property costs. Asset retirement obligations require estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligations are discounted using a credit-adjusted risk-free interest rate which is accreted to their expected settlement values over the estimated productive lives of the oil and gas properties. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in estimated costs to plug and abandon wells and restore the surface and changes in the estimated remaining lives of the oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement, which is included in proved oil and gas property costs.

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On an interim basis, the Company reassesses the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

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 the products are 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 for oil and gas revenues whereby revenue is recognized for all oil and gas 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 oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production and as of September 30, 2013 and December 31, 2012, the Company did not have any material production imbalances.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are recognized at their balance sheet date fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with a portion of its forecasted oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized 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 operations. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty and subject to master netting agreements.

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 8. Derivative Instruments” for further discussion of the Company’s derivative instruments.

Stock-Based Compensation

The Company grants 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 for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Stock Appreciation Rights	$	6,752		$	1,536		$	10,691		$	226
Restricted Stock Awards and Units	5,232			4,598			13,551			13,179
	11,984			6,134			24,242			13,405
Less: amounts capitalized	(2,112		)	(1,043		)	(4,904		)	(2,783		)
Total Stock-Based Compensation Expense	$	9,872		$	5,091		$	19,338		$	10,622
Income Tax Benefit	$	(3,627	)	$	(1,937	)	$	(7,097	)	$	(4,042	)

Stock Options and SARs. For stock options and SARs that the Company expects to settle in 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 expects to settle 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 other long-term liabilities. Subsequent to vesting, the liability for SARs that the Company expects to settle in cash is remeasured in earnings at

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each reporting period based on 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.

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

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments by taxing jurisdiction. If the Company concludes that it is more likely than not that some portion or all of the 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) From Continuing Operations Per Common Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
	(In thousands, except per share amounts)
Net income (loss) from continuing operations	$	5,712	$	(1,945	)	$	44,073	$	34,414
Basic weighted average common shares outstanding	40,386		39,634			40,083		39,559
Effect of dilutive instruments	541		—			518		433
Diluted weighted average common shares outstanding	40,927		39,634			40,601		39,992
Net income (loss) from continuing operations per common share
Basic	$	0.14	$	(0.05	)	$	1.10	$	0.87
Diluted	$	0.14	$	(0.05	)	$	1.09	$	0.86

Basic net income (loss) 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 (loss) from continuing operations per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock awards and units, stock options, SARs expected to be settled in common stock, warrants and convertible debt. The Company excludes shares related to restricted stock awards, units and stock options from the calculation of diluted weighted average shares outstanding when the grant date prices are greater than the average market prices of the common shares for the period as the effect would be antidilutive to the computation. The shares excluded for the three and nine months ended September 30, 2013 and nine months ended September 30, 2012 were not significant. The Company did not include 402,750 shares in the calculation of dilutive shares for the three months ended September 30, 2012 due to the net loss reported in the period. 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 three and nine months ended September 30,2013 or 2012, 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

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requirement effective January 1, 2013. The adoption did not have a material effect on the Company's consolidated financial statements.

3. Discontinued Operations

On February 22, 2013, the Company closed on the sale of Carrizo UK, and all of its interest in the Huntington Field discovery, including a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) for an agreed-upon price of $184.0 million, including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding under Carrizo UK's senior secured multicurrency credit facility as of the closing date.

During the third quarter, the Company received the remaining $6.8 million of deferred consideration, which was previously presented in assets of discontinued operations in the consolidated balance sheets. The liabilities of discontinued operations of $28.4 million relate to an accrual for estimated future obligations related to the sale. See “Note 2. Summary of Significant Accounting Policies—Use of Estimates” for further discussion of estimates and assumptions that may affect the reported amounts of assets and liabilities related to the sale of Carrizo UK.

The following table summarizes the amounts included in net income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of operations for the three and nine months ended September 30,2013 and 2012:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
OIL AND GAS REVENUES	$	—		$	—		$	—		$	—
COSTS AND EXPENSES
General and administrative	408			56			709			68
Accretion related to asset retirement obligations	—			104			36			258
TOTAL COST AND EXPENSES	408			160			745			326
OPERATING LOSS	(408		)	(160		)	(745		)	(326		)
OTHER INCOME AND EXPENSES
Gain on sale of discontinued operations	—			—			37,294			—
Decrease (increase) in estimated future obligations	(1,187		)	—			1,378			—
Gain (loss) on derivative instruments, net	(18		)	(135		)	(93		)	(543		)
Interest expense	—			(871		)	(253		)	(2,669		)
Capitalized interest	—			871			253			2,669
Other income (expense), net	106			4			438			(590		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	(1,507		)	(291		)	38,272			(1,459		)
INCOME TAX (EXPENSE) BENEFIT	316			1,306			(14,673		)	4,042
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(1,191	)	$	1,015		$	23,599		$	2,583

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. deferred income tax (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.

Foreign Currency

The U.S. dollar was the functional currency for the Company’s operations in the U.K. North Sea. Transaction gains or losses that occurred due to the realization of assets and the settlement of liabilities denominated in a currency other than the functional currency were recorded as Other income (expense), net.

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4. Property and Equipment, Net

At September 30, 2013 and December 31, 2012, property and equipment, net consisted of the following:

	September 30, 2013			December 31, 2012
	(In thousands)
Proved oil and gas properties	$	2,207,220		$	1,713,827
Accumulated depreciation, depletion and amortization	(711,239		)	(561,279		)
Proved oil and gas properties, net	1,495,981			1,152,548
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	302,391			238,833
Exploratory wells in progress	41,926			43,803
Capitalized interest	50,974			41,052
Total unproved properties, not being amortized	395,291			323,688
Other property and equipment	16,323			17,079
Accumulated depreciation	(6,523		)	(5,641		)
Other property and equipment, net	9,800			11,438
Total property and equipment, net	$	1,901,072		$	1,487,674

Utica Shale Joint Venture. On January 15, 2013, we exercised our option for an additional 40% in the remaining properties held through our joint venture 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 Holdings, LP, a private equity firm (collectively with ACP II and ACP III, “Avista”) by paying $63.1 million. Following the option exercise, the Company elected 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.

5. Income Taxes

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates are applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate will impact future income tax expense. Income tax expense differs from 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:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
	(In thousands)
Income tax expense (benefit) at the statutory rate	$	2,650		$	(889	)	$	24,474	$	19,384
State income taxes, net of U.S. federal income tax effect	(791		)	334			1,275		1,421
Other, net	—			(37		)	104		167
Income tax expense (benefit)	$	1,859		$	(592	)	$	25,853	$	20,972

As of September 30, 2013, the Company had U.S. income tax loss carryforwards of approximately $174.4 million. The U.S. loss carryforwards expire between 2019 and 2032 if not utilized in earlier periods. The realization of the deferred tax assets related to the U.S. loss carryforwards is dependent on the Company’s ability to generate sufficient future taxable income, which the Company expects to be able to generate within the applicable carryforward periods. Accordingly, the Company believes that it is more likely than not that its deferred tax assets related to the U.S. loss carryforwards will be fully realized.

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At September 30, 2013, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

6. Long-Term Debt

Long-term debt consisted of the following at September 30, 2013 and December 31, 2012:

	September 30, 2013			December 31, 2012
	(In thousands)
8.625% Senior Notes	$	600,000		$	600,000
Unamortized discount for 8.625% Senior Notes	(4,351		)	(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	87,000			—
	$	987,074		$	967,808

Convertible Senior Notes

On June 3, 2013, the Company completed a required tender offer to repurchase the 4.375% convertible senior notes due 2028, with $4.4 million aggregate principal amount of convertible senior notes remaining outstanding. The holders of the Company's remaining $4.4 million aggregate principal amount of convertible senior notes may require it to repurchase the remaining 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 also 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 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 revolving credit facility).

On October 9, 2013, a fourth amendment to the senior secured revolving credit facility (the "Fourth Amendment") 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 substantially all of the Company's Barnett Shale assets, 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.

As of September 30, 2013, the Company was 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 to 1.00; (2) a Current Ratio of not less than 1.00 to 1.00; (3) a ratio of Senior Debt to EBITDA of not more than 2.50 to 1.00; and (4) a ratio of EBITDA to Interest Expense of not less than 2.50 to 1.00 (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the credit agreement governing the revolving credit facility). As of September 30, 2013, the ratio of Total Debt to EBITDA was 2.44 to 1.00, the Current Ratio was 1.73 to 1.00, the ratio of Senior Debt to EBITDA was 0.20 to 1.00 and the ratio of EBITDA to Interest Expense was 5.02 to 1.00. Total Debt and Senior Debt, as defined in the credit agreement governing the revolving credit facility, is net of cash and cash equivalents. 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.

At September 30, 2013, the Company had $87.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 3.44%. At September 30, 2013, the Company also had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Upon closing of the Company's Barnett Shale assets on October 31, 2013, the borrowing base was automatically reduced to $470.0 million. Future availability under the borrowing base is subject to the terms and covenants of 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.

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7. 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.

8. Derivative Instruments

The Company uses various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital expenditure plan. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at termination or expiration. The Company's current strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 60 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations for the period in which the changes occur.

The fair value of derivative instruments at September 30, 2013 and December 31, 2012 was a net asset of $3.9 million and $29.2 million, respectively. The following sets forth a summary of the distribution of net fair value of the Company’s derivative instruments for each counterparty in a net asset position:

Counterparty	September 30, 2013		December 31, 2012
Credit Suisse	57	%	40	%
Societe Generale	27	%	22	%
BNP Paribas	13	%	33	%
Regions	2	%	—	%
BBVA Compass	1	%	3	%
Wells Fargo	—	%	2	%
Total	100	%	100	%

Master netting agreements are in place with each of these counterparties. Because the counterparties are investment grade financial institutions, 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. Because Credit Suisse, Societe Generale, Regions, BBVA Compass and Wells Fargo are lenders in the Company’s revolving credit facility, the Company is not required to post collateral with respect to derivative instruments in a net liability position with these counterparties as the contracts are secured by the revolving credit facility.

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The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of September 30, 2013:

Period	Type of Contract	Volumes (in Bbls/d)	Weighted Average Floor  Price ($/Bbl)		Weighted Average Ceiling  Price ($/Bbl)		Weighted Average Short Put  Price ($/Bbl)		Weighted Average Put Spread ($/Bbl)
Q4 2013	Swaps	4,000	$	94.15
	Collars	6,100	$	87.75	$	105.68
FY 2014	Swaps	5,996	$	92.36
	Collars	3,000	$	88.33	$	104.26
	Three-way collars	500	$	85.00	$	107.75	$	65.00	$	20.00
FY 2015	Swaps	3,250	$	90.64
	Collars	700	$	90.00	$	100.65
	Three-way collars	1,000	$	85.00	$	105.00	$	65.00	$	20.00
FY 2016	Three-way collars	667	$	85.00	$	104.00	$	65.00	$	20.00

The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of September 30, 2013:

Period	Type of Contract	Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q4 2013	Swaps	55,000	$	4.58
FY 2014	Swaps	40,000	$	4.07
	Calls	10,000			$	5.50
FY 2015	Swaps	10,000	$	4.33

For the three and nine months ended September 30,2013 and 2012, the Company recorded the following related to its oil and gas derivative instruments:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Realized gain on derivative instruments, net	$	1,313		$	9,450		$	9,320		$	30,544
Unrealized loss on derivative instruments, net	(28,971		)	(24,168		)	(25,806		)	(3,569		)
Gain (loss) on derivative instruments, net	$	(27,658	)	$	(14,718	)	$	(16,486	)	$	26,975

9. 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.

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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 September 30, 2013 and December 31, 2012. All items included in the tables below are Level 2 inputs within the fair value hierarchy:

	September 30, 2013
Description	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Derivative instruments	$	17,679		$	(10,269	)	$	7,410
Liabilities:
Derivative instruments	(13,793		)	10,269			(3,524		)
Total	$	3,886		$	—		$	3,886

	December 31, 2012
Description	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Derivative instruments	$	36,452		$	(7,291	)	$	29,161
Liabilities:
Derivative instruments	(7,291		)	7,291			—
Total	$	29,161		$	—		$	29,161

The fair values of the Company’s derivative instruments are based on a third-party 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 assets and liabilities for derivative instruments included in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to master netting agreements. The derivative instruments assets are classified in fair value of derivative instruments and the derivative instruments liabilities are classified in other accrued liabilities on the consolidated balance sheets. The Company had no transfers in or out of Levels 1 or 2 for the nine months ended September 30,2013 or 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 September 30, 2013 and December 31, 2012.

	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
8.625% Senior Notes	$	595,649	$	647,768	$	595,151	$	645,000
7.50% Senior Notes	300,000		316,500		300,000		308,250
4.375% Convertible Senior Notes	4,425		4,436		72,657		73,842

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10. 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 September 30, 2013 and December 31, 2012, and for the three and nine months ended September 30,2013 and 2012 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.

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

	September 30, 2013
	Parent Company		Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,799,935	$	182,326	$	—	$	(1,845,096	)	$	137,165
Property and equipment, net	652		1,877,367		1,624		21,429			1,901,072
Investments in subsidiaries	61,297		—		—		(61,297		)	—
Other assets	51,136		—		—		(17,378		)	33,758
Total assets	$	1,913,020	$	2,059,693	$	1,624	$	(1,902,342	)	$	2,071,995
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	234,737	$	1,952,129	$	1,624	$	(1,845,096	)	$	343,394
Current liabilities of discontinued operations	10,670		—		—		—			10,670
Long-term liabilities	993,043		46,267		—		(7,199		)	1,032,111
Long-term liabilities of discontinued operations	17,742		—		—		—			17,742
Shareholders’ equity (deficit)	656,828		61,297		—		(50,047		)	668,078
Total liabilities and shareholders’ equity	$	1,913,020	$	2,059,693	$	1,624	$	(1,902,342	)	$	2,071,995

	December 31, 2012
	Parent Company		Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(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
Investments 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 (deficit)	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

-17-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	For the Three Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	2,428		$	141,901		$	—	$	—		$	144,329
Cost and expenses	20,994			74,640			—		92			95,726
Operating income (loss)	(18,566		)	67,261			—		(92		)	48,603
Other income (expense), net	(36,314		)	(4,718		)	—		—			(41,032		)
Income (loss) from continuing operations before income taxes	(54,880		)	62,543			—		(92		)	7,571
Income tax (expense) benefit	19,208			(21,784		)	—		717			(1,859		)
Equity in income (loss) of subsidiaries	40,759			—			—		(40,759		)	—
Net income (loss) from continuing operations	5,087			40,759			—		(40,134		)	5,712
Net income from discontinued operations, net of income taxes	(1,191		)	—			—		—			(1,191		)
Net income (loss)	$	3,896		$	40,759		$	—	$	(40,134	)	$	4,521

	For the Three Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	4,459		$	91,738		$	—	$	—		$	96,197
Cost and expenses	15,256			56,135			—		488			71,879
Operating income (loss)	(10,797		)	35,603			—		(488		)	24,318
Other income (expense), net	(16,407		)	(10,448		)	—		—			(26,855		)
Income (loss) from continuing operations before income taxes	(27,204		)	25,155			—		(488		)	(2,537		)
Income tax (expense) benefit	9,531			(8,796		)	—		(143		)	592
Equity in income (loss) of subsidiaries	17,374			—			—		(17,374		)	—
Net income (loss) from continuing operations	(299		)	16,359			—		(18,005		)	(1,945		)
Net income from discontinued operations, net of income taxes	—			—			1,015		—			1,015
Net income (loss)	$	(299	)	$	16,359		$	1,015	$	(18,005	)	$	(930	)

-18-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	For the Nine Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	6,075		$	384,379		$	—	$	—		$	390,454
Cost and expenses	57,427			204,204			—		139			261,770
Operating income (loss)	(51,352		)	180,175			—		(139		)	128,684
Other income (expense), net	(41,995		)	(16,763		)	—		—			(58,758		)
Income (loss) from continuing operations before income taxes	(93,347		)	163,412			—		(139		)	69,926
Income tax (expense) benefit	32,671			(57,194		)	—		(1,330		)	(25,853		)
Equity in income (loss) of subsidiaries	106,218			—			—		(106,218		)	—
Net income (loss) from continuing operations	45,542			106,218			—		(107,687		)	44,073
Net income from discontinued operations, net of income taxes	23,599			—			—		—			23,599
Net income (loss)	$	69,141		$	106,218		$	—	$	(107,687	)	$	67,672

	For the Nine Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	15,856		$	244,874		$	—	$	—		$	260,730
Cost and expenses	62,608			150,242			—		(13,624		)	199,226
Operating income (loss)	(46,752		)	94,632			—		13,624			61,504
Other income (expense), net	18,890			(25,008		)	—		—			(6,118		)
Income (loss) from continuing operations before income taxes	(27,862		)	69,624			—		13,624			55,386
Income tax (expense) benefit	9,760			(24,360		)	—		(6,372		)	(20,972		)
Equity in income (loss) of subsidiaries	47,847			—			—		(47,847		)	—
Net income (loss) from continuing operations	29,745			45,264			—		(40,595		)	34,414
Net income from discontinued operations, net of income taxes	—			—			2,583		—			2,583
Net income (loss)	$	29,745		$	45,264		$	2,583	$	(40,595	)	$	36,997

-19-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	For the Nine Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities - continuing operations	$	(22,222	)	$	332,475		$	—		$	—		$	310,253
Net cash provided by (used in) investing activities - continuing operations	(170,725		)	(601,936		)	(1,624		)	270,884			(503,401		)
Net cash provided by (used in) financing activities - continuing operations	17,439			269,260			1,624			(270,884		)	17,439
Net cash provided by (used in) discontinued operations	129,342			—			(519		)	—			128,823
Net increase (decrease) in cash and cash equivalents	(46,166		)	(201		)	(519		)	—			(46,886		)
Cash and cash equivalents, beginning of period	51,894			201			519			—			52,614
Cash and cash equivalents, end of period	$	5,728		$	—		$	—		$	—		$	5,728

	For the Nine Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities - continuing operations	$	31,974		$	144,665		$	—		$	—		$	176,639
Net cash provided by (used in) investing activities - continuing operations	(306,682		)	(379,182		)	—			249,644			(436,220		)
Net cash provided by (used in) financing activities - continuing operations	264,344			232,369			—			(249,644		)	247,069
Net cash used in discontinued operations				—			(1,312		)	—			(1,312		)
Net increase (decrease) in cash and cash equivalents	(10,364		)	(2,148		)	(1,312		)	—			(13,824		)
Cash and cash equivalents, beginning of period	19,134			7,263			1,715			—			28,112
Cash and cash equivalents, end of period	$	8,770		$	5,115		$	403		$	—		$	14,288

-20-

11. Subsequent Events

During the third quarter of 2013, the Company agreed in three separate transactions to sell certain non-core assets, including substantially all of its remaining Barnett Shale assets, certain non-core assets in East Texas, and acreage in non-core areas of the Marcellus Shale, for an aggregate agreed upon sales price of $248.5 million and the assumption of certain liabilities and contractual obligations, subject to customary closing conditions and purchase price adjustments. In one of these transactions, the Company agreed to sell substantially all of its remaining Barnett Shale assets (the "Barnett Transaction") to affiliates of EnerVest Ltd. ("EnerVest") for an agreed upon purchase price of $218.0 million, subject to closing and post-closing purchase price adjustments and the assumption by EnerVest of certain liabilities and contractual obligations. The Barnett Transaction had an effective date of July 1, 2013. The Company closed the sale of its non-core East Texas assets in early September for $8.7 million. The Company closed the Barnett Transaction and the sale of its non-core Marcellus Shale assets in late October and as of October 31, 2013, the Company has received aggregate net proceeds related to these two asset sales totaling approximately $209.7 million. In addition, as a consequence of certain post-closing adjustments and holdbacks, the Company could receive up to an additional $23.8 million in cash proceeds related to such sales.

In connection with the Barnett Transaction, the Company entered into derivative instruments on behalf of EnerVest. These derivative instruments were novated to EnerVest upon the closing of the Barnett Transaction. As of September 30, 2013, these derivative instruments were in a net asset position and had a fair market value of $0.5 million.

Avista Transaction. Effective September 2011, the Company entered into a joint venture in the Utica Shale with Avista. On October 31, 2013, the Company completed the acquisition of acreage located primarily in Guernsey and Noble counties, Ohio from Avista. The transaction had an effective date of July 1, 2013, and the Company paid Avista $73.2 million in cash, subject to post-closing adjustments. The Company had an ownership in the working interest of the properties acquired through the Avista Utica Shale Joint Venture. The properties in the Avista Utica Joint Venture were held with an equal interest by the Company and Avista. The agreement provides for post-closing price and acreage adjustments and indemnities.

In connection with the Avista Transaction, the Company terminated the previously existing Avista Utica Shale Joint Venture agreements. After giving effect to the Avista Transaction, the Company and Avista remain working interest partners in the Utica Shale with the Company acting as the operator of the jointly owned properties which are now subject to standard joint operating agreements. The Company and Avista have established a new area of mutual interest that has been significantly reduced in coverage area and now applies only to certain of those areas in which the Company and Avista jointly own properties.

-21-

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is management’s discussion and analysis of the significant factors that affected the Company’s financial position and results of operations during the periods included in the accompanying unaudited consolidated financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012, and the unaudited consolidated financial statements included in this quarterly report.

Overview

Our third quarter 2013 included oil and gas revenues of $144.3 million and production of 2.8 MMBoe. The key drivers affecting our results for the three months ended September 30,2013 included the following:

Drilling and Completion. See the table below for details of our operated drilling and completion activity in our primary areas of activity:

	For the Three Months Ended September 30, 2013				As of September 30, 2013
	Drilled		Wells Brought on Production		Waiting on Completion		Producing		Rig count
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	19	14.7	11	8.6	32	24.1	106	83.3	3
Niobrara	15	4.7	14	4.7	8	2.3	64	25.2	2
Marcellus	6	1.8	5	1.7	26	8.0	54	18.4	1
Barnett	—	—	—	—	—	—	86	55.9	—
Total	40	21.2	30	15.0	66	34.4	310	182.8	6

Production. Our third quarter 2013 production of 2.8 MMBoe increased 17% from the third quarter 2012 production of 2.4 MMBoe. The increase in production from the third quarter of 2012 to the third quarter of 2013 was primarily due to increased production from new wells, partially offset by normal production decline and the impact of the sale of a portion of our working interest in connection with entering into our Niobrara joint venture transactions in the fourth quarter of 2012.

Commodity prices. Our average realized oil price during the third quarter of 2013 was $104.71 per barrel, or 8% higher compared to $96.66 for the third quarter of 2012. Our average realized natural gas price during the third quarter of 2013 was $2.38 per Mcf, or 24% higher than the $1.92 during the third quarter of 2012. Although natural gas prices have increased compared to the same period in 2012, the overall market for natural gas remains challenging, making the current market and outlook, and therefore the expenditure of capital, for crude oil more attractive. Commodity prices are affected by changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Commodity prices are beyond our control and have been and are expected to remain volatile.

Recent Developments. During the third quarter of 2013, we agreed in three separate transactions to sell certain non-core assets, including substantially all of our remaining Barnett Shale assets, certain non-core assets in East Texas, and acreage in non-core areas of the Marcellus Shale, for an aggregate agreed upon sales price of $248.5 million and the assumption of certain liabilities and contractual obligations, subject to customary closing conditions and purchase price adjustments. In one of these transactions, we agreed to sell substantially all of our remaining Barnett Shale assets (the "Barnett Transaction") to affiliates of EnerVest Ltd. ("EnerVest") for an agreed upon purchase price of $218.0 million subject to closing and post-closing purchase price adjustments and the assumption of certain liabilities and contractual obligations. The Barnett Transaction had an effective date of July 1, 2013. We closed the sale of our non-core East Texas assets in early September for $8.7 million. We closed the Barnett Transaction and the sale of our non-core Marcellus Shale assets in late October and as of October 31, 2013, we had received aggregate net proceeds related to these two asset sales totaling approximately $209.7 million. In addition, as a consequence of certain post-closing adjustments and holdbacks, we could receive up to an additional $23.8 million in cash proceeds related to such sales. We intend to use the net proceeds from these two sale transactions to repay borrowings under our revolving credit facility, initially fund the Avista Transaction described below and to partially fund the remainder of our 2013 capital expenditures plan.

We currently expect that the Barnett Transaction will result in a loss on the sale in the fourth quarter of 2013 as the proved reserves attributable to the Barnett Transaction represent 40% of the Company's proved reserves as of September 30, 2013 and therefore the sale is expected to significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to our U.S. cost center. Additionally, we currently anticipate that the Barnett Transaction will result in an increase in our future depreciation, depletion and amortization rate, and therefore will negatively affect our future reported earnings.

-22-

On October 31, 2013, we completed the acquisition of approximately 5,900 net acres located primarily in Guernsey and Noble counties, Ohio from Avista (the “Avista Transaction”). The transaction had an effective date of July 1, 2013, and the Company paid Avista approximately $73.2 million in cash, subject to post-closing adjustments. We had an ownership in the working interest of the properties acquired through the Avista Utica Joint Venture. The properties in the Avista Utica Joint Venture were held with an equal interest by the Company and Avista. The Avista Transaction was funded with proceeds from the sale of substantially all of our remaining properties in the Barnett Shale. The agreement provides for post-closing price and acreage adjustments and indemnities.

Results of Operations

Three Months Ended September 30,2013, Compared to the Three Months Ended September 30,2012

Revenues from oil and gas production for the three months ended September 30,2013 increased 50% to $144.3 million from $96.2 million for the same period in 2012 primarily due to the significant increase in oil production and oil and gas prices. Production volumes for the three months ended September 30,2013 and 2012 were 2.8 MMBoe and 2.4 MMBoe, respectively. The increase in production from the third quarter of 2012 to the third quarter of 2013 was primarily due to increased production from new wells, partially offset by normal production decline and our Niobrara joint venture transactions in the fourth quarter of 2012. Average realized oil prices increased 8% to $104.71 per barrel from $96.66 per barrel in the same period in 2012. Average realized gas prices increased 24% to $2.38 per Mcf in the third quarter of 2013 from $1.92 per Mcf in the same period in 2012.

-23-

The following table summarizes production volumes, average realized prices and oil and gas revenues for the three months ended September 30,2013 and 2012:

	Three Months Ended September 30,				2013 Period Compared to 2012 Period
	2013		2012		Increase (Decrease)			% Increase (Decrease)
Production volumes -
Crude oil (MBbls)	1,125		796		329			41	%
NGLs (MBbls)	202		78		124			159	%
Natural gas (MMcf)	8,603		8,877		(274		)	(3	)%
Total Natural gas and NGLs (MMcfe)	9,815		9,345		470			5	%
Total barrels of oil equivalent (MBoe)	2,761		2,354		407			17	%
Daily production volumes by product -
Crude oil (Bbls/d)	12,228		8,652		3,576			41	%
NGLs (Bbls/d)	2,196		848		1,348			159	%
Natural gas (Mcf/d)	93,511		96,489		(2,978		)	(3	)%
Total Natural gas and NGLs (Mcfe/d)	106,685		101,576		5,109			5	%
Total barrels of oil equivalent (Boe/d)	30,011		25,587		4,424			17	%
Daily production volumes by region (Boe/d) -
Eagle Ford	13,960		8,583		5,377			63	%
Niobrara	2,061		1,715		346			20	%
Barnett	7,609		9,805		(2,196		)	(22	)%
Marcellus	6,069		4,271		1,798			42	%
Other	312		1,213		(901		)	(74	)%
Total barrels of oil equivalent (Boe/d)	30,011		25,587		4,424			17	%
Average realized prices -
Crude oil ($ per Bbl)	$	104.71	$	96.66	$	8.05		8	%
NGLs ($ per Bbl)	29.83		28.53		1.30			5	%
Natural gas ($ per Mcf)	2.38		1.92		0.46			24	%
Total Natural gas and NGLs average realized price ($ per Mcfe)	$	2.70	$	2.06	$	0.64		31	%
Total average realized price ($ per Boe)	$	52.27	$	40.87	$	11.40		28	%
Oil and gas revenues (In thousands) -
Crude oil	$	117,797	$	76,945	$	40,852		53	%
NGLs	6,025		2,225		3,800			171	%
Natural gas	20,507		17,027		3,480			20	%
Total oil and gas revenues	$	144,329	$	96,197	$	48,132		50	%

Lease operating expenses were $12.9 million ($4.68 per Boe) for the three months ended September 30,2013 as compared to lease operating expenses of $7.1 million ($3.04 per Boe) for the same period in 2012. The $5.8 million increase in lease operating expenses is primarily due to increased production from new wells. The increase in operating cost per Boe is primarily due to the higher operating cost per Boe associated with the increased oil production.

Production taxes were $5.6 million (or 3.9% of oil and gas revenues) for the three months ended September 30,2013 as compared to $3.4 million (or 3.6% of oil and gas revenues) for the same period in 2012. The increase in production taxes is due primarily to increased oil production. The increase in production taxes as a percentage of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to our natural gas production.

Depreciation, depletion and amortization (“DD&A”) expense for the third quarter of 2013 increased $8.7 million to $55.2 million ($20.01 per Boe) from the DD&A expense for the third quarter of 2012 of $46.5 million ($19.76 per Boe). The increase in DD&A is attributable to both the increase in production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is largely due to significant increases in crude oil reserves in the Eagle Ford that were added throughout 2012, which have a higher finding cost per Boe than our natural gas reserves.

-24-

General and administrative expense increased to $19.7 million for the three months ended September 30,2013 from $12.4 million for the corresponding period in 2012. The increase was primarily due to an increase in personnel during the third quarter of 2013 as compared to the same period of 2012 as well as increased stock-based compensation expense which was primarily driven by an increase in the fair value of stock appreciation rights.

The net loss on derivative instruments of $27.7 million in the third quarter of 2013 consisted of a $29.0 million unrealized loss on derivatives and a $1.3 million realized gain on derivatives. The net loss on derivative instruments of $14.7 million in the third quarter of 2012 was comprised of a $24.2 million unrealized loss on derivatives and a $9.5 million realized gain on derivatives.

Interest expense and capitalized interest for the three months ended September 30,2013 were $20.9 million and $7.5 million, respectively, as compared to $18.1 million and $5.9 million, respectively, for the same period in 2012. The increase in interest expense was primarily due to interest on the $300.0 million aggregate principal amount of our 7.50% Senior Notes that were issued late in the third quarter of 2012 partially offset by the repurchase of the 4.375% convertible senior notes during the second quarter of 2013.

The estimated annual effective income tax rates for 2013 and 2012 were 36.7%, and 38.1%, respectively. The effective income tax rate for the third quarter of 2013 was 24.6% which was lower than the expected tax rate due to changes in current year state tax estimates. The effective income tax rate for the third quarter 2012 was 23.3% which was lower than the expected tax rate due to the pre-tax loss impact on state tax estimates.

-25-

Nine Months Ended September 30,2013, Compared to the Nine Months Ended September 30,2012

Revenues from oil and gas production for the nine months ended September 30,2013 increased 50% to $390.5 million from $260.7 million for the same period in 2012 primarily due to a significant increase in oil production and gas prices. Production volumes for the nine months ended September 30,2013 and 2012 were 7.7 MMBoe and 7.1 MMBoe, respectively. The increase in production from the nine months ended September 30,2012 to the nine months ended September 30,2013 was primarily due to increased production from new wells, partially offset by normal production decline, the sale of a significant portion of our remaining Barnett Shale properties to Atlas Resource Partners, L.P. (“Atlas”), and our Niobrara joint venture transactions in the fourth quarter of 2012. Average realized oil prices increased 2% to $102.60 per barrel from $100.93 per barrel in the same period in 2012. Average realized gas prices increased 55% to $2.64 per Mcf for the nine months ended September 30,2013 from $1.70 per Mcf in the same period in 2012.

The following table summarizes production volumes, average realized prices and oil and gas revenues for the nine months ended September 30,2013 and 2012:

	Nine Months Ended September 30,				2013 Period Compared to 2012 Period
	2013		2012		Increase (Decrease)			% Increase (Decrease)
Production volumes -
Crude oil (MBbls)	3,032		2,030		1,002			49	%
NGLs (MBbls)	408		191		217			114	%
Natural gas (MMcf)	25,680		29,011		(3,331		)	(11	)%
Total Natural gas and NGLs (MMcfe)	28,128		30,157		(2,029		)	(7	)%
Total barrels of oil equivalent (MBoe)	7,720		7,056		664			9	%
Daily production volumes by product -
Crude oil (Bbls/d)	11,106		7,409		3,697			50	%
NGLs (Bbls/d)	1,495		697		798			114	%
Natural gas (Mcf/d)	94,066		105,880		(11,814		)	(11	)%
Total Natural gas and NGLs (Mcfe/d)	103,033		110,062		(7,029		)	(6	)%
Total barrels of oil equivalent (Boe/d)	28,278		25,752		2,526			10	%
Daily production volumes by region (Boe/d) -
Eagle Ford	12,184		7,277		4,907			67	%
Niobrara	1,621		1,229		392			32	%
Barnett	8,131		12,617		(4,486		)	(36	)%
Marcellus	6,016		3,164		2,852			90	%
Other	326		1,465		(1,139		)	(78	)%
Total barrels of oil equivalent (Boe/d)	28,278		25,752		2,526			10	%
Average realized prices -
Crude oil ($ per Bbl)	$	102.60	$	100.93	$	1.67		2	%
NGLs ($ per Bbl)	28.26		34.88		(6.62		)	(19	)%
Natural gas ($ per Mcf)	2.64		1.70		0.94			55	%
Total Natural gas and NGLs average realized price ($ per Mcfe)	$	2.82	$	1.85	$	0.97		52	%
Total average realized price ($ per Boe)	$	50.58	$	36.95	$	13.63		37	%
Oil and gas revenues (In thousands) -
Crude oil	$	311,084	$	204,890	$	106,194		52	%
NGLs	11,532		6,662		4,870			73	%
Natural gas	67,838		49,178		18,660			38	%
Total oil and gas revenues	$	390,454	$	260,730	$	129,724		50	%

Lease operating expenses were $34.9 million ($4.52 per Boe) for the nine months ended September 30,2013 as compared to lease operating expenses of $22.6 million ($3.20 per Boe) for the same period in 2012. The $12.3 million increase in lease

-26-

operating expenses is primarily due to increased production from new wells partially offset by the sale to Atlas. The increase in operating cost per Boe is primarily due to the higher operating cost per Boe associated with the increased oil production.

Production taxes were $14.7 million (or 3.8% of oil and gas revenues) for the nine months ended September 30,2013 as compared to $9.7 million (or 3.7% of oil and gas revenues) for the same period in 2012. The increase in production taxes is due primarily to increased oil production. The increase in production taxes as a percentage of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to our natural gas production.

Ad valorem taxes decreased to $6.8 million ($0.89 per Boe) for the nine months ended September 30,2013 from $8.2 million ($1.17 per Boe) for the same period in 2012. The decrease in ad valorem taxes is due primarily to the sale of Barnett properties to Atlas and the Commonwealth of Pennsylvania's February 2012 enactment of an “impact fee” on the drilling of unconventional natural gas wells recognized in the first quarter of 2012, partially offset by an increase in ad valorem taxes for new wells drilled in 2012. Because of the retroactive nature of the impact fee, approximately $1.0 million of the impact fee recognized during the first half of 2012 was attributable to wells drilled prior to 2012.

DD&A expense for the nine months ended September 30,2013 increased $29.7 million to $151.2 million ($19.59 per Boe) from the DD&A expense for the nine months ended September 30,2012 of $121.5 million ($17.21 per Boe). The increase in DD&A is attributable to both the increase in production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is largely due to the impact of the significant decrease in natural gas reserves in the Barnett as a result of the Atlas sale as well as the significant increase in crude oil reserves in the Eagle Ford that were added throughout 2012, which have a higher finding cost per Boe than our natural gas reserves.

General and administrative expense increased to $53.7 million for the nine months ended September 30,2013 from $37.0 million for the corresponding period in 2012. The increase was primarily due to an increase in personnel during the second quarter of 2013 as compared to the same period of 2012 and increased stock-based compensation expense which was primarily driven by an increase in the fair value of stock appreciation rights.

The net loss on derivative instruments of $16.5 million in the nine months ended September 30,2013 consisted of a $25.8 million unrealized loss on derivatives and a $9.3 million realized gain on derivatives. The net gain on derivative instruments of $27.0 million in the nine months ended September 30,2012 was comprised of a $3.6 million unrealized loss on derivatives and a $30.5 million realized gain on derivatives.

Interest expense and capitalized interest for the nine months ended September 30,2013 were $64.2 million and $21.8 million, respectively, as compared to $51.3 million and $18.0 million, respectively, for the same period in 2012. The increase in interest expense was primarily due to interest on the $300.0 million aggregate principal amount of our 7.50% Senior Notes that were issued late in the third quarter of 2012 partially offset by a decrease in interest expense attributable to reduced borrowings under our revolving credit facility and the repurchase of the 4.375% convertible senior notes during the second quarter of 2013.

The estimated annual effective tax rates for 2013 and 2012 were 36.7% and 38.1%, respectively. The effective income tax rates for the nine months ended September 30,2013 and 2012 were 37.0% and 37.9%, respectively. The effective income tax rate for the nine months ended September 30, 2013 was higher than the estimated annual effective tax rate due to change in state tax estimates. The effective tax rate for the nine months ended September 30, 2012 was lower than the estimated annual effective tax rate due to change in state tax estimates.

Included in net income of $67.7 million for the nine months ended September 30,2013 was $23.6 million, net of income taxes, related to the sale of Carrizo UK Huntington Ltd (“Carrizo UK”), which is included in net income from discontinued operations, net of income taxes in the accompanying consolidated statements of operations.

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Liquidity and Capital Resources

Capital Expenditures Plan and Funding Strategy. The 2013 capital expenditures plan currently includes $550.0 to $560.0 million for drilling and completion and $240 million for leasehold and seismic. We intend to finance the remainder of our 2013 capital expenditures plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital expenditures plan could vary depending upon various factors, including the availability and cost of drilling rigs and completion services, land and industry partner issues, our available cash flow and financing, success of drilling and completion programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. Below is a summary of capital expenditures through September 30, 2013:

	Capital Expenditures for the Three Months Ended						Year to Date
	March 31, 2013		June 30, 2013		September 30, 2013		September 30, 2013
	(In thousands)
Eagle Ford	$	101,735	$	88,210	$	96,992	$	286,937
Marcellus	18,888		19,459		9,840		48,187
Niobrara	11,817		22,106		13,461		47,384
Barnett and Other	4,257		3,460		6,246		13,963
Total drilling and completion	136,697		133,235		126,539		396,471
Total leasehold and seismic	89,274		30,182		26,348		145,804
Total	$	225,971	$	163,417	$	152,887	$	542,275

The capital expenditures presented above exclude capitalized interest, capitalized overhead and asset retirement obligations.

For 2014, our expected capital expenditures plan (which remains subject to our Board's approval) is $600.0 to $620.0 million for drilling and completion and $75 million for leasehold and seismic.

Sources and Uses of Cash. Our primary use of cash is capital expenditures related to our drilling and completion programs and, to a lesser extent, our leasehold and seismic programs. In addition, on October 31, 2013, we completed the acquisition of acreage located in Ohio from Avista, for a purchase price of approximately $73.2 million in cash, including closing adjustments and reimbursements of certain past costs. For the nine months ended September 30,2013, we funded our capital expenditures with cash provided by operations, cash on hand, net proceeds from the sale of assets, including the sales of non-core assets, and borrowings under our revolving credit facility. Potential sources of future liquidity include the following:

• Cash provided by operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oilfield services. We hedge a portion of our forecasted production to mitigate the risk of a decline in oil and gas prices.

• Revolving credit facility. As of November 1, 2013, we had no borrowings outstanding and $0.9 million in letters of credit outstanding under the revolving credit facility, which reduce the amounts available under the revolving credit facility. The amount we are able to borrow with respect to the borrowing base of the revolving credit facility is subject to compliance with, and limited by, the financial covenants and other provisions of the credit agreement governing our revolving credit facility.

• Asset sales. In order to fund our capital expenditures plan, we may consider the sale of certain properties or assets, provided we are able to sell such assets on terms that are acceptable to us. During the third quarter of 2013, we agreed in three separate transactions to sell certain non-core assets, including substantially all of our remaining Barnett Shale assets, certain non-core assets in East Texas, and acreage in non-core areas of the Marcellus Shale, for an aggregate agreed upon sale price of $248.5 million and the assumption of certain liabilities and contractual obligations, subject to customary closing conditions and purchase price adjustments. As of November 1, 2013, we have received aggregate net proceeds related to the three separate transactions of approximately $218.4 million. In addition, as a consequence of certain post-closing adjustments and holdbacks, we could receive up to an additional $23.8 million in cash proceeds related to such sales.

• Securities offerings. As situations or conditions arise, we may choose to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.

• Joint ventures. Joint ventures with third parties including those through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both.

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Overview of Cash Flow Activities.Net cash provided by operating activities from continuing operations were $310.3 million and $176.6 million for the nine months ended September 30,2013 and 2012, respectively. The increase was primarily due to increased crude oil production and gas prices in the first nine months of 2013 as compared to the same period in 2012.

Net cash used in investing activities from continuing operations were $503.4 million and $436.2 million for the nine months ended September 30,2013 and 2012, respectively. The increase related primarily to lower proceeds received from sales of oil and gas properties in the first nine months of 2013 as compared to the same period in 2012.

Net cash provided by financing activities from continuing operations were $17.4 million and $247.1 million for the nine months ended September 30,2013 and 2012, respectively. The decrease related primarily to the proceeds from the issuance of $300.0 million of 7.50% Senior Notes in September 2012.

Liquidity and Cash Flow Outlook

Economic downturns may adversely affect our ability to access capital markets in the future. We currently believe that cash provided by operating activities, proceeds from the sale of assets, carry resulting from our Niobrara joint venture transactions and borrowings under our revolving credit facility will be sufficient to fund our immediate cash flow requirements. Cash provided by operating activities from continuing operations is primarily driven by production and commodity prices. To manage our exposure to commodity price risk and to provide a level of certainty in the cash flows that will support our capital expenditures plan, we hedge a portion of our forecasted production and, as of September 30, 2013, we had hedged approximately 55,000 MMBtu/d of natural gas for the remainder of 2013. Additionally, we had hedged approximately 10,100 Bbls/d of oil for the remainder of 2013. Our borrowing base under our revolving credit facility is $470.0 million as of October 31, 2013. As of November 1, 2013, we had no borrowings outstanding under our revolving credit facility and had issued $0.9 million in letters of credit, which reduce the amounts available under our revolving credit facility. Additionally, as described under “Sources and Uses of Cash” above, the amount we are 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 borrowing base under our revolving credit facility is affected by our lenders’ assumptions with respect to future oil and gas prices. Our borrowing base may decrease if our lenders reduce their expectations with respect to future oil and gas prices from those assumptions used to determine our existing borrowing base. Upon closing of the sale of Barnett Shale assets on October 31, 2013, the borrowing base was automatically reduced to $470.0 million. The next borrowing base redetermination is scheduled to occur in the Spring of 2014.

If cash provided by operating activities from continuing operations, proceeds from asset sales, funds available under our revolving credit facility and the other sources of cash described under “Sources and Uses of Cash” are insufficient to fund the remainder of our 2013 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our planned 2013 capital expenditure plan, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties. Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may use a portion of our internally generated cash flows, proceeds from asset sales or borrowings to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings.

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Contractual Obligations

The following table sets forth estimates of our contractual obligations as of September 30, 2013 (in thousands):

	2013		2014		2015		2016		2017		2018 and Beyond		Total
Long-term debt (1)	$	—	$	—	$	—	$	87,000	$	—	$	904,425	$	991,425
Interest on long-term debt (2)	26,737		77,441		77,441		74,663		74,444		119,331		450,057
Operating leases	435		1,846		1,792		1,770		1,770		7,964		15,577
Drilling and completion services (3)	25,099		37,325		9,892		1,165		—		—		73,481
Pipeline volume commitments (3)	3,616		13,406		13,294		7,735		2,941		12,850		53,842
Asset retirement obligations and other (4)	2,230		11,902		8,787		4,212		1,743		6,505		35,379
Total Contractual Obligations (5)	$	58,117	$	141,920	$	111,206	$	176,545	$	80,898	$	1,051,075	$	1,619,761

(1) At September 30, 2013, we had $87.0 million of borrowings outstanding under the revolving credit facility which matures in 2016. On October 9, 2013 the credit facility was amended to extend the maturity date from 2016 to 2018.

(2) Interest on long-term debt is based on the 8.625% Senior Notes, the 7.50% Senior Notes, 4.375% Convertible Senior Notes, and our revolving credit facility average interest rate of 3.44%.

(3) Drilling and 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.

(4) Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of September 30, 2013. Certain of such estimates and assumptions are inherently unpredictable and will differ from actuals results. See “Note 2. Summary of Significant Accounting Policies - Use of Estimates” for further discussion of estimates and assumptions that may affect the reported amounts.

(5) As a result of the non-core assets sales in October 2013, certain of the contractual obligations as of September 30, 2013 presented in the table above were reduced by an estimated $16.7 million as these obligations were assumed by the purchasers of such assets.

Financing Arrangements

Convertible Senior Notes

In May 2008, we issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028. These notes are convertible, using a net share settlement process, into a combination of cash and common stock that entitles holders of our 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 our conversion obligation in excess of such principal amount.

On June 3, 2013, we completed a tender offer to repurchase the convertible senior notes, with $4.4 million aggregate principal amount of convertible senior notes remaining outstanding. As of September 30, 2013, $4.4 million aggregate principal amount of convertible senior notes remained outstanding.

The holders of our remaining $4.4 million aggregate principal amount of convertible senior notes may require us to repurchase the remaining 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. We may also 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. We currently have no intention to redeem the remaining convertible senior notes prior to June 1, 2018.

Senior Secured Revolving Credit Facility

We are party to a senior secured revolving credit facility with Wells Fargo Bank, National Association as the administrative agent. The revolving credit facility is secured by substantially all of our U.S. assets and is guaranteed by all of our existing Material Domestic Subsidiaries (as defined in the revolving credit facility). Any subsidiary of ours that does not currently guarantee our obligations under our revolving credit facility that subsequently becomes a material domestic subsidiary (as defined under our revolving credit facility) will be required to guarantee our obligations under our revolving credit facility.

On October 9, 2013, a fourth amendment to the senior secured revolving credit facility (the "Fourth Amendment") 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 (subject to availability under the borrowing base),and (iii) approved a borrowing base of $530.0 million until the closing of the sale of substantially all of our Barnett Shale assets, at which time the approved borrowing base availability 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 our 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 borrowing base will be redetermined by the lenders at least semi-annually, generally on each May 1 and November 1, with the next redetermination expected in Spring 2014. The

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amount we are 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.

In addition, pursuant to the Fourth Amendment, the annual interest rate on each base rate borrowing has been decreased to (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 has been decreased to the adjusted LIBO Rate for the applicable interest period plus a margin between 1.50% and 2.50% (depending on the then-current level of borrowing base usage). As of September 30, 2013, we are subject to certain covenants under the terms of the revolving credit facility, as amended, which include, but are not limited to, the maintenance of the following financial covenants: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00; (2) a Current Ratio of not less than 1.00 to 1.00; (3) a ratio of Senior Debt to EBITDA of not more than 2.50 to 1.00; and (4) a ratio of EBITDA to Interest Expense of not less than 2.50 to 1.00 (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the credit agreement governing the revolving credit facility). As of September 30, 2013, the ratio of Total Debt to EBITDA was 2.44 to 1.00, the Current Ratio was 1.73 to 1.00, the ratio of Senior Debt to EBITDA was 0.20 to 1.00 and the ratio of EBITDA to Interest Expense was 5.02 to 1.00. Total Debt and Senior Debt, as defined in the credit agreement governing the revolving credit facility, are net of cash and cash equivalents.

Our revolving credit facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

Our revolving credit facility is subject to customary events of default, including a change in control (as defined in the credit agreement governing our revolving credit facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the credit agreement governing our 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 September 30, 2013, we had $87.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 3.44%. At September 30, 2013, we had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Upon closing of the sale of Barnett Shale assets, the borrowing base was automatically reduced to $470.0 million. Future availability under the borrowing base is subject to the terms and covenants of the revolving credit facility. The revolving credit facility is used to fund ongoing working capital needs and the remainder of our 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.

Critical Accounting Policies

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from the estimates. These policies and estimates are described in our Annual Report on Form 10-K for the year ended December 31, 2012. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, income taxes and commitments and contingencies.

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The table below presents results of the U.S. full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling test to changes in 12 month average oil and gas prices. The prices included represent the unweighted average market prices for sales of oil and gas on the first calendar day of each month during the 12-month period ended September 30, 2013. This sensitivity analysis is as of September 30, 2013 and, accordingly, does not consider drilling results, production and prices subsequent to September 30, 2013 that may require revisions to our proved reserve estimates.

	12 Month Average		Cushion/(Impairment)	Increase/(Decrease) from Cushion
U.S. Full Cost Pool Scenarios	Oil Price ($/Bbl)	Gas Price ($/Mcf)	(in millions)	(in millions)
September 30, 2013 Actual	$102.66	$2.80	$217	$—
Oil and Gas Price Sensitivity
Oil and Gas +10%	$112.16	$3.15	$402	$185
Oil and Gas -10%	$93.16	$2.44	$32	$(185)
Oil Price Sensitivity
Oil +10%	$112.16	$2.80	$356	$139
Oil -10%	$93.16	$2.80	$78	$(139)
Gas Price Sensitivity
Gas +10%	$102.66	$3.15	$263	$46
Gas -10%	$102.66	$2.44	$171	$(46)

Volatility of Oil and Gas Prices

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of oil and gas.

We review the carrying value of our oil and gas properties on a quarterly basis using the full cost method of accounting. See “Summary of Critical Accounting Policies—Oil and Gas Properties,” in our Annual Report on Form 10-K for the year ended December 31, 2012.

We use various types of derivative instruments to manage our exposure to commodity price risk and to provide a level of certainty in our forward cash flows supporting our capital expenditure plan. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination or expiration. Our current strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 60 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations for the period in which the changes occur.

The fair value of derivative instruments at September 30, 2013 and December 31, 2012 was a net asset of $3.9 million and $29.2 million, respectively. The following sets forth a summary of the distribution of net fair value of our derivative instruments for each counterparty in a net asset position:

Counterparty	September 30, 2013		December 31, 2012
Credit Suisse	57	%	40	%
Societe Generale	27	%	22	%
BNP Paribas	13	%	33	%
Regions	2	%	—	%
BBVA Compass	1	%	3	%
Wells Fargo	—	%	2	%
Total	100	%	98	%

Master netting agreements are in place with each of these counterparties. Because the counterparties are investment grade financial institutions, we believe we have minimal credit risk and accordingly do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, we are exposed to credit risk to the extent of nonperformance by the counterparties to our derivative instruments. Although we do not currently anticipate such nonperformance, we continue to monitor the financial viability of our counterparties. Because Credit Suisse, Wells Fargo, Societe Generale, Regions

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and BBVA Compass are lenders under our revolving credit facility, we are not required to post collateral with respect to derivatives instruments in a net liability position with these counterparties, as the contracts are secured by our revolving credit facility.

The following sets forth a summary of our crude oil derivative positions at average NYMEX prices as of September 30, 2013:

Period	Type of Contract	Volumes (in Bbls/d)	Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)		Weighted Average Short Put  Price ($/Bbl)		Weighted Average Put Spread ($/Bbl)
Q4 2013	Swaps	4,000	$	94.15
	Collars	6,100	$	87.75	$	105.68
FY 2014	Swaps	5,996	$	92.36
	Collars	3,000	$	88.33	$	104.26
	Three-way collars	500	$	85.00	$	107.75	$	65.00	$	20.00
FY 2015	Swaps	3,250	$	90.64
	Collars	700	$	90.00	$	100.65
	Three-way collars	1,000	$	85.00	$	105.00	$	65.00	$	20.00
FY 2016	Three-way collars	667	$	85.00	$	104.00	$	65.00	$	20.00

The following sets forth a summary of our natural gas derivative positions at average NYMEX prices as of September 30, 2013:

Period	Type of Contract	Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q4 2013	Swaps	55,000	$	4.58
FY 2014	Swaps	40,000	$	4.07
	Calls	10,000			$	5.50
FY 2015	Swaps	10,000	$	4.33

For the three and nine months ended September 30,2013 and 2012, we recorded the following related to our oil and gas derivative instruments:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Realized gain on derivative instruments, net	$	1,313		$	9,450		$	9,320		$	30,544
Unrealized loss on derivative instruments, net	(28,971		)	(24,168		)	(25,806		)	(3,569		)
Gain (loss) on derivative instruments, net	$	(27,658	)	$	(14,718	)	$	(16,486	)	$	26,975

Forward-Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, including our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, timing and amounts of production, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, capital expenditure plans, planned evaluation of prospects, probability of prospects having oil and gas, expected production or reserves, pipeline connections, increases in reserves, acreage, working capital requirements, commodity price risk management activities and the impact on our average realized prices, the availability of expected sources of liquidity to implement the Company’s business strategies, accessibility of borrowings under our credit facility, future exploration activity, drilling, completion and fracturing of wells, land acquisitions, production rates, forecasted production, growth in production, development of new drilling programs, participation of our industry partners, exploration and development expenditures, the impact of our business strategies, the benefits, results, effects, availability of and results of new and existing joint ventures and sales transactions, receipt of receivables, drilling carry, proceeds from sales, and all and any other statements regarding future operations, financial results, business plans and cash needs and other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “plan,” “believe” and similar

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expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, actions and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, borrowing base determinations and availability under our credit facility, evaluations of the Company by lenders under our credit facility the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information, property acquisition risks, availability of equipment, actions by our midstream and other industry partners, weather, availability of financing, actions by lenders, our ability to obtain permits and licenses, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability of and completion of land acquisitions, completion and connection of wells, and other factors detailed in the “Risk Factors” and other sections of our Annual Report on Form 10-K for the year ended December 31, 2012 and in our other filings with the SEC, including this quarterly report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2012. There have been no material changes to the disclosure regarding our exposure to certain market risks made in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of September 30, 2013 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended September 30, 2013 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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.

Item 1A. Risk Factors

There were no material changes to the factors discussed in Part I. Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

Avista Utica Shale 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”), and ACP III Utica LLC (“ACP III”), both affiliates of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP together with its affiliates, “Avista”). Under the terms of this Utica Shale joint venture, the Company and Avista had the right to contribute cash and properties to acquire and develop acreage in the Utica Shale play.

ACP II is also the Company’s joint venture partner in the Marcellus Shale. In connection with its Avista Marcellus joint venture, the Company was issued in 2008, “B Units” in ACP II that entitled the Company to increasing percentages of ACP II’s distributions to Avista if specified internal rates of return and return on investment thresholds with respect to Avista’s investment in ACP II were achieved.

The Avista Utica joint venture agreements established an area of mutual interest between the Company and Avista and provided the Company options on specified categories of properties to increase its participating interest in such properties to equal Avista’s. Under the joint venture agreements, the Company served as operator of the Avista Utica joint venture properties and agreed to provide certain management services to Avista related to the Utica joint venture. Avista or its designee has the right to become a co-operator of the joint venture properties if (i) Avista sells substantially all of its interests in the Avista Utica joint venture properties or (ii) the Company default under the terms of any pledge of its interest in the Avista Utica joint venture properties. Additionally, the Company’s “B Unit” interest in ACP II incorporated ACP II’s interests in the Avista Utica joint venture, and the Company was granted similar “B Units” in ACP III.

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 Shale play to a third party. Simultaneously with the closing of this Utica Shale 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 $72.9 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 Utica Shale joint venture agreements to provide that the expiration date of its 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% interest in approximately 11,000 acres pursuant to the terms of the Avista Utica joint venture agreement. The Company and Avista also agreed that after the option was exercised, the Company’s participating interest in subsequently acquired properties within the 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.

The area of mutual interest for the Utica joint venture, consisting of the portions of the State of Ohio that are prospective for Utica Shale exploration, was to have remained in place until the earliest to occur of the following events, at which time the area of mutual interest would only continue to apply to those areas where the joint venture is active: (i) September 1, 2014, (ii) ACP III’s investment reaches $170.0 million and Avista declines to participate in specified Utica acquisitions or other specified

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conditions are met, (iii) upon ACP II’s or ACP III’s request to be designated (or have its designee designated) as a co-operator of the properties, (iv) upon the Company's required designation of ACP II or ACP III (or either’s designee) as a co-operator of the applicable properties in connection with a default by the Company under the terms of any pledge of its interest in the Utica joint venture properties, (v) the sale by Avista of substantially all of its interest in the Utica joint venture properties or (vi) termination of the ACP III management services agreement. Each party’s ability to transfer its interest in the Utica joint venture to third parties was generally subject to “tag along” rights. Avista’s tag along rights did not apply upon a change of control of the Company.

Avista Transaction. On October 31, 2013, the Company completed the acquisition of approximately 5,900 net acres located primarily in Guernsey and Noble counties, Ohio from Avista (the “Avista Transaction”). The transaction had an effective date of July 1, 2013, and the Company paid Avista approximately $73.2 million in cash, subject to post-closing adjustments. The Company had an ownership in the working interest of the properties acquired through the Utica Joint Venture. The properties in the Utica Joint Venture were held on an equal basis by the Company and Avista. The agreement provides for post-closing price and acreage adjustments and indemnities. The Avista Transaction was initially funded with proceeds from the sale of substantially all of our remaining properties in the Barnett Shale as disclosed below.

In connection with the Avista Transaction, the Company terminated the Utica Shale Joint Venture agreements described above. After giving effect to the Avista Transaction, the Company and Avista remain working interest partners in approximately 10,000 acres in the Utica Shale net to the Company with the Company acting as the operator of the jointly owned properties which are now subject to standard joint operating agreements. The Company has established a new area of mutual interest that has been significantly reduced in coverage area and now applies only to certain of those areas in which the Company and Avista jointly own properties.

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 a party to prior arrangements with affiliates of Avista Capital Holdings LP.

The terms of the joint ventures with Avista in the Utica Shale and the Marcellus Shale as well as the Avista Transaction and the other acquisition transactions described above with Avista were approved by a special committee of the Company’s disinterested 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.

Barnett Shale Transaction. On October 31, 2013, the Company closed on the previously announced definitive agreement to sell, effective July 1, 2013, substantially all of its remaining oil and gas assets in the Barnett Shale (the “EnerVest Properties”) 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., EV Properties, L.P., and EnerVest Holding, L.P. (collectively, “EnerVest”). The effective date of this sale was July 1, 2013. The Company received net cash proceeds of approximately $188.9 million at the closing and, as a consequence of certain post-closing adjustments and holdbacks, the Company could receive up to an additional $20.2 million in cash proceeds. EnerVest also agreed to assume certain liabilities and contractual obligations. The parties each agreed to provide certain indemnities to the other. Estimated total proved reserves associated with the EnerVest Properties, as determined by the Company's third party engineers at year-end 2012, were approximately 303.5 Bcf. The Company plans to use the proceeds to repay borrowings under its revolving credit facility, to initially fund the Avista Transaction and to partially fund the remainder of our 2013 capital expenditures plan. The Company currently expects that the EnerVest Properties will result in a loss on the sale in the fourth quarter of 2013 as the proved reserves attributable to the EnerVest Properties represent 40% of the Company's proved reserves as of September 30, 2013 and therefore the sale is expected to significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the Company’s U.S. cost center. Additionally, the Company currently anticipates that the EnerVest Properties will result in an increase in its future depreciation, depletion and amortization rate, and therefore will negatively affect its future reported earnings.

A copy of the purchase and sale agreement and the first amendment to the purchase and sale agreement are filed as Exhibits 2.1 and 2.2 to this Form 10-Q and are incorporated herein by reference. The foregoing description of the purchase and sale agreement as amended does not purport to be complete and is qualified in its entirety by reference to the full text of such agreements.

Revenues, expenses and related earnings from the EnerVest Properties will be reported in the Company's financial results through October 31, 2013.

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The accompanying Pro Forma Financial Statements (see Exhibit 99.1) give effect to the sale of the Divested Properties as described in such statements and are incorporated herein by reference:

• Unaudited Pro Forma Condensed Consolidated Balance Sheet as of September 30, 2013

• Unaudited Pro Forma Condensed Consolidated Statements of Operations for the Nine Months Ended September 30, 2013 and for the Year Ended December 31, 2012

The accompanying Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Year Ended December 31, 2012 also includes the effect to the sale of a significant portion of the Company's Barnett Shale assets to Atlas Resource Partners, L.P. which closed in the second quarter of 2012.

The pro forma adjustments do not reflect any use of proceeds from the sale other than repayment of amounts outstanding under the Company’s senior secured revolving credit facility with the remaining proceeds invested in cash and cash equivalents.

Item 6. Exhibits

The following exhibits are required by Item 601 of Regulation S-K and are filed as part of this report:

Exhibit Number		Exhibit Description
*2.1	–	Purchase and Sale Agreement, dated as of September 3, 2013, among affiliates of EnerVest, Ltd. and Carrizo Oil & Gas, Inc., CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, Inc. The schedules to the Purchase and Sale Agreement have been omitted pursuant to item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.
*2.2	–	First Amendment to the Purchase and Sale Agreement, dated as of September 5, 2013, among affiliates of EnerVest, Ltd. and Carrizo Oil & Gas, Inc., CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, Inc. supplementally upon request.
*31.1	–	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	–	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	–	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	–	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1		Unaudited Pro Forma Condensed Consolidated Balance Sheet of Carrizo Oil & Gas, Inc. as of September 30, 2013 and Unaudited Pro Forma Condensed Consolidated Statements of Operations for the Nine Months Ended September 30, 2013 and for the Year Ended December 31, 2012.
*101	–	Interactive Data Files

* Filed herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Carrizo Oil & Gas, Inc. (Registrant)
Date:	November 4, 2013	By:	/s/ Paul F. Boling
		Chief Financial Officer, Vice President, Secretary and Treasurer (Principal Financial Officer)
Date:	November 4, 2013	By:	/s/ David L. Pitts
		Vice President and Chief Accounting Officer (Principal Accounting Officer)

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EX-2.1

Exhibit 2.1

PURCHASE AND SALE AGREEMENT

among

CARRIZO OIL & GAS, INC.,

CLLR, INC.,

HONDO PIPELINE, INC.
and
MESCALERO PIPELINE, LLC

as Seller

and

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

ENERVEST HOLDING, L.P.

as Buyer

dated

September 3, 2013

TABLE OF CONTENTS

			Page
ARTICLE I DEFINITIONS AND INTERPRETATION			1
	Section 1.1	Defined Terms	1
	Section 1.2	Interpretations	1
ARTICLE II PURCHASE AND SALE			2
	Section 2.1	Purchase and Sale	2
	Section 2.2	Excluded Assets	4
	Section 2.3	Revenues and Expenses	4
ARTICLE III PURCHASE PRICE			4
	Section 3.1	Purchase Price	4
	Section 3.2	Adjustments to Purchase Price	5
	Section 3.3	Adjustment Methodology	6
	Section 3.4	Preliminary Settlement Statement	6
	Section 3.5	Final Settlement Statement	7
	Section 3.6	Disputes	7
	Section 3.7	Allocation of Purchase Price for Tax Purposes	7
	Section 3.8	Allocated Value	8
ARTICLE IV REPRESENTATIONS AND WARRANTIES OF SELLER			8
	Section 4.1	Organization, Existence	8
	Section 4.2	Authorization	8
	Section 4.3	No Conflicts	8
	Section 4.4	Consents	9
	Section 4.5	Bankruptcy	9
	Section 4.6	Litigation	9
	Section 4.7	Material Contracts	9
	Section 4.8	No Violation of Laws	10
	Section 4.9	Preferential Rights	11
	Section 4.10	Personal Property	11
	Section 4.11	Imbalances	11
	Section 4.12	Current Commitments	11

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TABLE OF CONTENTS

(continued)

			Page
	Section 4.13	Contribution Requirements	11
	Section 4.14	Non-Consent Elections	11
	Section 4.15	Payout Balances	11
	Section 4.16	Environmental	11
	Section 4.17	Production Taxes	12
	Section 4.18	Tax Partnerships	12
	Section 4.19	Brokers’ Fees	12
	Section 4.20	Investment Company	12
	Section 4.21	Regulatory Status	12
	Section 4.22	Current Plugging Obligations	13
	Section 4.23	Royalties	13
	Section 4.24	Easements	13
	Section 4.25	Oil and Gas Operations	13
ARTICLE V BUYER’S REPRESENTATIONS AND WARRANTIES			13
	Section 5.1	Organization; Existence	13
	Section 5.2	Authorization	13
	Section 5.3	No Conflicts	14
	Section 5.4	Consents	14
	Section 5.5	Bankruptcy	14
	Section 5.6	Litigation	14
	Section 5.7	Financing	14
	Section 5.8	Independent Evaluation	14
	Section 5.9	Brokers’ Fees	15
	Section 5.10	Accredited Investor	15
ARTICLE VI CERTAIN AGREEMENTS			15
	Section 6.1	Conduct of Business	15
	Section 6.2	Notification of Breaches	16
	Section 6.3	Successor Operator	17
	Section 6.4	Governmental Bonds	17
	Section 6.5	Record Retention	17
	Section 6.6	License	18

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TABLE OF CONTENTS

(continued)

			Page
	Section 6.7	Like-Kind Exchange	18
	Section 6.8	Marketing and Transportation Agreements	18
ARTICLE VII CONDITIONS TO CLOSING			19
	Section 7.1	Buyer’s Conditions to Closing	19
	Section 7.2	Seller’s Conditions to Closing	19
ARTICLE VIII CLOSING			20
	Section 8.1	Date of Closing	20
	Section 8.2	Place of Closing	20
	Section 8.3	Closing Obligations	20
	Section 8.4	Records	22
ARTICLE IX ACCESS; CONFIDENTIALITY; USE; DISCLAIMERS			23
	Section 9.1	Access	23
	Section 9.2	Confidentiality; Use	25
	Section 9.3	Disclaimers	26
ARTICLE X TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS			27
	Section 10.1	Seller’s Title	27
	Section 10.2	Notice of Title Defects; Defect Adjustments	28
	Section 10.3	Casualty or Condemnation Loss	32
	Section 10.4	Preferential Rights to Purchase and Consents to Assign	33
ARTICLE XI ENVIRONMENTAL MATTERS			34
	Section 11.1	Environmental Conditions	34
	Section 11.2	NORM, Wastes and Other Substances	38
ARTICLE XII ASSUMPTION; SURVIVAL; INDEMNIFICATION			38
	Section 12.1	Assumption by Buyer and Retention by Seller	38
	Section 12.2	Indemnities of Seller	39
	Section 12.3	Indemnities of Buyer	40
	Section 12.4	Limitation on Liability	40
	Section 12.5	Express Negligence	40
	Section 12.6	Exclusive Remedy	40
	Section 12.7	Indemnification Procedures	41
	Section 12.8	Survival	43

-iii-

TABLE OF CONTENTS

(continued)

			Page
	Section 12.9	Waiver of Right to Rescission	43
	Section 12.10	Non-Compensatory Damages	43
	Section 12.11	Disclaimer of Application of Anti-Indemnity Statutes	44
	Section 12.12	Waiver of Trade Practices Act	44
ARTICLE XIII TERMINATION, DEFAULT AND REMEDIES			45
	Section 13.1	Right of Termination	45
	Section 13.2	Effect of Termination	45
	Section 13.3	Return of Documentation and Confidentiality	45
ARTICLE XIV MISCELLANEOUS			45
	Section 14.1	Expenses and Taxes	45
	Section 14.2	Assignment	46
	Section 14.3	Publicity	46
	Section 14.4	Notices	47
	Section 14.5	Removal of Name	48
	Section 14.6	Further Cooperation	48
	Section 14.7	Filings and Certain Governmental Approvals	49
	Section 14.8	Entire Agreement	49
	Section 14.9	Parties in Interest	49
	Section 14.10	Amendment	49
	Section 14.11	Waiver; Rights Cumulative	49
	Section 14.12	Governing Law; Dispute Resolution	49
	Section 14.13	Severability	51
	Section 14.14	Counterparts	51
	Section 14.15	Employees	51
	Section 14.16	Hedging Contracts	51
	Section 14.17	Office Lease	52

-iv-

TABLE OF CONTENTS

(continued)

LIST OF APPENDICES, EXHIBITS AND SCHEDULES
Appendices
Appendix 1	Definitions
Appendix 2	Permitted Encumbrances
Appendix 3	Illustrative List of Items that are not Title Defects
Exhibits
Exhibit A-1	Fee Interests
Exhibit A-2	Leases
Exhibit A-3	Wells
Exhibit B-1	Rights of Way
Exhibit B-2	Flow Lines
Exhibit C-1	Form of Assignment and Bill of Sale for Carrizo and CLLR
Exhibit C-2	Form of Assignment and Bill of Sale for certain Midstream Assets
Exhibit D	Form of Assignment and Assumption for certain Contracts
Exhibit E	Form of Deed
Exhibit F	Proportionate Shares
Exhibit G	Form of Office Lease
Schedules
Schedule 1	Excluded Assets
Schedule 2	Permitted Liens
Schedule 3.8	Allocated Values
Schedule 4.3	Conflicts
Schedule 4.4(a)	Consent
Schedule 4.4(b)	Customary Post-Closing Consents
Schedule 4.6	Litigation
Schedule 4.7	Material Contracts
Schedule 4.8	Violation of Laws
Schedule 4.9	Preferential Rights
Schedule 4.10	Personal Property
Schedule 4.11	Imbalances
Schedule 4.12	Current Commitments
Schedule 4.13	Contribution Requirements
Schedule 4.14	Non-Consent Elections
Schedule 4.15	Payout Balances
Schedule 4.16	Environmental
Schedule 4.17	Production Taxes
Schedule 4.18	Tax Partnerships
Schedule 4.21	Regulatory Status
Schedule 4.22	Plugging Obligations
Schedule 4.24	Easements
Schedule 4.25	Oil and Gas Operations
Schedule 6.1	Conduct of Business
Schedule 6.4	Governmental Bonds

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PURCHASE AND SALE AGREEMENT

THIS PURCHASE AND SALE AGREEMENT (as may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is executed as of this 3rd day of September, 2013 (the “Execution Date”), and is among Carrizo Oil & Gas, Inc., a Texas corporation (“Carrizo”), CLLR, Inc., a Delaware corporation (“CLLR”) and Hondo Pipeline, Inc., a Delaware corporation (“Hondo”), and Mescalero Pipeline, LLC, a Delaware limited liability company (“Mescalero,” and together with Carrizo, and CLLR and Hondo, “Seller”) and EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P., each a Delaware limited partnership, and EnerVest Holding, L.P., a Texas limited partnership (collectively, “Buyer”).

Recitals

A.    Seller desires to sell and convey, and Buyer desires to purchase and pay for, all of Seller’s right, title and interest in and to certain oil and gas properties located in the Barnett Shale area of the State of Texas (in Tarrant, Denton and Dallas Counties) effective as of the Effective Time (as hereinafter defined).

B.    Certain of the Properties (as hereinafter defined) are owned of record by Carrizo for the benefit of CLLR, a wholly owned subsidiary of Carrizo.

C.    Certain of the midstream Assets are owned by Hondo and Mescalero.

NOW, THEREFORE, for and in consideration of the mutual promises contained herein, the benefits to be derived by each party hereunder, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller and Buyer agree as follows:

ARTICLE I

DEFINITIONS AND INTERPRETATION

Section 1.1Defined Terms. In addition to the terms defined in the preamble of this Agreement, for purposes hereof, the capital terms used herein and not otherwise defined shall have the meanings set forth in this Appendix 1.

Section 1.2Interpretations. In construing this Agreement: (a) no consideration shall be given to the captions of the articles, sections, subsections or clauses, which are inserted for convenience in locating the provisions of this Agreement and not as an aid to construction and shall not be interpreted to limit or otherwise affect the provisions of this Agreement or the rights and other legal relations of the parties hereto; (b) no consideration shall be given to the fact or presumption that either party had a greater or lesser hand in drafting this Agreement; (c) examples shall not be construed to limit, expressly or by implication, the matter they illustrate; (d) the word “includes” and its syntactic variants mean, unless otherwise specified, “includes, but is not limited to” and corresponding syntactic variant expressions; (e) words such as “herein,” “hereby,” “hereafter,” “hereof,” “hereto,” “hereabove,” “hereinabove,” “hereinbelow” and “hereunder” refer to this Agreement as a whole and not to any particular article, section or provision of this Agreement;

(f) whenever the context requires, the plural shall be deemed to include the singular, and vice versa; (g) each gender shall be deemed to include the other gender, when such construction is appropriate; (h) all of the Exhibits and Schedules referred to in this Agreement are part of this Agreement and each Exhibit and Schedule is hereby incorporated herein as if set forth in full herein; (i) references to a Person are also to its permitted successors and permitted assigns; (j) all references in this Agreement to Exhibits, Schedules, Articles and Sections refer to the corresponding Exhibits, Schedules, Articles and Sections of this Agreement unless expressly provided otherwise; (k) unless expressly stated otherwise, the word “or” is not exclusive; and (l) unless otherwise expressly provided herein, any agreement, instrument or Law defined or referred to herein means such agreement, instrument or Law as from time to time amended, modified or supplemented, including (in the case of agreements or instruments) by waiver or consent and (in the case of Laws) by succession of comparable successor Laws and reference to all attachments thereto and instruments incorporated therein.

ARTICLE II

PURCHASE AND SALE

Section 2.1Purchase and Sale. Subject to the terms and conditions of this Agreement, Seller agrees to sell, and Buyer agrees to purchase and pay for, in each Buyer’s respective undivided proportionate interests set forth opposite each Buyer’s name in Exhibit F hereto (each Buyer’s “Proportionate Share”), all of Seller’s and its Affiliates’ right, title and interest in and to the following (less and except for the Excluded Assets, collectively, the “Assets”):

(a)the oil and gas mineral fee interests more particularly described in Exhibit A-1 (collectively, the “Fee Interests”);

(b)the oil and gas leases, more particularly described in Exhibit A-2 (collectively, the “Leases”), together with any and all other rights, titles and interests of Seller in and to (i) the leasehold estates created thereby and (ii) the lands covered by the Leases or Fee Interests included in units with which the Leases or Fee Interests may have been pooled or unitized (the “Lands”), including in each case, fee interests, royalty interests, overriding royalty interests, production payments, net profits interests, carried interests, reversionary interests and all other interests of any kind or character;

(c)all oil, gas, water, disposal or injection wells located on the Leases and the Lands or on other leases or lands with which the Leases and/or the Lands may have been pooled or unitized (collectively, the “Wells”) including those described in Exhibit A-3, and all Hydrocarbons produced therefrom or allocated thereto (the Fee Interests, Leases, the Lands and the Wells being collectively referred to hereinafter as the “Properties”);

(d)all rights and interests in, under or derived from all unitization and pooling agreements in effect with respect to the Properties and the units created thereby which accrue or are attributable to the interests of Seller in the Properties;

2

(e)all Applicable Contracts, but only with respect to rights and obligations arising thereunder from and after the Effective Time, except for rights relating to the Assumed Obligations;

(f)to the extent that they may be assigned, all permits, licenses, servitudes, easements, rights-of-way (including those set forth on Exhibit B-1) and other surface agreements to the extent used in connection with the ownership or operation of the Properties or the Personal Property (the “Easements”);

(g)all equipment, machinery, fixtures, and other real, personal and mixed property, operational and nonoperational, known or unknown, located on the Properties or the other Assets described above or used or held for use primarily in connection with the Properties or other Assets described above, including well equipment, SCADA, telemetry and radio equipment, radio towers, casing, rods, tanks, boilers, buildings, tubing, pumps, motors, fixtures, machinery, compression equipment, flow lines (including those set forth on Exhibit B-2), pipelines, gathering systems, processing and separation facilities, structures, materials and other items used or held for use primarily in the operation or maintenance thereof (“Personal Property”);

(h)all Imbalances relating to the Properties or other Assets arising from and after the Effective Time;

(i)all geophysical and other seismic and related technical data and information relating to the Assets, including any geologic and geophysical interpretations (collectively, the “Seismic Data and Information”), to the extent such data and information may be assigned without Third Party consent or expenditures beyond tape copying costs and expenses unless Buyer has paid such expenditures and entered into a license agreement with the Third Party licensor;

(j)all of the rights, titles and interests of Seller in and to all of the files, records, information and data, whether written or electronically stored, relating solely to the Assets, including: (i) land and title records (including abstracts of title, title opinions and title curative documents); (ii) contract files; (iii) correspondence; (iv) maps, engineering data and reports; (v) log books and Operating Data; and (vi) facility and well records (“Records”), which Records will be provided to Buyer in electronic form if so maintained by Seller in such format as maintained by Seller and otherwise in paper form; provided, however, that Seller shall have the right to retain copies of any or all such Records, subject to Section 9.2(b), and provided further, that Records shall not include any of the foregoing to the extent a transfer or disclosure would be restricted by obligations of confidentiality or to the extent that such information is privileged.;

(k)subject to the provisions in Article VI, any asset acquired by Seller following the Execution Date that would otherwise constitute an “Asset” if owned by Seller as of the Execution Date and for which Buyer will assume the Operating Expenses arising therefrom;

(l)any claims and causes of action arising under or with respect to any Asset and all proceeds arising from such claims and causes of action, including any settlements thereof, to the extent such claims, causes of action and proceeds are attributable to the period after the Effective Time or that relate to an Assumed Obligation;

3

(m)all audit rights arising under any of the Applicable Contracts or otherwise with respect to any period after the Effective Time pertaining to any of the Assets or that relate to an Assumed Obligation and, in each case, that do not relate to any Retained Obligations; and

(n)any amounts held in suspense by Seller or any Third Party on Seller’s behalf that relate to the period following the Effective Time.

Section 2.2Excluded Assets. Seller shall reserve and retain all of the Excluded Assets.

Section 2.3Revenues and Expenses.

(a)Subject to the provisions hereof, Seller shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall remain responsible for all Operating Expenses, in each case attributable to the Assets for the period of time prior to the Effective Time. Subject to the provisions hereof, and subject to the occurrence of the Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds), and shall be responsible for all Operating Expenses, in each case, attributable to the Assets for the period of time from and after the Effective Time. All Operating Expenses attributable to the Assets, in each case that are: (i) incurred with respect to operations conducted or production prior to the Effective Time shall be paid by or allocated to Seller and (ii) incurred with respect to operations conducted or production after the Effective Time shall be paid by or allocated to Buyer. “Operating Expenses” means all operating expenses (including obligations to pay working interests, Royalties or other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons relating to the Properties) and capital expenditures incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to the Assets under the relevant operating agreement or unit agreement, if any, but excluding Taxes and Retained Obligations.

(b)For purposes of allocating production (and proceeds of production and other proceeds) under this Section 2.3, (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Properties when they pass through the pipeline connecting into the storage facilities into which they are run for such Hydrocarbons above the inlet connection in the storage facilities and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Properties when they pass through the royalty measurement meters, delivery point sales meters or custody transfer meters on the gathering lines or pipelines through which they are transported (whichever meter is closest to the well). Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings or gauging and strapping data is not available.

ARTICLE IIIPURCHASE PRICE

Section 3.1Purchase Price. The purchase price for the Assets shall be Two Hundred Eighteen Million Dollars ($218,000,000.00) (the “Purchase Price”), payable in United States currency by wire transfer in same day funds as and when provided in this Agreement.

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Section 3.2Adjustments to Purchase Price. The Purchase Price shall be adjusted as follows, and the resulting amount shall be herein called the “Adjusted Purchase Price”:

(a)The Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i)an amount equal to all proceeds received by Buyer, or reasonably estimated by Buyer to be received, following Closing, in each case attributable to the sale of Hydrocarbons produced from or allocable to the Assets prior to the Effective Time, net of any sales, excise or similar Taxes not already taken into account under Section 3.2(b)(iii), incurred in connection therewith and not reimbursed to Buyer by a Third Party purchaser and net of all Royalties (provided that to the extent such a netting for Royalties is made, Buyer shall assume the obligation to pay the netted amounts to the Persons to whom such amounts are due);

(ii)an amount equal to all Operating Expenses paid by Seller and not reimbursed to Seller pursuant to a joint interest billing that are attributable to the Assets during the Interim Period, whether paid before or after the Effective Time;

(iii) the amount of all Production Taxes prorated to Buyer pursuant to Section 14.1(b) but paid by Seller;

(iv)the amount provided in Section 10.2(f) for Title Benefits if the Title Benefit Amounts have been determined prior to Closing;

(v)an amount equal to the value of any Imbalances by which Seller is underproduced priced at $4.00 per Mcf for gas Imbalances, existing as of the Effective Time;

(vi)any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Seller and Buyer.

(b)The Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i)an amount equal to all proceeds received by Seller, or reasonably estimated by Seller to be received, following the Effective Time, in each case attributable to the sale of Hydrocarbons produced from or allocable to the Assets during the Interim Period, net of any sales, excise or similar Taxes not already taken into account under Section 3.2(a)(iii), incurred in connection therewith and not reimbursed to Seller by a Third Party purchaser and net of all Royalties (provided that to the extent such a netting for Royalties is made, Seller shall assume the obligation to pay the netted amounts to the Persons to whom such amounts are due);

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(ii)an amount equal to all other proceeds received by Seller (other than from the sale of Hydrocarbons produced from or allocable to the Assets before the Effective Time) to which Buyer is entitled pursuant to Section 2.3;

(iii)the amount of all Production Taxes prorated to Seller pursuant to Section 14.1(b) but to be paid by Buyer;

(iv)an amount equal to the value of any Imbalances by which Seller is overproduced priced at $4.00 per Mcf for gas Imbalances, existing as of the Effective Time;

(v)the amount provided in Section 10.2(b)(i) for Title Defects if the Title Defect Amounts have been determined prior to Closing;

(vi)the amount provided in Section 11.1(b)(i) for Environmental Conditions if the Remediation Amounts have been determined prior to Closing;

(vii)the amounts provided in Section 9.1(b), Section 10.2(b)(ii), Section 10.3(c)(iii), Section 10.3(d), Section 10.4, or Section 11.1(b) for any Properties and other Assets excluded from the Assets pursuant to such Section;

(viii)the amount of any funds held in suspense as described in Section 2.1(n); and

(ix)any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Seller and Buyer.

Section 3.3Adjustment Methodology. When available, actual figures will be used for the adjustments to the Purchase Price at the Closing. To the extent actual figures are not available, estimates will be used subject to final adjustments in accordance with Section 3.5.

Section 3.4Preliminary Settlement Statement. Not less than five Business Days prior to the Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “Preliminary Settlement Statement”) that shall set forth the Adjusted Purchase Price, reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the calculation of the adjustments used to determine such amount, together with reasonable supporting documentation and the designation of Seller’s account for the wire transfers of funds as set forth in Section 8.3(a)(vii). Within three Business Days after receipt of the Preliminary Settlement Statement, Buyer will deliver to Seller a written report containing all changes with the explanation therefor that Buyer proposes to be made to the Preliminary Settlement Statement. The Preliminary Settlement Statement, as agreed upon by the parties, will be used to adjust the Purchase Price at Closing. If the parties are unable to reach agreement, the Preliminary Settlement Statement as prepared by Seller will be used to adjust the Purchase Price at Closing, absent manifest error.

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Section 3.5Final Settlement Statement. On or before 180 days after the Closing, a final settlement statement (the “Final Settlement Statement”) will be prepared by Buyer, based on actual income and expenses during the Interim Period and which takes into account all final adjustments made to the Purchase Price (including pursuant to Section 11.1(b), Section 10.2(b) and Section 10.2(f)) and shows the resulting final Purchase Price (“Final Price”). The Final Settlement Statement shall set forth the actual proration of the amounts required by this Agreement (including Section 2.3). As soon as practicable, and in any event within 30 days, after receipt of the Final Settlement Statement, Seller shall return a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “Settlement Statement Dispute Notice”). If the Final Price set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer, the Final Settlement Statement and the Final Price, shall be final and binding on the parties hereto. Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price shall be paid by the owing party within ten days to the owed party. All amounts paid pursuant to this Section 3.5 shall be delivered in United States currency by wire transfer of immediately available funds to the account specified in writing by the relevant party.

Section 3.6Disputes. If Seller and Buyer are unable to resolve the matters addressed in the Settlement Statement Dispute Notice, each of Buyer and Seller shall, within 14 Business Days after the delivery of such Settlement Statement Dispute Notice, summarize its position with regard to such dispute in a written document and submit such summaries to Ernst & Young LLP, or such other party as the parties may mutually select (the “Accounting Arbitrator”), together with the Settlement Statement Dispute Notice, the Final Settlement Statement and any other documentation such party may desire to submit. The Accounting Arbitrator shall calculate the Final Price based on the information submitted by the parties and in accordance with the adjustment methodology set forth in this Article III, and render its decision no later than 20 days after receiving the parties’ respective submissions. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against any of the parties in any court of competent jurisdiction. The costs of such Accounting Arbitrator shall be borne one-half by Buyer and one-half by Seller. Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price, as determined by the Accounting Arbitrator, shall be paid by the owing party within ten days to the owed party.

Section 3.7Allocation of Purchase Price for Tax Purposes. For federal income tax purposes, Buyer and Seller agree that the Final Price shall be allocated among the Assets transferred to Buyer by each of (i) Carrizo, (ii) CLLR, (iii) Hondo and (iv) Mescalero, in accordance with the principles of Section 1060 of the Code and the Treasury Regulations and in a manner reasonably consistent with the Allocated Values, and will be set forth in separate schedules proposed by Seller and acceptable to Buyer (the “Tax Allocations”). If Seller and Buyer are unable to agree upon the Tax Allocations within 15 days of delivery of proposed schedules by Seller, the matter will be submitted to the Accounting Arbitrator for binding resolution in accordance with Section 3.6. Buyer and Seller shall each bear their own respective costs of obtaining such resolution, except that any fees and expenses related to the procurement of services from an Accounting Arbitrator shall be shared equally by Buyer and Seller. Buyer and Seller agree that (i) the Tax Allocations, as

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agreed to by Seller and Buyer, shall be used by Seller and Buyer as the basis for reporting asset values and other items for purposes of all federal, state and local Tax returns, including Internal Revenue Service Form 8594, provided that in the event Buyer and Seller cannot agree to the Tax Allocations, the commercially reasonable allocation of Seller shall be acceptable to the parties, and (ii) neither they nor their Affiliates will take positions inconsistent with such Tax Allocations in notices to Governmental Authorities, in audit or other proceedings with respect to Taxes, in notices to preferential purchase right holders, or in other documents or notices relating to the transactions contemplated by this Agreement, except as required by applicable Law. Seller makes no representation or warranty as to the accuracy of any value determined hereunder.

Section 3.8Allocated Value. The “Allocated Value” for any Asset equals the portion of the unadjusted Purchase Price allocated to such Asset on Schedule 3.8, and such Allocated Value shall be used in calculating adjustments to the Purchase Price as provided herein. Seller makes no representation or warranty as to the accuracy of any Allocated Value.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SELLER

Except as otherwise provided below or in the disclosures schedules, Seller represents and warrants to Buyer the matters set out in this Article IV:

Section 4.1Organization, Existence. Seller is a corporation or limited liability company duly organized, validly existing and in good standing under the laws of the jurisdiction of its incorporation. Seller has all requisite power and authority to own and operate its property (including its interests in the Assets) and to carry on its business as now conducted. Seller is duly licensed or qualified to do business as a foreign entity, and is in good standing in all jurisdictions in which such qualification is required by Law, except where the failure to qualify or be in good standing could not reasonably be expected to have a Material Adverse Effect.

Section 4.2Authorization. Seller has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Seller of this Agreement and the Transaction Documents to which Seller is a party have been duly and validly authorized and approved by all necessary corporate or limited liability company action on the part of Seller. This Agreement is, and the Transaction Documents to which Seller is a party when executed and delivered by Seller will be, the valid and binding obligation of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

Section 4.3No Conflicts. Subject to the receipt of the consents set forth on Schedule 4.4(a), all matters disclosed on Schedule 4.3 and the Customary Post-Closing Consents, including those set forth on Schedule 4.4(b), the execution, delivery and performance by Seller of this Agreement and the consummation of the transactions contemplated herein will not (a) conflict with or result in a breach of any provisions of the organizational documents or other governing documents of Seller, (b) result in a default or the creation of any Encumbrance or give rise to any

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right of termination, cancellation, or acceleration under any of the terms, conditions or provisions of any Lease, operating agreement, note, bond, mortgage, indenture, license or other material agreement to which any Seller is a party or by which any Seller or the Assets may be bound or (c) violate any Law applicable to Seller or any of the Assets the violation of which could reasonably be expected to have a Material Adverse Effect.

Section 4.4Consents. Except (a) as set forth in Schedule 4.4(a), (b) Customary Post-Closing Consents, including those set forth on Schedule 4.4(b), and (c) Preferential Right to Purchase set forth in Schedule 4.9 and other than those consents that will have been obtained on or prior to the Closing Date, there are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case) that are necessary in connection with the transfer of the Assets or the consummation of the transactions contemplated by this Agreement by Seller.

Section 4.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened against Seller.

Section 4.6Litigation. Except as set forth in Schedule 4.6, there is no suit, action or litigation by any Person by or before any Governmental Authority, and no legal, administrative or arbitration proceedings pending or, to Seller’s Knowledge, threatened against the Assets or Seller relating to the Assets or that could otherwise reasonably be expected to have a Material Adverse Effect.

Section 4.7Material Contracts.

(a)Schedule 4.7 sets forth all Applicable Contracts of the type described below to which Seller (or one or more of its Affiliates) is a party and that relate to the Assets (collectively, the “Material Contracts”):

(i)any Applicable Contract that has resulted or can reasonably be expected to result in aggregate payments by Seller (or its Affiliates) of more than $125,000 for (y) Applicable Contracts that have been in effect for at least one year, during the last fiscal year (based solely on the terms thereof and realized volumes and without regard to any expected increase in volumes or revenues) or (z) Applicable Contracts that have been in effect for less than one year, during the current or any subsequent fiscal year (based solely on the terms thereof and current volumes and without regard to any expected increase in volumes or revenues);

(ii)any Applicable Contract that has resulted or can reasonably be expected to result in aggregate revenues to Seller (or its Affiliates) of more than $125,000 for (y) Applicable Contracts that have been in effect for at least one year, during the last fiscal year (based solely on the terms thereof and realized volumes and without regard to any expected increase in volumes or revenues) or (z) Applicable Contracts that have been in effect for less than one year, during the current or any subsequent fiscal year (based solely on the terms thereof and current volumes and without regard to any expected increase in volumes or revenues);

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(iii)any Hydrocarbon purchase and sale, exchange, gathering, transportation, processing or similar Applicable Contract that is not terminable without penalty on 60 days’ or less notice;

(iv)any Applicable Contract that constitutes a lease under which Seller (or its Affiliates) is the lessor or the lessee of real or personal property which lease (A) cannot be terminated by Seller without penalty or cost upon 60 days’ or less notice and (B) involves an annual base rental of more than $50,000;

(v)any indenture, mortgage, loan, credit or sale-leaseback or similar Applicable Contract secured by any of the Assets;

(vi)any farmout or farmin agreement relating to the Assets;

(vii)any futures, hedge, swap, collar, put, call, floor, cap, option or other Applicable Contract that is intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons;

(viii)any Applicable Contract that constitutes a non-competition agreement, area of mutual interest agreement or any other agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, Buyer after the Closing will be able to conduct business, including area of mutual interest Applicable Contracts;

(ix)any Applicable Contract containing “tag along” or similar rights allowing a Third Party to participate in future sales of any of the Assets or interests therein;

(x)any Applicable Contract related to Seismic Data and Information that is not an Excluded Asset;

(xi)any Applicable Contract with any Affiliate of Seller that will not be terminated prior to Closing; and

(xii)any saltwater disposal contract and any compressor contract not otherwise listed in this Section 4.7 relating to the Assets.

(b)Except as set forth on Schedule 4.7, the Material Contracts are in full force and effect in all material respects, and there exist no material defaults under the Material Contracts by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Material Contracts, and no event has occurred that with notice or lapse of time, or both, constitute any default under any such Material Contract by Seller or, to Seller’s Knowledge any other Person who is a party to such Material Contract. Seller has not received or given any unresolved written notice of termination or default with regards to any Material Contract.

Section 4.8No Violation of Laws. Except as set forth on Schedule 4.8, Seller is not the subject of any pending or, to Seller’s Knowledge, threatened regulatory compliance or

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enforcement action related to the Assets and Seller has not received written notice alleging any violation of any Law applicable to the Assets, in each case, the resolution of which is currently outstanding. This Section 4.8 does not include any matters with respect to Environmental Laws, such matters being addressed exclusively in Section 4.16.

Section 4.9Preferential Rights. Except as set forth in Schedule 4.9, there are no Preferential Rights to Purchase that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby.

Section 4.10Personal Property. To Seller’s Knowledge, except as set forth in Schedule 4.10, all Personal Property constituting a part of the Assets are in a state of reasonable repair (ordinary wear and tear excepted) so as to be suitable for the purposes of which such Personal Property was constructed, obtained or currently being used, except as would reasonably be expected to have a Material Adverse Effect.

Section 4.11Imbalances. Schedule 4.11 sets forth to Seller’s Knowledge all Imbalances associated with the Properties as of the Effective Time.

Section 4.12Current Commitments. Schedule 4.12 sets forth, as of the date of this Agreement, all authorities for expenditures (“AFEs”) relating to the Properties to drill or rework Wells or for other capital expenditures pursuant to any of the Material Contracts or any applicable joint operating agreement that have been sent or received by Seller and which in each case require expenditures in excess of $100,000 and for which all of the activities anticipated in such AFEs or commitments have not been completed by the date of this Agreement.

Section 4.13Contribution Requirements. Except as set forth on Schedule 4.13 and only with respect to Assets that are operated by Seller, there are no material contribution requirements with respect to defaulting co-owners as to any of such Assets. To Seller’s Knowledge, except as set forth on Schedule 4.13 and only with respect to Assets that are not operated by Seller, there are no material contribution requirements with respect to defaulting co-owners as to any of the Assets.

Section 4.14Non-Consent Elections. Except as set forth on Schedule 4.14, Seller has not elected nor been deemed to have elected as a non-consenting party with respect to any Well, proposal or other operations with respect to the Assets.

Section 4.15Payout Balances. Schedule 4.15 contains a list of the estimated status of any “payout” balance (net to the interest of Seller), as of the dates shown in such Schedule, for each Property that is subject to a reversion or other adjustment at some level of cost recovery or payout.

Section 4.16Environmental.

(a)Except as set forth on Schedule 4.16, Seller’s ownership, use and operation of the Assets is in compliance with the regulatory requirements of all applicable Environmental

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Laws, except for such failures to comply as have not had, and would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect.

(b)Except as set forth on Schedule 4.16, Seller has not received, nor to Seller’s Knowledge has any Third Party operator received, any notice of violation of any Environmental Law relating to the Assets, which alleged failure(s) to comply would reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect.

Section 4.17Production Taxes. Except as disclosed on Schedule 4.17, during the period of Seller’s ownership of the Assets, all conservation, ad valorem, property, excise, production, severance and similar Taxes and assessments (including penalties and interest) based on or measured by the ownership or operation of the Assets, the production of Hydrocarbons therefrom, or the receipt of proceeds therefrom (“Production Taxes”) that have become due and payable have been properly paid, other than Production Taxes which have been contested in good faith, and no such contests are ongoing. Except as set forth in Schedule 4.17, all returns with respect to Production Taxes that are required to be filed by Seller have been filed and there are no audits, investigations, litigation or other proceedings pending, or, to the Knowledge of Seller, threatened, against Seller before any Governmental Authority relating to the payment of any Production Taxes imposed or based on Seller’s interest in the Properties or Hydrocarbons produced from such interest in the Properties.

Section 4.18Tax Partnerships. Except as set forth on Schedule 4.18, to Seller’s Knowledge, no Property is subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute, and in the case of any Property subject to a tax partnership agreement, the tax partnership has an election in effect under Section 754 of the Code.

Section 4.19Brokers’ Fees. Seller has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall have any responsibility or which would burden the Assets.

Section 4.20Investment Company

. Seller is not (a) an investment company or a company controlled by an investment company within the meaning of the Investment Company Act of 1940, as amended, or (b) subject in any respect to the provisions of said Act.

Section 4.21Regulatory Status. All pipeline systems and related facilities comprising the Assets are (i) “gathering facilities” that are exempt from regulation by the Federal Energy Regulatory Commission under the Natural Gas Act of 1938, as amended (“NGA”), and (ii) except as set forth on Schedule 4.21, not subject to the requirement to file a tariff with the Railroad Commission of Texas pursuant to Texas Administrative Code, Title 16, Section 7.315. Seller is not a natural gas company within the meaning of the NGA, and, Seller has not operated any of the Assets in a manner that would subject such Seller to the jurisdiction of, or invoke regulation by, the

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Federal Energy Regulatory Commission under the Natural Gas Policy Act of 1978, as amended, or the NGA with respect to the Assets.

Section 4.22Current Plugging Obligations. Except as set forth in Schedule 4.22, Seller has not received any notices or demands from any Governmental Authority or, to Seller’s Knowledge, any other Person to plug any Wells or perform any mechanical integrity tests.

Section 4.23Royalties. Except for amounts that are being held in suspense, Seller has paid all Royalties due by Seller or if not paid, is contesting such Royalties in good faith.

Section 4.24Easements. Except as set forth in Schedule 4.24, each of the Easements used or held primarily for use in connection with the ownership or operation of the Assets is legal, valid, binding, enforceable and in full force and effect and Seller is not in breach of or, to its Knowledge, default under any such Easement, and to Seller’s Knowledge, no event has occurred or circumstance exists that, with the delivery of notice, the passage of time or both, would constitute such a breach or default, or permit the termination, modification or acceleration of rent under any such Easement, in each case that could reasonably be expected to cause a Material Adverse Effect.

Section 4.25Oil and Gas Operations. Except as provided in Schedule 4.25, all Wells operated by Seller have been drilled, completed, operated and produced in accordance with generally accepted oil and gas field practices and in compliance in all material respects with applicable leases, pooling and unit agreements, joint operating agreements and Laws, except for such practices and non-compliance as have not had, and would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect.

ARTICLE V

BUYER’S REPRESENTATIONS AND WARRANTIES

Except as otherwise provided below, Buyer hereby represents and warrants to Seller the matters set forth in this Article V.

Section 5.1Organization; Existence. Each Buyer is a limited partnership duly organized, validly existing and in good standing under the laws of the state of its formation and has all requisite power and authority to own and operate, or operate through its contract operator, EnerVest Operating, L.L.C., its property and to carry on its business as now conducted. Buyer is duly licensed or qualified to do business as a foreign limited partnership, and is in good standing in all jurisdictions in which such qualification is required by Law, except where the failure to qualify or be in good standing would not have a material adverse effect on Buyer’s ability to consummate the transactions contemplated in this Agreement.

Section 5.2Authorization. Buyer has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Buyer of this Agreement and each Transaction Document to which Buyer is a party have been duly and validly authorized and approved by all necessary company action on the part of Buyer. This Agreement is, and the Transaction Documents to which Buyer is a party when executed and delivered by Seller

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will be, the valid and binding obligation of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

Section 5.3No Conflicts. The execution, delivery, and performance by Buyer of this Agreement and the consummation of the transactions contemplated herein will not (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer, (b) result in a default or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or other agreement to which Buyer is a party or by which Buyer or any of its property may be bound or (iii) violate any Law applicable to Buyer or any of its property, except in the case of clauses (ii) and (iii) where such default, lien, encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect on Buyer’s ability to consummate the transactions contemplated in this Agreement.

Section 5.4Consents. There are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case) that would be applicable in connection with the consummation of the transactions contemplated by this Agreement by Buyer.

Section 5.5Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened against Buyer.

Section 5.6Litigation. There is no suit, action, investigation or inquiry by any Person or by or before any Governmental Authority, and no legal, administrative or arbitration proceedings pending, or, to Buyer’s knowledge, threatened against Buyer, or to which Buyer is a party, that could reasonably be expected to have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated in this Agreement.

Section 5.7Financing. Buyer has on the date hereof, and shall have on the Closing Date sufficient funds with which to pay the Purchase Price and consummate the transactions contemplated by this Agreement.

Section 5.8Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transaction contemplated herein, Buyer, except to the extent of Seller’s representations in Article IV, and the special warranty of title in the Conveyance Documents, (a) has relied or shall rely solely on its own independent investigation and evaluation of the Assets and the advice of its own legal, tax, economic, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives, consultants or advisors engaged by Seller and (b) has undertaken such due diligence pertaining to the Properties and other Assets as Buyer deems adequate.

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Section 5.9Brokers’ Fees. Buyer has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Seller or any Affiliate of Seller shall have any responsibility.

Section 5.10Accredited Investor.

(a)Buyer is aware that the sale of the Assets conveyed herein by Seller has not been registered under the Securities Act or under the securities Laws of any state. Buyer represents and warrants that (i) Buyer is an accredited investor as such term is defined in Regulation D of the Securities Act and (ii) Buyer is acquiring an interest in the Assets for its own account for use in Buyer’s trade or business and not with a view toward or for sale in connection with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act (including the rules and regulations thereunder). Buyer represents and warrants that if it sells, transfers or otherwise disposes of the Assets, it will do so in compliance with the Securities Act and any other applicable securities Laws (including state securities Laws).

(b)Buyer is aware that no federal or state agency has made any findings or determinations as to the fairness of purchasing the Assets conveyed herein or any recommendations or endorsement with respect thereto.

(c)Buyer recognizes that its representations and warranties in this Section 5.10 are material inducements to Seller’s acceptance of Buyer’s purchase of the Assets conveyed herein, and without such representations and warranties, Buyer’s purchase would not be accepted.

ARTICLE VICERTAIN AGREEMENTS

Section 6.1Conduct of Business. Except as set forth in Schedule 6.1 and as required by any Lease, Applicable Contract, Law or Governmental Authority, including as contemplated by the AFEs and other capital commitments described in Section 4.12, Seller agrees that from and after the date hereof until Closing, except as contemplated by this Agreement or as consented to in advance in writing by Buyer (which consent shall not be unreasonably withheld, conditioned or delayed), to:

(a)operate the Assets in a good and workman like manner and consistent with past practice;

(b)maintain the books of account and records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of Seller and applicable Law;

(c)(i) not propose or commit to any single operation, or series of related operations, reasonably anticipated to require capital expenditures by the owner of the Assets in excess of $50,000, (ii) make any capital expenditures with respect to any single operation, or series of related operations, in excess of $50,000 or (iii) propose or make capital expenditures subject to clauses (i) and (ii) in excess of $500,000 in the aggregate; provided, however, that Seller may consent

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to any AFEs from Third Parties to drill, frac or complete wells unless Seller and Buyer mutually agree in writing that Seller shall not consent to such AFE;

(d)maintain insurance coverage on the Assets furnished as of the Execution Date by Third Parties in the amounts and of the types in place as of the Execution Date;

(e)maintain all material permits, approvals and registrations from and with Governmental Authorities applicable to the Assets that are maintained by Seller or its Affiliate as of the Execution Date in all material respects;

(f)not transfer, sell, mortgage, pledge or dispose of or otherwise encumber any of the Assets other than (i) Permitted Encumbrances, (ii) the sale and/or disposal of Hydrocarbons in the ordinary course of business and (iii) sales of equipment and other Assets that are no longer necessary or useful in the operation of the Assets or for which replacement equipment has been obtained;

(g)not settle, waive, or compromise any claim or other proceeding in a manner that would adversely affect in any material respect the ownership, operation, or use of the Assets or for which Buyer would have liability; and

(h)not commit to do any of the items described in Section 6.1(c), Section 6.1(f) and Section 6.1(g).

Buyer acknowledges that Seller owns undivided interests in certain of the Properties where Seller is not the operator, and Buyer agrees that the acts or omissions of the other working interests owners (including the operators) who are not Seller or an Affiliate of Seller shall not constitute a breach of the provisions of this Section 6.1, nor shall any action required by a vote of working interest owners constitute such a breach so long as Seller and its Affiliates have not proposed an action that would be in violation of this Section 6.1 and, subject to Section 6.1(c), have voted their interest in a manner that complies with the provisions of this Section 6.1.

Section 6.2Notification of Breaches. Until the Closing,

(a)Buyer shall notify Seller promptly after Buyer obtains actual knowledge that any representation or warranty of Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect; and

(b)Seller shall notify Buyer promptly after any Seller obtains actual knowledge that any representation or warranty of Buyer contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Buyer prior to or on the Closing Date has not been so performed or observed in any material respect.

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Any of Buyer’s or Seller’s representations or warranties that are untrue or shall become untrue in any material respect between the Execution Date and the Closing Date, and any of Buyer’s or Seller’s covenants or agreements to be performed or observed prior to or on the Closing Date that have not been so performed or observed in any material respect, shall be considered not to have occurred for all purposes of this Agreement to the extent that any such breach of representation, warranty, covenant or agreement is (if curable) not cured by the Closing. No failure by Buyer or Seller, respectively, under Section 6.2(a) or (b), respectively, with respect to any matter that would not result, individually or in the aggregate with any other such matters, in a failure of the conditions to Closing of Seller set forth in Section 7.2(a) or (b) or of the conditions to Closing of Buyer set forth in Section 7.1(a) or (b) shall result in a failure of the conditions to Closing of Seller in Section 7.2(b) or in a failure of the conditions to Closing of Buyer in Section 7.1(b) respectively.

Section 6.3Successor Operator. While Buyer acknowledges that it desires to succeed Seller as operator of those Assets or portions thereof that Seller may presently operate, Buyer acknowledges and agrees that Seller cannot and does not covenant or warrant that Buyer shall become successor operator of the same since the Assets or portions thereof may be subject to operating or other agreements that control the appointment of a successor operator. Seller agrees, however, that as to the Assets it operates, it shall use its commercially reasonable efforts to support Buyer’s efforts to become successor operator (to the extent permitted under any joint operating agreement) effective as of the Closing and to designate and/or appoint by assignment, to the extent legally possible, Buyer as successor operator effective as of the Closing.

Section 6.4Governmental Bonds. Buyer acknowledges that no bonds, letters of credit and guarantees that have been posted by Seller or its Affiliates with Governmental Authorities and relating to the Assets are transferable to Buyer and any bonds, letter of credit and guarantees shall be cancelled by Seller at or after Closing. On or before the Closing Date, Buyer shall obtain, or cause to be obtained in the name of Buyer or its designee, replacements for the bonds and letters of credit listed on Schedule 6.4 and such guarantees, in each case to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guarantees posted by Seller and/or its Affiliates.

Section 6.5Record Retention. Each party, for the longer of a period of seven years and as required by Law, following Closing, will retain the Records and provide the other party, its Affiliates, and its and their officers, employees and representatives with reasonable access upon prior notice to the Records (to the extent that such other party has not retained the original or a copy) during normal business hours for review and copying at such other party’s expense; provided that any party may destroy Records from time to time and prior to the end of such period in accordance with its normal document retention policy as long as such party notifies the other party in advance and provides such other party an opportunity to copy such Records at such other party’s expense. Each party shall also provide the other party, its Affiliates and its and their officers, employees and representatives with reasonable access during normal business hours to Records relating to any indemnification claim made under this Agreement for review and copying at such other party’s expense.

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Section 6.6License. Buyer hereby grants to Carrizo and its wholly-owned Affiliates, effective from and after the Closing Date, a royalty-free perpetual license, without restriction, of all Seismic Data and Information that, immediately before the Closing, was owned (but not licensed from a Third Party) by Seller or its Affiliate. The license granted pursuant to this Section 6.6 is not assignable without consent of Buyer unless such assignment occurs in connection with the direct or indirect sale of all or substantially all of the assets or control of Carrizo.

Section 6.7Like-Kind Exchange. Either party may elect to structure this transaction as a like-kind exchange pursuant to Section 1031 of the Code, and the regulations promulgated thereunder, with respect to any or all of the Assets (a “Like-Kind Exchange”) at any time prior to the date of Closing. In order to effect a Like-Kind Exchange, non-electing party shall cooperate and do all acts as may be reasonably required or requested by the party electing for a Like-Kind Exchange with regard to effecting such Like-Kind Exchange, including, but not limited to, permitting such party to assign its rights under this Agreement to a Qualified Intermediary (“QI”) of such party’s choice in accordance with Treasury Regulation § 1.1031(k)-1(g)(4) or executing additional escrow instructions, documents, agreements or instruments to effect an exchange. Buyer reserves the right, at or prior to Closing, to assign its rights or a portion thereof under this Agreement with respect to any or all of the Assets to Buyer’s Qualified Exchange Accommodation Titleholder (as that term is defined in Revenue Procedure 2000-37) (“QEAT”) in connection with effecting a Like-Kind Exchange. Seller and Buyer acknowledge and agree that a whole or partial assignment of this Agreement to a QI or QEAT shall not release either Seller or Buyer from, or expand, any of their respective liabilities and obligations to each other under this Agreement. The party not participating in the Like-Kind Exchange shall not be obligated to pay any additional costs or incur any additional obligations in its sale or purchase, as applicable, of the Assets if such costs are the result of the other party’s Like-Kind Exchange, and the party electing to consummate the sale or purchase as a Like-Kind Exchange agrees to hold harmless and indemnify the other party from and against all claims, losses and liabilities, if any, resulting from the Like-Kind Exchange..

Section 6.8Marketing and Transportation Agreements. Seller shall use commercially reasonable efforts to obtain the consents necessary to assign any marketing and transportation agreements before Closing. However, if Seller is unable to obtain such consents prior to Closing, Seller shall, if requested by Buyer and if permitted under the terms of such agreements and applicable Law, make available the benefits of such marketing and transportation agreements to Buyer by marketing and selling Buyer’s Hydrocarbons through such agreements on the same terms and conditions as they exist on the Closing Date or such amended terms and conditions as Seller shall approve; provided, that Seller shall not be obligated to extend the stated term of any marketing and transportation agreements, including pursuant to any available renewal option; provided further, that Buyer shall use commercially reasonable efforts to replace such agreements as soon as practicable. If Seller markets and sells Buyer’s Hydrocarbons pursuant to this Section 6.8, Buyer shall deliver such quantity of Hydrocarbons to Seller as is sufficient to allow Seller to meet the minimum quantity and quality commitments under such agreement at the delivery point set forth therein. Buyer shall also fully comply with all other terms and conditions of such marketing and transportation agreements as if it were a party thereto. Buyer shall indemnify, defend, hold harmless and release the Seller Indemnified Parties against any Claims arising from or related

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to Seller’s marketing and transportation of Buyer’s gas, except for any claims actually resulting from the gross negligence or willful misconduct of Seller.

ARTICLE VIICONDITIONS TO CLOSING

Section 7.1Buyer’s Conditions to Closing. The obligations of Buyer to consummate the transactions provided for herein are subject, at the option of Buyer, to the fulfillment by Seller or waiver by Buyer, on or prior to the Closing of each of the following conditions:

(a)Representations. The representations and warranties of Seller set forth in this Agreement shall be true and correct in all material respects on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than individual representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except in the case where the failure of such representations and warranties to be so true and correct (without giving effect to any limitation as to materiality, Material Adverse Effect or any similar limitation contained therein), individually or in the aggregate, would not reasonably be expected to have a Material Adverse Effect.

(b)Performance. Seller shall have performed or complied in all material respects with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or at the Closing Date.

(c)No Legal Proceedings. No material suit, action or other proceeding by a Third Party shall be pending against Buyer or its Affiliates before any Governmental Authority seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages from Buyer or its Affiliates in connection with, the transactions contemplated by this Agreement.

(d)Title Defects and Environmental Conditions. The sum of (i) the amount of (A) all Title Defect Amounts determined pursuant to Section 10.2(d) with respect to Title Defects submitted on or before 45 days after the Execution Date which exceed the Title Defect Deductible and (B) all Remediation Amounts for Environmental Conditions determined pursuant to Section 11.1, which exceed the Environmental Condition Deductible, (ii) all Casualty Losses pursuant to Section 10.3, (iii) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.3(d), and (iv) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.4(c) or Section 10.4(f), shall be less than 25% of the Purchase Price

Section 7.2Seller’s Conditions to Closing. The obligations of Seller to consummate the transactions provided for herein are subject, at the option of Seller, to the fulfillment by Buyer or waiver by Seller, on or prior to the Closing of each of the following conditions:

(a)Representations. The representations and warranties by Buyer set forth in this Agreement shall be true and correct in all material respects on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than individual representations and warranties that refer to a

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specified date, which need only be true and correct on and as of such specified date), except in the case where the failure of such representations and warranties to be so true and correct (without giving effect to any limitation as to materiality, Material Adverse Effect or any similar limitation contained therein), individually or in the aggregate, would not reasonably be expected to have a Material Adverse Effect.

(b)Performance. Buyer shall have performed or complied in all material respects with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date.

(c)No Legal Proceedings. No material suit, action or other proceeding by a Third Party shall be pending against Seller or its Affiliates before any Governmental Authority seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages from Seller or its Affiliates in connection with, the transactions contemplated by this Agreement.

(d)Title Defects and Environmental Conditions. The sum of (i) the amount of (A) all Title Defect Amounts determined pursuant to Section 10.2(d) with respect to Title Defects submitted on or before 45 days after the Execution Date which exceed the Title Defect Deductible and (B) all Remediation Amounts for Environmental Conditions determined pursuant to Section 11.1, which exceed the Environmental Condition Deductible, (ii) all Casualty Losses pursuant to Section 10.3, (iii) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.3(d), and (iv) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.4(c) or Section 10.4(f), shall be less than 25% of the Purchase Price.

ARTICLE VIIICLOSING

Section 8.1Date of Closing. Subject to the conditions stated in this Agreement, the sale by Seller and the purchase by Buyer of the Assets pursuant to this Agreement (the “Closing”) shall occur on or before two Business Days after the satisfaction (or waiver) of all closing conditions set forth in Article VII, or such other date as Buyer and Seller may agree upon in writing. The date on which the Closing occurs is referred to herein as the “Closing Date”. The parties acknowledge and agree that the target closing date is October 31, 2013.

Section 8.2Place of Closing. The Closing shall be held at Seller’s offices located at 500 Dallas Street, Suite 2300, Houston, TX 77002.

Section 8.3Closing Obligations. At the Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)Buyer shall deliver to Seller:

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(i)a certificate duly executed by an authorized corporate officer of Buyer, dated as of the Closing, certifying on behalf of Buyer that the conditions set forth in Section 7.2 have been fulfilled;

(ii)a certificate duly executed by an authorized representative of Buyer, dated as of the Closing, (A) attaching and certifying on behalf of Buyer complete and correct copies of (1) the organization documents of Buyer, each as in effect as of the Closing and (2) evidence of Buyer’s authorization for the execution, delivery, and performance by Buyer of this Agreement and the transactions contemplated hereby and (B) certifying on behalf of Buyer the incumbency of each authorized representative of Buyer executing this Agreement or any document delivered in connection with the Closing;

(iii)the executed Assignment, in sufficient counterparts to facilitate recording in the applicable counties, covering the Assets;

(iv)the executed Assignment and Assumption;

(v)the executed Deed, in sufficient counterparts to facilitate recording in the applicable counties, covering the Assets;

(vi)subject to Section 3.4, the Preliminary Settlement Statement;

(vii)to the account designated in the Preliminary Settlement Statement, by direct bank or wire transfer in same day funds, the Adjusted Purchase Price;

(viii)any conveyances on official forms and related documentation reasonably necessary to transfer the Property to Buyer in accordance with requirements of any Governmental Authority; and

(ix)any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at the Closing.

(b)Seller shall deliver to Buyer:

(i)certificates duly executed by an authorized corporate officer of each Seller, dated as of the Closing, certifying on behalf of each Seller that the conditions set forth in Section 7.1 have been fulfilled;

(ii)a certificate duly executed by the authorized representative of each Seller, dated as of the Closing, (A) attaching and certifying on behalf of Seller complete and correct copies of (1) the certificate of incorporation or formation and the bylaws or operating agreement of Seller, each as in effect as of the Closing and (2) the resolutions of the Board of Directors of Seller authorizing the execution, delivery, and performance by such Seller of this Agreement and the transactions contemplated hereby and (B) certifying on behalf of Seller the incumbency of each

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authorized representative of such Seller executing this Agreement or any document delivered in connection with the Closing;

(iii)the executed Assignments, in sufficient counterparts to facilitate recording in the applicable counties covering the Assets;

(iv)the executed Assignment and Assumption;

(v)the executed Deed, in sufficient counterparts to facilitate recording in the applicable counties, covering the Assets;

(vi)subject to Section 3.4, the Preliminary Settlement Statement;

(vii)on forms supplied by Buyer and reasonably acceptable to Seller, transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Buyer of proceeds attributable to production from the Assets from and after the Effective Time, for delivery by Buyer to the purchasers of production;

(viii)any conveyances on official forms and related documentation necessary to transfer the Properties to Buyer in accordance with requirements of any Governmental Authority;

(ix)an executed statement described in Treasury Regulation Section 1.1445-2(b)(2) certifying that Seller is not a foreign person or is a disregarded entity whose owner is not a foreign person within the meaning of Section 1445 of the Code;

(x)full releases, effective as of the Closing Date, of all Encumbrances encumbering or affecting any of the Assets that are created under or pursuant to or evidenced by that certain Credit Agreement dated as of January 27, 2011, as the same has been amended through the Closing Date, among the Carrizo, as borrower, Wells Fargo, as administrative agent, arranger, bookrunner, and other agent and lender named therein, which releases will be in form and substance customary in the industry; provided, however, that Buyer shall have the opportunity to review and comment on such releases; and

(xi)any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at the Closing.

Section 8.4Records. In addition to the obligations set forth in Section 8.3 above, no later than 30 days following the Closing and pursuant to Buyer’s reasonable instructions, Seller shall deliver to Buyer the Records in either written or electronic format as available. From and after the Execution Date, Seller shall coordinate with Buyer and provide such commercially reasonable information to Buyer as may be reasonably necessary to permit Buyer to operate the Assets from and after the Closing and until receipt of the Records.

After execution of this Agreement and within five (5) Business Days prior to the Closing Date, Seller will deliver to Buyer, any requested Records available in digital format (“Digital Records”)

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upon such request by Buyer so that Buyer may prepare to take over operations on the Closing Date. Any Digital Records delivered to Buyer prior to Closing will be subject to the Confidentiality provision in Section 9.2 and the Confidentiality Agreement. If this Agreement is terminated, then Buyer will return the Digital Records pursuant to Section 13.3.

ARTICLE IX
ACCESS; CONFIDENTIALITY; USE; DISCLAIMERS

Section 9.1Access.

(a)From and after the date hereof and up to delivery of the Records to Buyer as provided in Section 8.4 (or earlier termination of this Agreement) but subject to the other provisions of this Section 9.1 and obtaining any required consents of Third Parties, including Third Party operators of the Assets (with respect to which consents Seller shall use commercially reasonable efforts to obtain), Seller shall afford to Buyer and its officers, employees, agents, accountants, attorneys, consultants and other authorized representatives (“Buyer’s Representatives”) reasonable access, during normal business hours, to the Assets and all Records and other documents in Seller’s or its Affiliates’ possession relating primarily to the Assets. If Buyer requests access to the Assets and all Records and other documents in Seller’s or its Affiliates’ possession relating primarily to the Assets outside of normal business hours and if such access is requested by Buyer as part of Buyer’s title review process, Seller will make reasonable efforts to provide such access. Seller shall also make available to Buyer and Buyer’s Representatives, upon reasonable notice during normal business hours, Seller’s and Seller’s Affiliates’ personnel knowledgeable with respect to the Assets so that Buyer may make such reasonable diligence investigation as Buyer considers reasonably necessary or appropriate. All investigations and due diligence conducted by Buyer or any Buyer’s Representative shall be conducted at Buyer’s sole cost, risk and expense and any conclusions made from any examination done by Buyer or any Buyer’s Representative shall result from Buyer’s own independent review and judgment and shall be conducted so as not to interfere unreasonably with the operation of the business of Seller and shall not require Seller to waive any attorney-client privilege nor to violate any contractual obligation. In addition, Seller shall provide Buyer with access to any records and to Seller’s Representatives to the extent reasonably requested and necessary to respond to any tax audit or inquiry suggesting that Buyer is liable as successor, transferee or member of a group having joint and several liability for any Taxes payable by Buyer but allocated to Seller or its Affiliates under Section 14.1; provided, however, Seller shall not be required to take any action pursuant to this Section 9.1 which would result in a waiver of attorney-client privilege.

(b)Buyer shall be entitled to conduct a Phase I environmental property assessment with respect to the Assets. Seller or its designee shall have the right to accompany Buyer and Buyer’s Representatives whenever they are on site on the Assets and also to collect split test samples if any are collected. Notwithstanding anything herein to the contrary, Buyer shall not have access to, and shall not be permitted to conduct any environmental due diligence (including any Phase I environmental property assessments) with respect to any Assets where Seller does not have the authority to grant access for such due diligence (provided, however, Seller shall use its commercially reasonable efforts to obtain permission from any Third Party to allow Buyer and Buyer’s Representatives such access). In the event that Buyer’s Phase I environmental property

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assessments identify actual or potential “recognized environmental conditions”, then Buyer may request Seller’s permission to conduct additional Phase II environmental property assessments to further assess such conditions. Any sampling, boring, drilling or other invasive investigation activities shall be considered “Phase II” activities. The additional Phase II environmental property assessment procedures relating to any additional investigation shall be submitted to Seller in a Phase II environmental property assessment plan, which shall include a written description of the proposed scope of the Phase II assessment, including a description of the activities to be conducted, and a description of the approximate location and expected timing of such activities. Seller may, in its sole discretion, approve said Phase II environmental property assessment plan, in whole or in part, and Buyer shall not have the right to conduct any activities set forth in such plan until such time that Seller has approved such plan in writing. Any such approved Phase II environmental property assessment plan shall be conducted by a reputable environmental consulting or engineering firm, approved in advance by Seller (such approval not to be unreasonably withheld or delayed) and, once approved, such environmental consulting or engineering firm shall be deemed to be a “Buyer’s Representative,” and any such assessment shall be performed in accordance with this Section 9.1 and in compliance with all Laws. If Seller denies Buyer permission to conduct additional Phase II environmental property assessments on an Asset or portion of an Asset, then Buyer may, at its sole discretion, exclude such Asset or portion thereof, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset or portion thereof.

(c)Buyer shall coordinate any environmental property assessments and physical inspections of the Assets with Seller and all applicable Third Party operators to minimize any inconvenience to or interruption of the conduct of business by Seller or such Third Party operators. Buyer shall abide by Seller’s and any Third Party operator’s safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Assets. Buyer hereby defends, indemnifies and holds harmless each of the operators of the Assets and Seller Indemnified Parties from and against any and all personal injury or property damage actually resulting from the access permitted pursuant to this Section 9.1 and the related due diligence activity conducted by Buyer or any Buyer’s Representative with respect to the Assets, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, SOLELY OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY A MEMBER OF SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

(d)Buyer will promptly provide a copy of any final environmental report prepared by any Third Party environmental consultant to Seller. Seller shall not be deemed by its receipt of said documents or otherwise as a result of Buyer’s environmental assessment process to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Assets or to the accuracy of said documents or the information contained therein, it being understood that Seller’s only representations or warranties with respect to environmental matters shall be those set forth in Section 4.16 of this Agreement.

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(e)Upon completion of Buyer’s due diligence, Buyer shall at its sole cost and expense and without any cost or expense to Seller or its Affiliates, (i) repair all damage done to the Assets in connection with Buyer’s due diligence in a manner that restores the Assets to the approximate same or better condition existing prior to commencement of Buyer’s due diligence and (ii) remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s due diligence. Any damage to the Assets (including the leasehold associated therewith) resulting from Buyer’s due diligence will be promptly corrected by Buyer.

(f)Buyer and Seller agree that any environmental consultant retained by Buyer, as a condition to its entry onto any of the Assets, shall obtain insurance coverage for general liability in an amount not less than $1,000,000 per occurrence and hold professional liability insurance. If the environmental consultant or Buyer fails to provide Seller with evidence of such insurance, Seller may deny the environmental consultant the right to enter upon the Assets.

Section 9.2Confidentiality; Use.

(a)Buyer acknowledges that, pursuant to its right of access to the Records or the Assets, Buyer will become privy to confidential and other information of Seller and that such confidential information shall be held confidential by Buyer and Buyer’s Representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets).

(b)If the Closing should occur, from and after the Closing and except as otherwise provided in this Agreement, Seller shall not, and shall cause its Affiliates and their respective officers, directors, employees, agents, consultants and other representatives (“Seller’s Representatives”) not to, disclose, use or copy any trade secrets and or proprietary or confidential information solely relating to the Assets, except for (i) disclosures and uses required by Law or stock exchange rules or information that is in the public domain or that after the Closing becomes part of the public domain through no fault of Seller or Seller’s Representatives after the Closing, (ii) disclosures to Affiliates, (iii) disclosures to financial institutions or other Third Party in connection with evaluation of a financing, sales or acquisition transaction provided that such financial institution or other Third Party is bound by a reasonable obligation of confidentiality covering such information and (iv) any trade secrets, proprietary or confidential information which becomes available to Seller, any of its Affiliates or any of their representatives on a non-confidential basis from a source that did not acquire such information from Seller or Buyer or any of their Affiliates on a confidential basis. Notwithstanding any of the foregoing and anything to the contrary in this Agreement, Seller shall have the non-exclusive right to use in the ordinary course of business any information about the Assets, including copies (retained by Seller) of (A) any geophysical and other seismic and related technical data and information relating to the Assets (including copies of any geologic and geophysical interpretations retained pursuant to Section 2.1(i)) and (B) any maps, engineering data and reports, reserve studies and evaluations, logs, Records or other data and information being transferred as part of the Assets; provided, however, that, except as required by Law, Seller shall, and shall cause Seller’s Representatives and each of their respective Affiliates to (i) keep such data and information confidential in accordance with the terms hereof, (ii) require any

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Third Party consultant or advisor to keep such information confidential in accordance with the terms hereof and (iii) continue to comply with the obligations under any Third Party confidentiality agreements with respect to such data or information or the Assets pursuant to the terms of such Third Party confidentiality agreements.

Section 9.3Disclaimers.

(a)Except as and to the extent expressly set forth in Article IV, or the special warranties of title contained in the Conveyance Documents, (i) Seller makes no representations or warranties, express, statutory or implied, and (ii) Seller expressly disclaims all liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to Buyer or any of its affiliates, employees, agents, consultants or representatives (including any opinion, information, projection or advice that may have been provided to Buyer by any of Seller’s representatives and including with respect to the Seismic Data and Information).

(b)EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV OF THIS AGREEMENT OR THE SPECIAL WARRANTIES OF TITLE CONTAINED IN THE CONVEYANCE DOCUMENTS, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, INCLUDING THE SEISMIC DATA AND INFORMATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS (INCLUDING FINANCIAL STATEMENTS) PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c)EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV OF THIS AGREEMENT OR THE SPECIAL WARRANTIES OF TITLE CONTAINED IN THE CONVEYANCE DOCUMENTS, SELLER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR

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CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT, SUBJECT TO BUYER’S RIGHTS UNDER SECTION 12.2(A), BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS, INCLUDING THE SEISMIC DATA AND INFORMATION, IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS OF THE ASSETS, INCLUDING THE SEISMIC DATA AND INFORMATION, AS BUYER DEEMS APPROPRIATE.

(d)OTHER THAN THOSE REPRESENTATIONS SET FORTH IN SECTION 4.16, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND SUBJECT TO BUYER’S RIGHTS UNDER SECTION 12.2, BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE. ANY INFORMATION FURNISHED ON THE DISCLOSURE SCHEDULES SHALL BE DEEMED TO MODIFY ALL OF THE REPRESENTATIONS AND WARRANTIES OF SELLER. THE INCLUSION OF ANY INFORMATION ON THE DISCLOSURE SCHEDULE SHALL NOT BE DEEMED TO BE AN ADMISSION OR ACKNOWLEDGMENT, IN AND OF ITSELF, THAT SUCH INFORMATION IS REQUIRED BY THE TERMS HEREOF TO BE DISCLOSED, IS MATERIAL TO SELLER, IS OUTSIDE THE ORDINARY COURSE OF BUSINESS INSISTENT WITH PAST PRACTICE, OR IS OTHERWISE REQUIRED TO BE INCLUDED ON SUCH SCHEDULE.

SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 9.3 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE X
TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS

Section 10.1Seller’s Title.

(a)General Disclaimer of Title Warranties and Representations. Except for the special warranty of title set forth in the Conveyance Documents and without limiting Buyer’s remedies for Title Defects set forth in this Article X, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Wells, Undrilled

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Locations or Fee Interests, and Buyer hereby acknowledges and agrees that Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Wells, Undrilled Locations or Fee Interests (i) before the Title Claim Date, shall be as set forth in Section 10.2 and (ii) after the Title Claim Date, shall be pursuant to the special warranty of title set forth in the Conveyance Documents.

(b)Special Warranty of Title. If the Closing occurs, then effective as of the Closing Date in the Conveyance Documents, the Assets are being conveyed by Seller “WHERE IS” and “AS IS”, and without any warranty of title, express or implied, except as to claims made by, through or under Seller, subject, however, to the Permitted Encumbrances. Said special warranties of title contained in the Conveyance Documents shall be subject to the further limitations and provisions of this Section 10.1(b). If Buyer provides written notice of a breach of this special warranty of title in the Conveyance Documents to Seller, Seller shall have a reasonable opportunity to cure such breach to the reasonable satisfaction of Buyer, and in any event, the value of any losses with respect to such breach shall not exceed the Allocated Value of the affected Asset. Disputes regarding the existence of a breach of the special warranties of title contained in the Conveyance Documents or the cure thereof shall be resolved in accordance with Section 10.2(g) of this Agreement.

(c)Beneficial Ownership by CLLR. Buyer acknowledges that as of the Execution Date and the Closing Date, Carrizo holds record title as to certain of the Properties for the benefit of CLLR with CLLR owning all of the beneficial interest in such Properties. At the Closing, CLLR shall cause Carrizo to convey to Buyer record title to those Properties as to which Carrizo holds record title on behalf of Seller.

Section 10.2Notice of Title Defects; Defect Adjustments.

(a)Title Defect Notices. Reasonably promptly following discovery and in any event no later than 45 days after the Execution Date (the “Title ClaimDate”), Buyer must deliver claim notices to Seller meeting the requirements of this Section 10.2(a) (collectively the “Title Defect Notices” and individually a “Title Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect pursuant to this Article X. For all purposes of this Agreement and notwithstanding anything herein to the contrary, but subject in all cases to Buyer’s rights pursuant to the special warranty of title in the Conveyance Documents, Buyer shall be deemed to have waived, and Seller shall have no liability for, any Title Defect which Buyer fails to assert as a Title Defect by a Title Defect Notice received by Seller on or before the Title Claim Date. To be effective, each Title Defect Notice shall be in writing, and shall include (i) a description of the alleged Title Defects, (ii) the Wells, Undrilled Locations or Fee Interests affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property and (iv) the amount, which estimate is non-binding, by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defects. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use reasonable efforts to give Seller written notice (which shall not constitute a Title Defect Notice) of all Title Defects discovered by Buyer on a weekly basis, which

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notice may be preliminary in nature and supplemented prior to the Title Claim Date and will not prejudice in any way Buyer’s ability to assert a Title Defect.

(b)Remedies for Title Defects. Subject to the rights of the parties pursuant toSection 13.1, and subject to Seller’s right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted by Buyer, in the event that any Title Defect timely asserted by Buyer in accordance with Section 10.2(a) is not waived in writing by Buyer or cured on or before the Closing Date to Buyer’s reasonable satisfaction, the parties shall mutually agree to elect one of the following remedies:

(i)subject to the Individual Title Defect Threshold and the Title Defect Deductible, a reduction in the Purchase Price by the Title Defect Amount; or

(ii)Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure at any time prior to 175 days after the Closing Date (the “Cure Period”), to the reasonable satisfaction of Buyer, any Title Defects of which it has been advised by Buyer.

If Seller elects to cure any Title Defect pursuant to subsection (ii) of this Section 10.2(b), Buyer shall withhold from the Purchase Price the applicable Title Defect Amount. At Closing, (A) Seller shall remove from the Assignment any Asset or portions thereof subject to such Title Defect, as applicable, which Seller has elected to cure (the “Cure Assets”) and with respect to which Buyer has retained the Title Defect Amount and (B) if the applicable Title Defect is cured as provided herein or determined to have been cured as provided herein within the Cure Period, within ten (10) Business Days after the date that Seller has notified Buyer that it has effected such cure, Seller shall convey the applicable Cure Asset to Buyer and Buyer shall pay to Seller the applicable Title Defect Amount, on the same terms as the Assets conveyed at Closing. If the parties are unable to agree on whether subsection (i) or (ii) above will apply, then the parties shall be deemed to have elected option (i); provided, however, that if the Title Defect Amount is greater than 50% of the Allocated Value of such Title Defect Property, then Seller, in its sole discretion, may elect to retain the entirety of such Title Defect Property, together with all associated Assets.

(c)Exclusive Remedy. Except for Seller’s special warranty of title under the Conveyance Documents, Section 10.2(b), shall be the exclusive right and remedy of Buyer with respect to Seller’s failure to have Defensible Title or any other title matter with respect to any Well, Undrilled Location, Fee Interest or Lease.

(d)Title Defect Amount. The “Title Defect Amount” resulting from a Title Defect that is not waived in writing by Buyer shall be the amount by which the Allocated Value of the affected Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i)if Buyer and Seller agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

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(ii)if the Title Defect is an Encumbrance (other than a Permitted Encumbrance) that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii)if the Title Defect represents a discrepancy between (i) the actual Net Revenue Interest for any Title Defect Property and (ii) the Net Revenue Interest as stated on Schedule 3.8, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property and a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest stated in Schedule 3.8 (provided, however, that an adjustment shall be made for any proportionate decrease in Working Interest);

(iv)if the Title Defect represents an obligation or Encumbrance (other than a Permitted Encumbrance) upon or other defect in title to the Title Defect Property of a type not described above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the likelihood that the Title Defect will be asserted, the values placed upon the Title Defect by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation;

(v)the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(vi)notwithstanding anything to the contrary in this Agreement, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(e)Title Deductibles. Notwithstanding anything to the contrary, in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for (i) any individual Title Defect for which the Title Defect Amount does not exceed $25,000 (the “Individual Title Defect Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any Title Defect for which the Title Defect Amount exceeds the Individual Title Defect Threshold unless (A) the amount of the sum of the Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold, in the aggregate, excluding any Title Defect Amounts attributable to Title Defects cured by Seller, after offsetting all Title Benefits which individually exceed the Individual Benefit Amount, exceeds (B) the Title Defect Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other remedies only with respect to such Title Defects in excess of such Title Defect Deductible; provided that the entire Title Defect Amount of Title Defects meeting the description in subclause (A) above and not just the portion in excess of the Individual Title Defect Threshold shall be counted toward determining whether the Title Defect Deductible has been met. If Seller

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retains any Title Defect Property pursuant to the last sentence of Section 10.2(b), the Purchase Price shall be reduced by the Allocated Value of such Title Defect Property and the Title Defect Amount relating to such Title Defect Property will not be counted towards the Title Defect Deductible; provided, however, that the Title Defect Deductible will be recalculated based on the Purchase Price after it is reduced by the Allocated Value of such Title Defect Property.

(f)Title Benefits. Seller may notify Buyer in writing of the existence of a Title Benefit and the associated Title Benefit Amount if Seller discovers a Title Benefit (such notice by Seller, a “Title Benefit Notice”). A Title Benefit Notice must be delivered by the Title Claim Date. Each Title Benefit Amount in excess of the Individual Title Benefit Threshold shall be an upward adjustment to the Purchase Price. To be effective, each Title Benefit Notice shall be in writing, and shall include (i) a description of the alleged Title Benefits, (ii) the Assets affected by the Title Benefit (each a “Title Benefit Property”), (iii) the Allocated Value of each Title Benefit Property and (iv) the amount, which estimate is non-binding, by which Buyer reasonably believes the Allocated Value of each Title Benefit Property is increased by the alleged Title Benefits.

(g)Title Dispute Resolution. Seller and Buyer shall attempt to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to the end of the Cure Period. If Seller and Buyer are unable to agree by the end of the Cure Period, the Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved pursuant to this Section 10.2(g). There shall be a single arbitrator, who shall be a title attorney with at least ten years experience in oil and gas titles involving properties in Texas, as selected by mutual agreement of Buyer and Seller within 15 days after the end of the Cure Period, and absent such agreement, by the Houston office of the American Arbitration Association (the “Title Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 10.2. The Title Arbitrator’s determination shall be made within 20 days after submission of the matters in dispute and shall be final and binding upon both parties without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set forth in this Article X and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrator are necessary to make a proper determination. The Title Arbitrator, however, may not award Buyer or Seller a greater Title Defect Amount or Title Benefit Amount, as applicable, than the Title Defect Amount or Title Benefit Amount claimed by Buyer or Seller in its applicable Title Defect Notice or Title Benefit Notice, and notwithstanding anything herein to the contrary, the Title Arbitrator’s awards are subject to the limitation on liabilities provisions set forth in Section 10.2(e). The Title Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Title Arbitrator. To the extent that the award of the Title Arbitrator with respect to any Title Defect Amount or Title Benefit Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.4 or Section 3.5, then within ten days after the Title Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Title Defect Amount or Title Benefit Amount, Seller shall pay to Buyer or Buyer shall pay to Seller, as applicable, the

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amount, if any, so awarded by the Title Arbitrator to Buyer or Seller. Subject to the parties’ rights pursuant to Section 13.1, the Closing shall not be delayed on account of any arbitration hereunder and to the extent any adjustments are not agreed upon by the parties as of the Closing, the Purchase Price shall not be adjusted therefor as of the Closing and subsequent adjustments thereto, if any, will be made pursuant to Section 3.5 or this Section 10.2.

Section 10.3Casualty or Condemnation Loss.

(a)Seller shall promptly notify Buyer of any material casualty to the Assets or any portion thereof that occurs, or any condemnation proceeding commenced, after the Execution Date and prior to the Closing Date.

(b)If, after the Execution Date and before the Closing, Casualty Losses occur with respect to the Assets that result in losses of less than five percent (5%) of the Purchase Price in the aggregate, then, notwithstanding such Casualty Loss, Buyer and Seller shall proceed with the purchase and sale of the affected Assets without reduction of the Purchase Price, and Seller, at Seller’s sole discretion, shall select one of the following options which shall apply to the Casualty Losses: (i) Seller shall cause the Assets affected by such Casualty Losses to be repaired or restored to at least their condition prior to such Casualty Losses, at Seller’s sole cost, as promptly as reasonably practicable (which work may extend after the Closing Date) or (ii) Seller shall, at Closing, pay to Buyer all sums paid to Seller or its Affiliates by Third Parties by reason of such Casualty Losses and shall assign to Buyer all of Seller’s or its Affiliates’ right, title and interest (if any) in insurance claims, unpaid awards and other rights against Third Parties arising out of the casualty.

(c)If, after the Execution Date and before the Closing, Casualty Losses occur with respect to the Assets that result in losses equal to or in excess of five percent (5%) of the Purchase Price in the aggregate, then at the Closing, Seller and Buyer shall mutually agree to either (i) have Seller cause the Assets adversely affected by such Casualty Losses to be repaired or restored to at least their condition prior to such Casualty Losses, at Seller’s sole cost and expense, as promptly as reasonably practicable (which work may extend after the Closing Date), (ii) to have Seller indemnify the Buyer against any costs or expenses that Buyer reasonably incurs to repair or restore the Assets subject to any such Casualty Losses or (iii) to the extent such Assets are not material to the operation or value of the other Assets, exclude such Assets (and any Assets solely related to such Assets) from this Agreement and adjust the Purchase Price by the Allocated Value of such excluded Assets.

(d)If after the date of this Agreement but prior to the Closing Date, any portion of the Assets is taken in condemnation or under right of eminent domain by any Governmental Authority, the Assets or portion thereof shall be excluded from the Assets to be conveyed to Buyer at Closing to the extent of the interest affected by the condemnation or right of eminent domain and the Purchase Price will be reduced by the Allocated Value of such interest.

(e)If any action for condemnation or taking under right of eminent domain is pending or threatened with respect to any Asset or portion thereof after the Execution Date, but no taking of such Asset or portion thereof occurs prior to the Closing Date, the transaction contemplated by this Agreement shall nevertheless close and Seller, at Closing, shall assign, transfer and set over

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to Buyer or subrogate Buyer to all of Seller’s or its Affiliates’ right, title and interest (if any) in such taking, including any insurance claims, unpaid awards and other rights against Third Parties arising out of the taking, insofar as they are attributable to the Assets threatened to be taken.

(f)Notwithstanding anything herein to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion or otherwise (including watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of Personal Property due to ordinary wear and tear, in each case, with respect to the Assets.

Section 10.4Preferential Rights to Purchase and Consents to Assign.

(a)With respect to each Preferential Right to Purchase pertaining to an Asset and the transactions contemplated hereby, Seller, promptly following the date hereof, and, in any event, prior to the Closing, shall send to the holder of each such right a notice, in compliance with the contractual provisions applicable to such right. In addition, promptly following the date hereof, and, in any event, prior to the Closing, Seller shall send to each holder of a right to consent to assignment (excepting the holder of a right to a Customary Post-Closing Consent) pertaining to the Assets and the transactions contemplated hereby a notice seeking such party’s consent to the transaction contemplated hereby.

(b)If, prior to the Closing, any holder of a Preferential Right to Purchase notifies Seller or an Affiliate of Seller that it intends to consummate the purchase of the Asset to which its Preferential Right to Purchase applies, that Asset shall be excluded from the Assets to be conveyed to Buyer to the extent of the interest affected by the Preferential Right to Purchase, and the Purchase Price shall be reduced by the Allocated Value of the relevant Asset (or portion thereof) allocable to such interest. Seller shall be entitled to all proceeds paid by a party exercising a Preferential Right to Purchase prior to the Closing. If such holder of such Preferential Right to Purchase thereafter fails to consummate the purchase of the Asset covered by such right on or before 60 days following the later of the Closing Date or the expiration of the time for exercising such Preferential Right to Purchase, then Seller shall so notify Buyer, and Buyer shall purchase, on or before ten days following receipt of such notice, such Asset from Seller, under the terms of this Agreement for a price equal to the Allocated Value (or portion thereof) previously allocated to it.

(c)If a Preferential Right to Purchase burdening any Asset is not exercised, or the time for exercising such Preferential Right to Purchase has not expired prior to the Closing Date, then such Asset shall be excluded from the Assets to be conveyed at Closing and the Purchase Price shall be reduced by the Allocated Value of the relevant Asset. If the holder of such Preferential Right to Purchase thereafter fails to exercise or consummate the purchase of the Asset covered by such right on or before 60 days following the later of the Closing Date or the time for exercising such Preferential Right to Purchase expires without being exercised, then Seller shall so notify Buyer, and Buyer shall purchase, on or before ten days following receipt of such notice, such Asset from Seller, under the terms of this Agreement for a price equal to the Allocated Value (or portion thereof) previously allocated to it.

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(d)All Assets for which Preferential Rights to Purchase have been waived, or as to which the period to exercise such right has expired prior to the Closing, shall be sold to Buyer at the Closing pursuant to the provisions of this Agreement.

(e)Promptly following the date hereof, and, in any event, prior to the Closing, Seller shall use its commercially reasonable efforts to obtain all consents listed on Schedule 4.4(a) and Schedule 4.4(b) that are required to permit the assignment of the Assets by Seller to Buyer and the consummation by Seller of the transactions contemplated hereby; provided, however, neither party shall be required to incur any Liability or pay any money in order to be in compliance with the foregoing covenant.

(f)If Seller fails to obtain a consent (other than a Customary Post-Closing Consent), which required consents are set forth on Schedule 4.4(a), prior to the Closing, then the Asset (or portion thereof) subject to such failed consent shall be excluded from the Assets to be conveyed to Buyer (subject, however, to Section 6.8), and the Purchase Price shall be reduced by the Allocated Value of the excluded Asset (or portion thereof). For a period of 175 days following Closing, Seller and Buyer shall use their commercially reasonable efforts to attempt to obtain any such consent. If such consent is obtained within such period, then Seller shall convey to Buyer the Asset (or portion thereof) which was excluded from the Assets, and Buyer shall pay to Seller the Allocated Value of the excluded Asset (or portion thereof).

ARTICLE XIENVIRONMENTAL MATTERS

Section 11.1Environmental Conditions.

(a)Assertions of Environmental Conditions. Buyer must deliver claim notices to Seller meeting the requirements of this Section 11.1(a) (collectively the “Environmental Condition Notices” and individually an “Environmental Condition Notice”) reasonably promptly following discovery and, in any event, no later than the Environmental Claim Date, setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Conditions and which Buyer intends to assert as Environmental Conditions pursuant to this Section 11.1. For all purposes of this Agreement but subject to Buyer’s remedy for a breach of Seller’s representation contained in Section 4.16 and Seller’s indemnity obligation in Section 12.2, Buyer shall be deemed to have waived any Environmental Condition which Buyer fails to assert as an Environmental Condition by an Environmental Condition Notice received by Seller on or before the Environmental Claim Date. To be effective, each Environmental Condition Notice shall be in writing and shall include (i) a reasonably detailed description, including, where available, supporting documentation, of the matter constituting the alleged Environmental Condition, (ii) a description of each Asset (or portion thereof) that is affected by the alleged Environmental Condition, (iii) Buyer’s assertion of the Allocated Value of the portion of the Assets affected by the alleged Environmental Condition, and (iv) an estimate, which is non-binding, of the Remediation Amount that Buyer asserts is attributable to such alleged Environmental Condition. Buyer’s calculation of the Remediation Amount included in the Environmental Condition Notice should describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Condition

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and the primary assumptions used in calculating the Remediation Amount, including, any standards that Buyer asserts must be met to comply with Environmental Laws.

(b)Remedies for Environmental Conditions. Subject to the parties’ rights pursuant to Section 13.1, in the event that any Environmental Condition timely asserted by Buyer in accordance with Section 11.1(a) is not waived in writing by Buyer or Remediated on or before the last day of the Environmental Condition Cure Period, then the parties shall mutually agree to elect one of the following remedies:

(i)subject to the Individual Environmental Threshold and the Environmental Condition Deductible, a reduction of the Purchase Price by the Remediation Amount agreed upon by Seller and Buyer or determined in accordance with Section 11.1(g) and assumption by Buyer of responsibility for Remediation of the Environmental Condition;

(ii)Seller may elect to Remediate any claimed Environmental Condition, to the reasonable satisfaction of Buyer, on or before 175 days after the Closing Date (the “Environmental Condition Cure Period”). Seller may select and employ, with Buyer’s consent, which consent may not be unreasonably withheld, any generally accepted remedial technology or approach to Remediate an identified Environmental Condition.

(iii)retention by Seller of the entirety of the Asset that is subject to such Environmental Condition, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset and such associated Assets.

If Seller elects to Remediate any claimed Environmental Condition pursuant to clause (ii) of this Section 11.1(b), Buyer shall withhold from the Purchase Price the applicable Allocated Value for such Asset affected by the Environmental Condition. At Closing, (i) Seller shall remove from the Assignment any Asset or portions thereof subject to such Environmental Condition, as applicable, which Seller has elected to cure (the “Environmental Remediation Assets”) and with respect to which Buyer has retained the related Allocated Value and (ii) if the applicable Environmental Condition is remediated as provided herein or determined to have been remediated as provided herein within the Environmental Condition Cure Period, within ten (10) Business Days after the date that Seller has notified Buyer that it has effected such Remediation, Seller shall convey the applicable Environmental Remediation Asset to Buyer and Buyer shall pay to Seller the applicable Allocated Value, on the same terms as the Assets conveyed at Closing. In the event the parties cannot agree to either Section 11.1(b)(i), (ii) or (iii), then Section 11.1(b)(ii) shall be the remedy for an Environmental Condition unless the Allocated Value of such Asset is equal to or less than the Remediation Amount asserted by Buyer, in which event Section 11.1(b)(iii) shall be the remedy for an Environmental Condition.

(c)If clause (i) above is applicable or the default remedy, Buyer shall be deemed to have assumed responsibility for Remediation of such Environmental Condition and such Environmental Condition and all Liabilities with respect thereto shall be deemed to constitute

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Assumed Obligations. If clause (ii) above is applicable, then Seller shall use commercially reasonable efforts to implement such Remediation in a manner which is consistent with the requirements of Environmental Laws, taking into consideration Buyer’s use and operation of the Assets, in a timely fashion for the type of Remediation Seller elects to undertake and, upon advance written notice, Buyer hereby grants Seller access to the affected Assets after the Closing Date to implement and complete such Remediation in accordance with an access agreement mutually agreeable to the parties. Upon completion of Remediation under clause (ii) above, Seller shall at its sole cost and expense and without any cost or expense to Buyer or its Affiliates, (1) close all bore holes from its Remediation in accordance with recognized industry standards, (2) repair all damage done to the Assets in connection with the Remediation, and (3) remove all equipment, tools or other property brought onto the Assets in connection with the Remediation. Under either clause (i) or clause (ii) above, the party performing Remediation shall keep the other party reasonably informed regarding any Remediation. In completing the Remediation, the party performing the Remediation shall provide the other party with draft copies of all documents to be submitted to any Governmental Authorities regarding the Remediation and shall reasonably cooperate with the other party to incorporate comments provided by it to the party performing the Remediation regarding such documents. In addition, the party performing the Remediation shall promptly provide the other party with copies of any correspondence with any Governmental Authority regarding the Remediation and shall provide the other party with the opportunity to participate in any meetings with any Governmental Authority regarding the Remediation. The party performing the Remediation shall be solely responsible for obtaining any permits or other authorizations from any Governmental Authority associated with the Remediation. The party performing the Remediation shall promptly remove any waste material generated during the Remediation from the Assets. The party performing the Remediation shall require any contractors or subcontractors entering the Assets in connection with the Remediation to provide the other party with certificates of insurance demonstrating coverage under Commercial General Liability, Contractors Pollution Liability, and Errors and Omissions Liability insurance policies in a form reasonably acceptable to the other party and naming the other party as an additional insured.

(d)With respect to any provision of this Article XI that refers to any Remediation completed by Seller, whether before or after the Closing, Seller will be deemed to have adequately completed the Remediation (A) upon receipt of a certificate of approval or completion or its equivalent from the applicable Governmental Authority that the Remediation has been implemented to the extent necessary to comply with existing Laws or (B) if no certificate or approval is available under Environmental Law or upon express written consent of Buyer, upon mutual agreement of the parties, upon receipt of a certificate from an independent, licensed professional engineer that the Remediation has been implemented to the extent necessary to comply with Environmental Laws; provided, if the parties cannot agree, the issue of whether the Remediation is completed may be resolved by the dispute resolution procedures set forth in Section 11.1(g).

(e)Exclusive Remedy. Except for Buyer’s remedy for a breach of Seller’s representation contained in Section 4.16, Seller’s indemnification obligation in Section 12.2, and Buyer’s rights to terminate this Agreement pursuant to Section 13.1, the provisions set forth in Section 11.1(b) shall be the exclusive right and remedy of Buyer with respect to any Environmental Condition or other environmental matter with respect to any Asset. The parties acknowledge and

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agree that information identified or discovered by Buyer prior to the Environmental Claim Date or information identified, discovered or developed in connection with the Remediation of a noticed Environmental Condition shall not form the basis for a claim for a breach of representation or warranty pursuant to Section 4.16.

(f)Environmental Deductibles. Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any individual Environmental Condition for which the Remediation Amount does not exceed $50,000 (“Individual Environmental Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any Environmental Condition for which the Remediation Amount exceeds the Individual Environmental Threshold unless the sum of the Remediation Amounts of all such Environmental Conditions that exceed the Individual Environmental Threshold, in the aggregate, excluding any Environmental Conditions Remediated by Seller, exceeds the Environmental Condition Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other remedies only with respect to the portion of the Remediation Amounts in excess of such Environmental Condition Deductible; provided that the entire Remediation Amount and not just the portion in excess of the Individual Environmental Threshold shall be counted toward determining whether the Environmental Condition Deductible has been met.

(g)Environmental Dispute Resolution. Seller and Buyer shall attempt to agree on all Environmental Conditions and Remediation Amounts prior to the end of the Environmental Condition Cure Period. If Seller and Buyer are unable to agree by the end of the Environmental Condition Cure Period, the Environmental Conditions and/or Remediation Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 11.1(g). There shall be a single arbitrator, who shall be an environmental attorney or environmental expert with at least ten years experience in environmental matters involving oil and gas producing properties in Texas, as selected by mutual agreement of Buyer and Seller within 15 days after the Closing Date, and absent such agreement within such time period, then each party will nominate a candidate to select the Environmental Arbitrator, and such candidates so nominated by Buyer and Seller shall together determine the Environmental Arbitrator within 15 days after the last candidate is nominated and absent such determination within such time period, the Environmental Arbitrator shall be selected by the Houston office of the American Arbitration Association (the “Environmental Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Article. The Environmental Arbitrator’s determination shall be made within 20 days after submission of the matters in dispute and shall be final and binding upon both parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 11.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination. The Environmental Arbitrator, however, may not award Buyer a greater Remediation Amount than the Remediation Amount claimed by Buyer in its applicable Environmental Condition Notice or a lesser Remediation Amount than the Remediation Amount claimed by Seller and notwithstanding anything herein to the contrary, the Environmental Arbitrator’s awards are subject to the limitations on liability set forth in Section 11.1(f). The

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Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Environmental Conditions and/or Remediation Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.4 or Section 3.5, then within ten days after the Environmental Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Remediation Amount, (i) Buyer shall pay to Seller the amount, if any, so awarded by the Environmental Arbitrator to Seller, if any, and (ii) Seller shall pay to Buyer the amount, if any, so awarded by the Environmental Arbitrator to Buyer. Subject to the parties’ rights pursuant to Section 13.1, nothing herein shall operate to cause the Closing to be delayed on account of any arbitration hereunder and to the extent any adjustments are not agreed upon by Seller and Buyer as of the Closing, the Purchase Price shall not be adjusted therefor as of the Closing and subsequent adjustments thereto, if any, will be made pursuant to Section 3.5 or this Section 11.1.

Section 11.2 NORM, Wastes and Other Substances. Buyer acknowledges that the Assets have been used for exploration, development and production of oil and gas and that there may be Hydrocarbons, produced water, wastes, Hazardous Substances or other substances or materials located in, on or under the Assets or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, NORM or other Hazardous Substances. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms. The wells, materials and equipment located on the Assets or included in the Assets may contain NORM and other wastes or Hazardous Substances. NORM containing material and/or other wastes or Hazardous Substances may have come in contact with various environmental media, including water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation or disposal of environmental media, wastes, asbestos, NORM and other Hazardous Substances from the Assets.

ARTICLE XIIASSUMPTION; SURVIVAL; INDEMNIFICATION

Section 12.1Assumption by Buyer and Retention by Seller.

(a)Except as otherwise provided herein (including in Section 14.1(b)) and subject to Buyer’s rights to indemnity under Section 12.2 and the Retained Obligations under Section 12.1(b), from and after the Closing, Buyer assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all obligations and Liabilities, known or unknown, with respect to the Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including obligations and Liabilities relating in any manner to the ownership, operation or use of the Assets, including obligations (a) to furnish makeup gas and/or settle Imbalances according to the terms of applicable gas sales, processing, gathering or transportation Contracts, (b) to pay Working Interests, Royalties and owners’ revenues or proceeds attributable to the sale of Hydrocarbons produced from or attributable to the Assets after the Effective Time (including any such payments held in suspense that are transferred to Buyer pursuant to Section

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2.1(n)), (c) to properly plug, re-plug and abandon any and all Wells, wells, wellbores, or previously plugged Wells on the Properties to the extent required or necessary, (d) to dismantle or decommission and remove any Personal Property and other property of whatever kind related to or associated with operations and activities conducted on the Properties or Assets, (e) to clean up, restore and/or remediate the premises covered by or related to the Assets in accordance with applicable agreements and Laws, including Environmental Laws, (f) to perform all obligations applicable to or imposed on the lessee, owner or operator from and after the Effective Time under the Leases and the Applicable Contracts or as required by agreements and Laws, (g) to pay for actual or claimed property damage, personal injury or death relating to the Assets and (h) to dispose of or transport of any Hazardous Substances (all of said obligations and Liabilities herein being referred to as the “Assumed Obligations”).

(b)Subject to Seller’s right to indemnity under Section 12.3 and the limitations set forth in Section 12.4, from and after the Closing, Seller retains and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all obligations and Liabilities, known or unknown, with respect to the Assets, for such obligations or Liabilities that arose prior to the Effective Time to the extent involving or relating to (i) the ownership, use or operation of the Excluded Assets, (ii) the transport or disposal prior to the Closing Date of any Hazardous Substances from the Assets operated by Seller to any location not on the Assets prior to the Closing Date; (iii) any Working Interests, Royalties or other owners’ revenues or proceeds payable by Seller on or attributable to the sale of Hydrocarbons to the extent produced from or attributable to the Assets prior to the Effective Time; (iv) any Tax Liability of Seller or its Affiliates for which Seller is ultimately responsible under Section 14.1(b), but excluding Transfer Taxes and that portion of any Production Taxes for which Buyer is ultimately responsible under Section 14.1(b) hereunder; (v) any Liability or obligation for compensation or reimbursement to any of Seller’s current or former employees for work performed, including any Liabilities or obligations to the extent related to or arising under any employee benefit plan, express or implied contract, wages, bonuses, commissions or severance benefits prior to Closing; (vi) any fines, penalties and sanctions asserted, imposed or levied by any Governmental Authority resulting from any criminal investigation or proceedings to the extent arising out of or related to Seller’s ownership, use, maintenance or operation of the Assets; or (vii) any death, physical injury or illness to any employees of Seller to the extent related to or arising out of Seller’s ownership or operation of the Assets (collectively, the “Retained Obligations”).

Section 12.2Indemnities of Seller. Effective as of the Closing, subject to the limitations set forth in Section 12.4 and otherwise in this Article XII, Seller shall be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Buyer and its Affiliates, and all of their respective stockholders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Buyer Indemnified Parties”) from and against any and all Liabilities arising from, based upon, related to or associated with:

(a)any breach by Seller of its representations or warranties contained in Article IV as of the Execution Date and as of the Closing, as though made at and as of the Closing;

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(b)any breach by Seller of its covenants and agreements under this Agreement; and

(c)any of the Retained Obligations.

Section 12.3Indemnities of Buyer. Effective as of the Closing, Buyer shall be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Seller and its Affiliates, and all of their respective owners, stockholders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Liabilities arising from, based upon, related to or associated with:

(a)any breach by Buyer of its representations or warranties contained inArticle V, as of the Execution Date and as of the Closing, as though made at and as of the Closing;

(b)any breach by Buyer of its covenants and agreements under this Agreement;

(c)Buyer’s obligations pursuant to Section 6.8; and

(d)the Assumed Obligations.

Section 12.4Limitation on Liability.

(a)Seller shall not have any liability for any indemnification under Section 12.2(a) (except for breaches of Fundamental Representations made by Seller and for the Retained Obligations in Sections 12.1(b)(i)-(iv) and 12.1(b)(vii)) until and unless the aggregate amount of all Liabilities for which Claim Notices are delivered by Buyer exceeds the Post-Closing Deductible.

(b)Seller shall not have any liability for any indemnification under Section 12.2(a) (except for breaches of Fundamental Representations made by Seller and for the Retained Obligations in Sections 12.1(b)(i)-(iv) and 12.1(b)(vii)), in the aggregate, in excess of 25% of the Final Price.

Section 12.5Express Negligence. THE INDEMNIFICATION, RELEASE, ASSUMED OBLIGATIONS AND RETAINED OBLIGATIONS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE GROSS, SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY, EXCEPT FOR THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

Section 12.6Exclusive Remedy. THE SOLE AND EXCLUSIVE REMEDY OF ANY PARTY TO THIS AGREEMENT AND ITS AFFILIATES WITH RESPECT TO THIS AGREEMENT, THE ASSETS, THE EVENTS GIVING RISE TO THIS AGREEMENT AND THE

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TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT SHALL BE LIMITED TO THE INDEMNIFICATION PROVISIONS AND REMEDIES SET FORTH IN SECTION 6.8 AND ARTICLES X, XI AND XII (WITH RESPECT TO THE MATTERS ADDRESSED THEREIN), AND, IN FURTHERANCE OF THE FOREGOING, EACH OF THE PARTIES, ON BEHALF OF ITSELF AND OF ITS AFFILIATES, HEREBY WAIVES, RELEASES AND DISCHARGES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE OTHER PARTIES TO THIS AGREEMENT AND THEIR RESPECTIVE AFFILIATES FROM ANY AND ALL LIABILITIES OF ANY KIND (WHETHER AT LAW OR IN EQUITY OR OTHERWISE, FORESEEN OR UNFORESEEN, MATURED OR UNMATURED, KNOWN OR UNKNOWN, ACCRUED OR NOT ACCRUED OR BASED ON ANY LAW OR RIGHT OF ACTION OR OTHERWISE) EXCEPT AS PROVIDED IN THIS AGREEMENT NOTWITHSTANDING THE STRICT LIABILITY OR NEGLIGENCE OF A RELEASED PARTY (WHETHER SOLE, JOINT OR CONCURRENT OR ACTIVE OR PASSIVE), EXCEPT FOR SUCH RELEASED PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

Section 12.7Indemnification Procedures. All claims for indemnification under Section 9.1(c), Section 12.2 and Section 12.3 shall be asserted and resolved as follows:

(a)For purposes of this Article XII, the term “Indemnifying Party”, when used in connection with particular Liabilities, shall mean the party or parties having an obligation to indemnify another party or parties with respect to such Liabilities pursuant to this Article XII, and the term “Indemnified Party”, when used in connection with particular Liabilities, shall mean the party or parties having the right to be indemnified with respect to such Liabilities by another party or parties pursuant to this Article XII.

(b)To make a claim for indemnification under Section 9.1(c), Section 12.2 or Section 12.3, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 12.7, including the specific details of, and specific basis under this Agreement for, its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Claim and shall enclose a copy of all papers (if any) served with respect to the Claim; provided that the failure of any Indemnified Party to give notice of a Claim as provided in this Section 12.7 shall not relieve the Indemnifying Party of its obligations under Section 9.1(c), Section 12.2 or Section 12.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the claim.

(c)In the case of a claim for indemnification based upon a Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 30 day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

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(d)If the Indemnifying Party admits its liability, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof subject to the remainder of this Section 12.7(d). If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Claim which the Indemnifying Party elects to contest, including by making available all records (in any form) and furnishing management and employees as may be reasonable necessary for the preparation of any defense or settlement. The Indemnified Party may participate in, but not control, any defense or settlement of any Claim controlled by the Indemnifying Party pursuant to this Section 12.7(d). An Indemnifying Party shall not, without the prior written consent of the Indemnified Party, (i) settle any Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all liability in respect of such Claim or (ii) settle any Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e)If the Indemnifying Party does not admit its liability within the 30 day period or admits its liability but fails to diligently defend or settle the Claim, then the Indemnified Party shall have the right to defend against the Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing; provided that the Indemnified Party shall not settle a Claim or consent to the entry of any judgment with respect thereto without the prior written consent of the Indemnifying Party, which consent shall not be unreasonably withheld, delayed or conditioned.

(f)In the case of a claim for indemnification not based upon a Claim, the Indemnifying Party shall have 90 days from its receipt of the Claim Notice to (i) cure, if curable, or Remediate, if applicable, the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities.

(g)The amount of any Liabilities for which any of the Indemnified Parties is entitled to indemnification under this Agreement or in connection with the transactions contemplated by this Agreement shall be reduced by (i) the value of any corresponding Tax benefit created or generated and actually realized, net of any corresponding tax costs incurred by such party covering such Liabilities or (ii) any corresponding insurance proceeds actually realized, net of any collection costs, and excluding the proceeds of any insurance underwritten by the Indemnified Parties. Each Indemnified Party agrees that it shall pursue in good faith all claims under any applicable insurance policies and against other Persons (including its Affiliates) that may be responsible for any of Seller’s Liabilities or Buyer’s Liabilities, as applicable. The Indemnified Party shall take all reasonable steps to mitigate damages in respect of any claim for which such Indemnified Party, as applicable, is seeking indemnification and shall use commercially reasonable efforts to avoid any costs or expenses associated with such claim and, if such costs and expenses cannot be avoided, to use commercially reasonable efforts to minimize the amount thereof. The Indemnifying Party shall be subrogated to the rights of the Indemnified Party in respect of any insurance relating to the Indemnifying Party’s Liability, as the case may be, to the extent of any indemnification payments made hereunder, and the Indemnified Party shall provide all reasonably requested assistance to the

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Indemnifying Party in respect of such subrogation. If an Indemnified Party directly or indirectly receives an amount under insurance coverage with respect to Buyer Liabilities or Seller Liabilities, as applicable, at any time subsequent to any indemnification provided by Seller or Buyer, as applicable, pursuant to this Section 12.7, then such Indemnified Party shall promptly reimburse the Indemnifying Party for any payment made or expense incurred by the Indemnifying Party in connection with providing such indemnification up to such amount received by the Indemnified Party.

(h)Any liability for indemnification hereunder shall be determined without duplication of recovery by reason of the state of facts giving rise to such Liability constituting a breach of more than one representation, warranty, covenant or agreement herein. The Indemnifying Party shall not be liable for indemnification with respect to any of the Indemnified Party’s Liabilities, based on any set of facts to the extent the Purchase Price is being or has been adjusted by reason of the same set of facts. The determination of the dollar amount of any Liabilities shall be based solely on the actual dollar value thereof, on a dollar-for-dollar basis, and shall not take into account any multiplier valuations, including any multiple based on earnings or other financial condition.

Section 12.8Survival.

(a)The representations and warranties of the parties in Article IV and Article V (other than (i) the Fundamental Representations and the covenants and agreements in Section 6.1) shall survive the Closing and for a period of twelve (12) months thereafter. Subject to the foregoing, the remainder of this Agreement shall survive the Closing without time limit; provided that the representations in Section 4.17 shall only survive until the date that is 60 days following expiration of the applicable statute of limitations. Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration and no claim may be brought in respect thereof after the date of such expiration; provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date. The parties intend to shorten the applicable statute of limitations as provided herein.

(b)The indemnities in this Article XII shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification, except in each case as to matters for which a Claim Notice has been delivered to the Indemnifying Party on or before such termination date.

Section 12.9Waiver of Right to Rescission. Seller and Buyer acknowledge that the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated in this Agreement. As the payment of money shall be adequate compensation, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

Section 12.10Non-Compensatory Damages. None of the Buyer Indemnified Parties nor the Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, or their respective Affiliates, any punitive, special, indirect, remote, speculative, exemplary or consequential

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damages of any kind arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such party suffers such damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending of such damages) to a Third Party, which damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder. SUBJECT TO THE PRECEDING SENTENCE, BUYER, ON BEHALF OF EACH OF THE BUYER INDEMNIFIED PARTIES, AND SELLER, ON BEHALF OF EACH OF SELLER INDEMNIFIED PARTIES, WAIVE ANY RIGHT TO RECOVER PUNITIVE, SPECIAL, INDIRECT, REMOTE, SPECULATIVE, EXEMPLARY AND CONSEQUENTIAL DAMAGES, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 12.11Disclaimer of Application of Anti-Indemnity Statutes. The parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement and/or the transactions contemplated hereby.

Section 12.12Waiver of Trade Practices Act.

(a)It is the intention of the parties that Buyer’s rights and remedies with respect to this transaction and with respect to all acts or practices of Seller, past, present or future, in connection with this transaction shall be governed by the legal principles other than the Texas Deceptive Trade Practices-Consumer Protection Act, Tex. Bus. & Com. Code Ann. § 17.41 et seq. (the “DTPA”). As such, Buyer hereby waives the applicability of the DTPA to this transaction and any and all duties, rights or remedies that might be imposed by the DTPA, whether such duties, rights and remedies are applied directly by the DTPA itself or indirectly in connection with other statutes. Buyer acknowledges, represents and warrants (i) that it is purchasing the goods and/or services covered by this Agreement for commercial or business use, (ii) that it or its controlling entity has assets of $25,000,000 or more according to its most recent financial statement prepared in accordance with generally accepted accounting principles, (iii) that it has knowledge and experience in financial and business matters that enable it to evaluate the merits and risks of a transaction such as this and (iv) that it is not in a significantly disparate bargaining position with Seller. In furtherance of the foregoing,

WAIVER OF CONSUMER RIGHTS

BUYER WAIVES ITS RIGHTS UNDER THE TEXAS DECEPTIVE TRADE PRACTICES-CONSUMER PROTECTION ACT, SECTION 17.41 ET SEQ., BUSINESS & COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS AND PROTECTIONS. AFTER CONSULTATION WITH AN ATTORNEY OF BUYER’S OWN SELECTION, BUYER VOLUNTARILY CONSENTS TO THIS WAIVER.

(b)Buyer expressly recognizes that the price for which Seller has agreed to perform its obligations under this Agreement has been predicated upon the inapplicability of the

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DTPA and this waiver of the DTPA. Buyer further recognizes that Seller, in determining to enter into this Agreement, has expressly relied on this waiver and the inapplicability of the DTPA.

ARTICLE XIIITERMINATION, DEFAULT AND REMEDIES

Section 13.1Right of Termination. This Agreement and the transactions contemplated herein may be terminated (i) at any time at or prior to Closing by mutual written agreement of the parties, (ii) by Seller if the Closing shall not have occurred on or before December 13, 2013, or (iii) by Seller or Buyer if the Closing shall not have occurred on or before February 14, 2014; provided, however, that no party shall have the right to terminate this Agreement to this Section 13.1 if such party or its Affiliates are at such time in material breach of any provision of this Agreement.

Section 13.2Effect of Termination. If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 13.1 hereof, then except for the provisions of Section 1.1, Section 9.1(e), Section 9.2, Section 12.10 and this Section 13.2 and Article XIV (other than Section 14.1(b), Section 14.5, Section 14.6 and Section 14.7), this Agreement shall forthwith become void and the parties shall have no Liability or obligation hereunder except and to the extent such termination results from the willful and material breach by a party of any of its covenants or agreements hereunder.

Section 13.3Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall promptly (a) return to Seller all Records, including all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps and other information furnished by Seller to Buyer or prepared by or on behalf of Buyer in connection with its due diligence investigation of the Assets and any documents, data, reports, assessments in paper, electronic, digital or any other form, to the extent derived from the matters described in this subclause (a) or from any confidential information obtained under the Confidentiality Agreement, and (b) destroy any copies of such data, assessments or reports. An officer of Buyer shall certify same to Seller in writing.

ARTICLE XIVMISCELLANEOUS

Section 14.1 Expenses and Taxes.

(a)Except as otherwise specifically provided, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the party incurring the same, including legal and accounting fees, costs and expenses.

(b)All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer, except Seller shall be responsible for recording fees and expenses related to the filing of any release of liens delivered by

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Seller at Closing. Buyer shall (i) file all necessary Tax returns and other documentation with respect to all sales, use, transfer and similar taxes (“Transfer Taxes”) and fees arising out of or in connection with the transactions effected pursuant to this Agreement and (ii) be liable for and either promptly reimburse Seller for, or promptly pay, any such Transfer Taxes. For the period that includes the Effective Time, Seller shall be responsible for, and shall bear and pay, all Production Taxes assessed by any Governmental Authority for any portion of such period prior to the Effective Time. Buyer shall be responsible for, and shall bear and pay, all Production Taxes assessed by any Governmental Authority for any period, or portion thereof, that begins on or after the Effective Time (including any “rollback” or similar ad valorem or property Tax resulting from a change in use of property by Buyer, regardless of the period with respect to which such rollback or similar Tax is calculated). For purposes of this Agreement, (i) production, severance, and similar taxes (including any applicable interest or penalties) shall be allocated to the period during which the relevant production occurred and (ii) ad valorem, property and similar taxes (including any applicable interest or penalties) shall be prorated at the Closing based on the ratio of the number of days in the year prior to (for Seller) and on and after (for Buyer) the Effective Time to the total number of days in the year as applied to the amount of such taxes for the most recent year for which the amount of such taxes can be finally determined at the Closing, except to the extent Seller has paid all or a portion of such taxes to the Governmental Authority for the current tax year prior to Closing. Seller shall pay to Buyer on demand Seller’s portion of all Production Taxes prorated to Seller under this Section 14.1 but paid by Buyer to the extent not taken into account under Section 3.2(b)(iii). Buyer shall pay to Seller on demand Buyer’s portion of all Production Taxes prorated to Buyer under this Section 14.1 but paid by Seller to the extent not taken into account under Section 3.2(a)(iii).

(c)If Buyer receives a refund of any Taxes that Seller is responsible for hereunder, or if Seller receive a refund of any Taxes that Buyer is responsible for hereunder, and such refund was not taken into account for purposes of determining the Final Price under Section 3.2, the party receiving such refund shall, within 30 days after receipt of such refund, remit it to the party who has responsibility for such Taxes hereunder.

Section 14.2Assignment. Except as otherwise set forth in Section 6.7, this Agreement may not be assigned by either party without prior written consent of the other. No assignment of any rights hereunder by a party shall relieve such party of any obligations and responsibilities hereunder. Notwithstanding the preceding sentence, provided the original parties constituting Buyer remain liable hereunder for full performance hereof, EnerVest Holding, L.P. shall have the right to convey all of its rights, benefits, duties and obligations in, to and arising from this Agreement on or before Closing to EV Properties, L.P., or to the other original parties constituting Buyer allocated based on each party’s current Proportionate Share in the Agreement. In the event of any such conveyance, Exhibit F shall be amended to reflect the revised Proportionate Shares. Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns.

Section 14.3Publicity. Except as otherwise set forth in this Section 14.3, Seller and Buyer shall consult with each other with regard to all press releases or other public or private announcements issued or made prior to the Closing concerning this Agreement or the transactions contemplated herein, and, except as the disclosing party may reasonably consider necessary in order

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to satisfy its or its Affiliates’ obligations under Laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Buyer nor Seller shall issue any such press release or other publicity prior to the Closing, without the prior written consent of the other party, which shall not be unreasonably withheld; provided that a party shall have no obligation under this Section 14.3 with respect to information the substance of which has previously been publicly disclosed. Subject to the preceding sentence, unless Buyer provides consent otherwise, Seller will only refer to Buyer as “Undisclosed Buyer” or words to such effect in any press releases or other public or private announcements prior to, on or after Closing concerning this Agreement or the transactions contemplated herein.

Section 14.4Notices. All notices and communications required or permitted to be given hereunder shall be in writing and shall be (a) delivered personally, (b) sent by bonded overnight courier, (c) mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid or (d) sent by email (provided any such email is confirmed by written confirmation which may be by email), in each case addressed to the appropriate party at the address for such party shown below or at such other address as such party shall have theretofore designated by written notice delivered to the party giving such notice:

If to Seller:

Carrizo Oil & Gas, Inc.
CLLR, Inc.
Hondo Pipeline, Inc.
Mescalero Pipeline, LLC
500 Dallas, Suite 2300
Houston, TX 77002
Attention: Michael KenningtonEmail: mike.kennington@crzo.net

If to Buyer:

EnerVest Energy Institutional Fund XIII-A, L.P.

EnerVest Energy Institutional Fund XIII-WIB, L.P.

EnerVest Energy Institutional Fund XIII-WIC, L.P.

EnerVest Holding, L.P.

c/o EnerVest, Ltd.

1001 Fannin Street, Suite 800

Houston, Texas 77002

Attn: Phil C. DeLozier,

Senior Vice President, Business Development

Phone: 713-495-5330

Email: pdelozier@enervest.net

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With a copy to:

EnerVest, Ltd.

1001 Fannin Street, Suite 800

Houston, Texas 77002

Attn: Philip B. Berry,

Associate General Counsel

Phone: 713-495-5315

Email: pberry@enervest.net

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier during normal business hours, or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail. The parties hereto may change the address, telephone numbers and emails to which such communications are to be addressed by giving written notice to the other parties in the manner provided in this Section 14.4.

Section 14.5Removal of Name. As promptly as practicable, but in any case within 30 days after the Closing Date, Buyer shall eliminate the name “Carrizo”, “Hondo” and “CLLR” and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

Section 14.6Further Cooperation. After the Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as any party may reasonably request to convey and deliver the Assets to Buyer, to perfect Buyer’s title thereto and to accomplish the orderly transfer of the Assets to Buyer in the manner contemplated by this Agreement. If any party hereto receives monies belonging to the other, such amount shall immediately be paid over to the proper party. If an invoice or other evidence of an obligation is received by a party, which is partially an obligation of both Seller and Buyer, then the parties shall consult with each other, and each shall promptly pay its portion of such obligation to the obligee. At Seller’s sole cost and expense, Buyer agrees to use commercially reasonable efforts to cooperate with Seller in connection with Seller’s defense and other actions relating to or arising out of the litigation and claims that are Retained Obligations, including upon reasonable request by making its and its Affiliates’ employees engaged in the operation of the Assets available during normal business hours and upon reasonable notice for the purposes of providing testimony, depositions, information and other related activities relating to such litigation and claims. At Buyer’s sole cost and expense, Seller agrees to use commercially reasonable efforts to cooperate with Buyer in connection with Buyer’s defense and other actions relating to or arising out of any litigation and claims that are Assumed Obligations, including upon reasonable request by making its and its Affiliates’ employees that were engaged in the operation of the Assets prior to Closing available during normal business hours and upon reasonable notice for the purposes of providing testimony, depositions, information and other related activities relating to such litigation and claims.

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Section 14.7Filings and Certain Governmental Approvals. Promptly after Closing Buyer shall (a) record the Assignments of the Assets executed at the Closing in all applicable real property records and (b) actively pursue the approval of all applicable Governmental Authorities of the assignment of the Assets to Buyer and the designation of Buyer as the operator thereof, as applicable. Buyer shall be solely responsible for all filing fees associated therewith.

Section 14.8Entire Agreement. This Agreement, the exhibits and schedules hereto, the Assignments, Assignment and Assumption, the Deed, the Transaction Documents, and, only until Closing, the Confidentiality Agreement, collectively constitute the entire Agreement among Seller and Buyer pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties pertaining to the subject matter hereof.

Section 14.9Parties in Interest. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of Seller and Buyer and their respective legal representatives, successors and assigns. No other person shall have any right, benefit, priority, or interest hereunder or as a result hereof or have standing to require satisfaction of the provisions hereof in accordance with their terms.

Section 14.10Amendment. This Agreement may be amended only by an instrument in writing executed by the parties hereto against whom enforcement is sought.

Section 14.11Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the party hereto waiving compliance. No course of dealing on the part of Seller or Buyer, or their respective officers, employees, agents or representatives, nor any failure by Seller or Buyer to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such party at a later time to enforce the performance of such provision. No waiver by any party of any condition, or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of Seller and Buyer under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

Section 14.12Governing Law; Dispute Resolution.

(a)This Agreement and the legal relations among the parties shall be governed and construed in accordance with the laws of the State of Texas, excluding any conflicts of law rule or principle that might refer construction of such provisions to the laws of another jurisdiction.

(b)Any controversy, dispute or claim arising out of or relating to this Agreement or the Transaction Documents, or the transactions contemplated thereby (a “Dispute”) shall be resolved in accordance with this Section 14.12. Any party may give the other party written notice (a “Dispute Notice”) of any Dispute which has not been resolved in the normal course of business. Within 15 Business Days after delivery of the Dispute Notice, the receiving party shall submit to

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the other party a written response (the “Response”). The Dispute Notice and the Response shall each include (i) a statement setting forth the position of the party giving such notice, a summary of the arguments supporting such position and, if applicable, the relief sought and (ii) the name and title of a senior manager of such party who has authority to settle the Dispute and will be responsible for the negotiations related to the settlement of the Dispute (the “Senior Manager”).

(c)Within 10 days after the delivery of the Response provided for in Section 14.12(b), the Senior Managers of both parties shall meet or communicate by telephone at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary, and shall negotiate in good faith to attempt to resolve the Dispute that is the subject of such Dispute Notice. It is agreed between the parties that the content of any communications pursuant to this Section 14.12(c) will be and shall remain confidential. The parties, on behalf of themselves and their attorneys, hereby agree that they will not in any way reveal the content or terms of any such communications to any person, firm, corporation, or entity, with the exception that the disclosure shall not be a violation of this paragraph where the same is required by Law or court order, or any agency or authority having jurisdiction to require disclosure; provided further, however, that the parties may disclose the content or terms of such communications to their attorneys, accountants, trustees, financial advisors and/or their tax related consultants, as may be necessary in their business affairs. If such Dispute has not been resolved within 30 days after delivery of the Dispute Notice, then the parties may proceed to arbitration pursuant to Section 14.12(d).

(d)Except as specifically otherwise provided in this Agreement, the parties agree that any and all Disputes arising from or related to this Agreement that cannot be amicably settled pursuant to Section 14.12(c), shall be determined solely and exclusively by arbitration in accordance with the Federal Arbitration Act and using the rules of the American Arbitration Association or any successor thereof when not in conflict with such act. Arbitration shall take place at an appointed time and place in Houston, Texas. Each party shall select one impartial arbitrator, and the two so designated shall select a third impartial arbitrator. If either party shall fail to designate an arbitrator within 14 days after arbitration is requested, or if the two arbitrators shall fail to select a third arbitrator within 30 days after arbitration is requested, then an arbitrator shall be selected by the Senior U.S. District Judge for the Southern District of Texas. Discovery shall be made pursuant to the Federal Rules of Civil Procedure and completed within 45 days of selection of the third arbitrator. Final hearing on the matter shall be had within 60 days of the selection of the third arbitrator and a final decision (which may include the award of reasonable attorney’s fees and costs) with a written opinion stating the reasons therefor shall be rendered within 75 days of said date, and be final and binding, and the parties also waive irrevocably their right to any form of appeal, review or recourse to any state court or other judicial authority, insofar as such waiver may be validly made. Judgment upon an award of the majority of the arbitrators shall be binding. Judgment on the award may be entered and enforced by any court of competent jurisdiction. In no event, may the arbitrators award damages that have been waived by the parties under Section 12.10. The arbitration process shall be kept confidential and such conduct, statements, promises, offers, views and opinions shall not be discoverable or admissible in any legal proceeding for any purpose, except to the extent reasonably necessary to enforce the final decision of the arbitrators.

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Section 14.13Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any party. Upon the determination that any term or provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 14.14Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a party by facsimile or electronic transmission shall be deemed an original signature hereto.

Section 14.15Employees. Seller will provide Buyer with the opportunity to interview certain of its employees whom are available for Buyer to hire and are separately identified by Seller to Buyer in writing.

Section 14.16Hedging Contracts. To the extent that doing so would not cause Seller to be in violation of any provision of any credit agreement (or other loan or similar document) to which it is a party or otherwise cause Seller to be in breach of any representation and warranty contained in this Agreement, Seller shall use its commercially reasonable efforts to enter into, in consultation with Buyer, hedging transactions (which are capable of being transferred to, or novated in favor of, Buyer) covering that portion of production from the Assets requested by Buyer. Within two (2) Business Days of the Execution Date, Seller shall, in consultation with Buyer, obtain quotations from counterparties with whom Seller have current ISDA agreements for straight swaps for quantities of production from the future proved developed producing oil and gas reserves attributable to the Assets. Upon receipt of oral instruction from the Buyer directing Seller which swaps to enter into and with which counterparty, subject to the indemnities set forth herein, Seller shall use its commercially reasonable efforts to execute, for the benefit and liability of Buyer, such transactions with the counterparty providing the terms acceptable to the Buyer as set forth in such instruction (the “Hedging Transactions”). Immediately thereafter, Buyer shall provide written confirmation to Seller confirming Buyer’s oral instructions. At Closing, all such Hedging Transactions shall be transferred to, or novated in favor of, Buyer. Whether or not the Closing occurs, Buyer shall pay, be responsible for, release, defend, indemnify and hold Seller harmless from and against any and all (i) costs and expenses of entering into the Hedging Transactions, (ii) costs and expenses related to transferring to, or novating in favor of, Buyer and (iii) costs, expenses and other liabilities arising from or attributable to the Hedging Transactions. In the event that this Agreement is terminated prior to Closing, Seller may, at is sole election, unwind any or all of the Hedging Transactions; but in any event, Buyer shall release, defend, indemnify and hold Seller harmless from and against any and all losses, costs, expenses or other liabilities arising from or related to the Hedging Transactions, and shall make any required payments to Seller within ten (10) Business Days after receipt of an invoice with respect thereto.

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Section 14.17Office Lease. Seller agrees to lease to Buyer for a one (1) year term, its field office located at 613 S. 4^th Street. Such lease, substantially in the form attached to this Agreement as Exhibit G, will include an option to purchase the field office and related land, at a price mutually agreed to by Buyer and Seller, which must be exercised within the first six (6) months of the lease. Buyer agrees that, if Buyer determines it no longer needs the field office, Buyer will notify Seller as soon as reasonably practicable. In such event, if the one (1) year term has not ended, Buyer and Seller will terminate the lease so that Seller may immediately market to sell the field office and related land.

[THE NEXT SUCCEEDING PAGE IS THE EXECUTION PAGE]

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IN WITNESS WHEREOF, Seller, Buyer and, for the limited purpose set forth herein, Buyer Parent have executed this Agreement on the date first above written.

SELLER:
CARRIZO OIL & GAS, INC.
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary
CLLR, INC.
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary
HONDO PIPELINE, INC.
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary
MESCALERO PIPELINE, LLC
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary

Signature Page to Purchase and Sale Agreement

BUYER:
ENERVEST ENERGY INSTITUTIONAL FUND XIII-A, L.P. ENERVEST ENERGY INSTITUTIONAL FUND XIII-WIB, L.P.
By:	EnerVest, Ltd., its Managing General Partner
By:	EnerVest Management GP, L.C., its General Partner
By:	/s/ John B. Walker
	John B. Walker
	President and Chief Executive Officer
ENERVEST ENERGY INSTITUTIONAL FUND XIII-WIC, L.P.
By:	EnerVest Holding XIII, LLC, its General Partner
By:	EnerVest Ltd., its Sole Member
By:	EnerVest Management GP, L.C., its General Partner
By:	/s/ John B. Walker
	John B. Walker
	President and Chief Executive Officer
ENERVEST HOLDING, L.P.
By:	EnerVest Operating, L.L.C., its General Partner
By:	/s/ Mark A. Houser
	Mark A. Houser
	Executive Vice President

Signature Page to Purchase and Sale Agreement

Appendix 1

Definitions

“Accounting Arbitrator” shall have the meaning set forth in Section 3.6.

“Adjusted Purchase Price” shall have the meaning set forth in Section 3.2.

“AFEs” shall have the meaning set forth in Section 4.12.

“Affiliate” shall mean any Person that, directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, another Person. The term “control” and its derivatives with respect to any Person means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall have the meaning set forth in the preamble to this Agreement.

“Allocated Value,” with respect to any Asset, shall have the meaning set forth in Section 3.8.

“Applicable Contracts” shall mean all Contracts by which the Properties and other Assets are bound or that primarily relate to the Properties or other Assets and (in each case) that will be binding on the Assets or Buyer after the Closing, including surface use agreements; farmin and farmout agreements; bottomhole agreements; crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; pooling declarations or agreements; unitization agreements; processing agreements; saltwater disposal agreements; water use agreements; facilities or equipment leases; crossing agreements; letters of no objection; production handling agreements; frac pond agreements; and other similar contracts and agreements, except for any master services agreements.

“Assets” shall have the meaning set forth in Section 2.1.

“Assignment” shall mean the Assignment and Bill of Sale from Seller to Buyer, pertaining to certain of the Assets, substantially in the form attached to this Agreement as Exhibit C.

“Assignment and Assumption” shall mean the Assignment and Assumption from Seller to Buyer, pertaining to certain of the Assets, substantially in the form attached to this Agreement as Exhibit D.

“Assumed Obligations” shall have the meaning set forth in Section 12.1.

“Business Day” means a day other than a Saturday, Sunday or a day on which commercial banks in Houston, Texas are authorized or required by applicable Law to be closed for business.

“Buyer” shall have the meaning set forth in the preamble to this Agreement.

Appendix 1-1

“Buyer Indemnified Parties” shall have the meaning set forth in Section 12.2.

“Buyer’s Representatives” shall have the meaning set forth in Section 9.1(a).

“Carrizo” shall have the meaning set forth in the preamble to this Agreement.

“Casualty Loss” means any loss, damage or reduction in value of the Assets that occurs during the period between the Execution Date and Closing as a result of acts of God, fire, explosion, earthquake, windstorm or flood, but excluding any loss, damage or reduction in value as a result of depreciation, ordinary wear and tear and any change in condition of the Assets for production of Hydrocarbons through normal depletion (including the watering-out of any well, collapsed casing or sand infiltration of any well).

“Claim” shall have the meaning set forth in Section 12.7(b).

“Claim Notice” shall have the meaning set forth in Section 12.7(b).

“CLLR” shall have the meaning set forth in the preamble to this Agreement.

“Closing” shall have the meaning set forth in Section 8.1.

“Closing Date” shall have the meaning set forth in Section 8.1.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” shall mean that certain Confidentiality Agreement by and between Carrizo and Buyerdated effective as ofJuly 10, 2013.

“Contract” shall mean any written or oral contract, agreement, agreement regarding indebtedness, indenture, debenture, note, bond, loan, lease, mortgage, franchise, license agreement, purchase order, binding bid, commitment, letter of credit or any other legally binding arrangement, excluding, however, any Lease, contract or agreement relating to Seismic Data and Information, easement, right-of-way, permit or other instrument creating or evidencing an interest in the Assets or a real or immovable property related to or used in connection with the operations of any Assets.

“Conveyance Documents” shall mean the Assignment and the Deed.

“Cure Assets” shall have the meaning set forth in Section 10.2.

“Cure Period” shall have the meaning set forth in Section 10.2.

“Customary Post-Closing Consents” shall mean the consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer, that are customarily obtained after the assignment of properties similar to the Assets, and consents of lessors under any Lease that specifies that the lessor’s consent will not be unreasonably withheld, which lessors’ consents are set forth on Schedule 4.4(b).

Appendix 1-2

“Deed” shall mean the Deedpertaining to certain of the Assets, substantially in the form attached to this Agreement as Exhibit E.

“Defensible Title” shall mean such title of Seller with respect to the Assets that, subject to Permitted Encumbrances:

(a)    with respect to each Well, Undrilled Location and Fee Interest shown in Schedule 3.8 (or the specified zone(s) therein), entitles Seller to receive not less than the Net Revenue Interest shown for such Well, Undrilled Location or Fee Interest in Schedule 3.8 (or the specified zone(s) therein) throughout the duration of the productive life of such Well, Undrilled Location or Fee Interest (or the specified zone(s) therein), except (i) for decreases in connection with those operations in which Seller may from and after the date of this Agreement be a non-consenting co-owner if permitted by the terms of this Agreement, (ii) for decreases resulting from the establishment or amendment from and after the date of this Agreement of pools or units if permitted by the terms of this Agreement, (iii) for decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries, to the extent such underproduction or under deliveries are set forth on Schedule 4.11, and (iv) as otherwise set forth in Schedule 3.8;

(b)    with respect to each Well, Undrilled Location or Fee Interest (or the specified zone(s) therein) listed on Schedule 3.8, obligates Seller to bear not more than the Working Interest shown in Schedule 3.8 for such Well, Undrilled Location or Fee Interest (or the specified zone(s) therein), unless any defect relating to such increase is accompanied by a proportionate increase in the Net Revenue Interest for such Well, Undrilled Location or Fee Interest (or the specified zone(s) therein);

(c)    with respect to Assets other than the Fee Interests, Leases, Undrilled Locations or Wells (or the specified zone(s) therein) is defensible;

(d)    is free and clear of all Encumbrances (except for the Permitted Encumbrances); and

(e)    if a Preferential Right to Purchase applies to such Assets, in connection with the transaction contemplated by this Agreement such Preferential Right to Purchase has been waived in writing or the time period during which such Preferential Right to Purchase must be exercised has expired (without such preferential purchase price having been exercised), and if a consent (other than a Customary Post-Closing Consent) applies to such Assets in connection with the transaction contemplated by this Agreement, such consent has been granted in writing.    

“Dispute” shall have the meaning set forth in Section 14.12(b).

“Dispute Notice” shall have the meaning set forth in Section 14.12(b).

“DTPA” shall have the meaning set forth in Section 12.12(a).

Appendix 1-3

“Easements” shall have the meaning set forth in Section 2.1(f).

“Effective Time” shall mean 12:01 a.m. (Central Standard Time) on July 1, 2013.

“Encumbrance” shall mean any lien, security interest, pledge, charge or encumbrance.

“Environmental Arbitrator” shall have the meaning set forth in Section 11.1(g).

“Environmental Claim Date” shall mean 30 days after the Execution Date.

“Environmental Condition” shall mean (a) a condition in, on, under or migrating from the Assets (including the air, soil, subsurface, surface waters, ground waters and/or sediments) existing on or prior to the Closing Date that causes an Asset (or Seller with respect to an Asset) not to be in compliance with any Environmental Law, (b) the existence on or prior to the Closing Date with respect to the Assets or their operation of any environmental pollution, contamination, degradation, damage or injury for which remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws or (c) the failure of an Asset to be in compliance with any operational or permitting requirements imposed under Environmental Laws applicable to the Assets as of the Closing Date.

“Environmental Condition Cure Period” shall have the meaning set forth in Section 11.1(a).

“Environmental Condition Deductible” shall mean 2% of the Purchase Price.

“Environmental Condition Notice” shall have the meaning set forth in Section 11.1(a).

“Environmental Laws” shall mean all applicable federal, state and local laws in effect as of the date of this Agreement, including common law, relating to the protection of the public health, welfare and the environment, including those laws relating to the storage, handling and use of chemicals and other Hazardous Substances, and those relating to the generation, processing, treatment, storage, transportation, disposal or other management thereof. The term “Environmental Laws” does not include good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority that exceed the requirements of Environmental Laws.

“Excluded Assets” shall mean (a) all of Seller’s corporate minute books, financial records and other business records that relate to Seller’s business other than those directly related to the ownership and operation of the Assets and Seller’s accounting records (other than Operating Data); (b) all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time; (c) all claims and causes of action of Seller arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds), except to the extent relating to an Assumed Obligation; (d) all rights and interests of Seller (A) under any policy or agreement of insurance or indemnity, (B) under any bond or (C) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction

Appendix 1-4

of property prior to the Effective Time, in each case, except to the extent relating to an Assumed Obligation; (e) all Hydrocarbons produced and sold from the Properties with respect to all periods prior to the Effective Time; (f) all claims of Seller for refunds of or loss carry forwards with respect to (A) Taxes for which Seller is responsible pursuant to Section 14.1(b), (B) income or franchise Taxes or (C) any Taxes attributable to the Excluded Assets; (g) all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks and logos and all other intellectual property of any kind; (h) all documents and instruments of Seller that are protected by an attorney-client privilege or that are work product of Seller’s counsel (other than title opinions); (i) all data that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties; provided that (except with respect to all Seismic Data and Information) Seller shall use its commercially reasonable efforts to obtain a waiver of such restrictions in order to permit disclosure to Buyer; (j) all Seismic Data and Information relating to the Assets that requires Third Party consent for transfer to Buyer if such consent is not obtained or obtainable without the payment of any funds that have not been paid by Buyer, and all such Contracts relating to Seismic Data and Information are set forth on Schedule 1; (k) all audit rights arising under any of the Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Imbalances and except to the extent relating to an Assumed Obligation; (l) all other rights and obligations arising under the Applicable Contracts prior to the Effective Time (except to the extent relating to an Assumed Obligation); (m) documents prepared or received by Seller with respect to (A) lists of prospective purchasers for transactions compiled by Seller, (B) bids submitted by other prospective purchasers of the Assets, (C) analyses by Seller of any bids submitted by any prospective purchaser, (D) correspondence between or among Seller, its representatives and any prospective purchaser and (E) correspondence between Seller or any of its representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated in this Agreement; (n) any offices, office leases or personal property not directly related to any one or more of the Assets (for example, trucks, computers and communication equipment); (o) all reserve estimates and economic estimates; (p) copies of any of the foregoing that are retained by Seller; (q) copies of all log books and other Operating Data; (r) any Assets that are retained by Seller pursuant to Section 10.2(b), Section 10.3(d), Section 10.4 or Section 11.1(b); (s) any Assets which are excluded from the transaction contemplated by this Agreement by virtue of any provisions hereof; (t) Seller’s permits and licenses or other authorizations, to the extent not transferable; (u) all bonds, trade credits, account receivables, note receivables, take or pay amounts receivable and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time (except to the extent relating to an Assumed Obligation); (v) any amounts in suspense as of the Effective Time; (w) all Imbalances relating to the Properties or other Assets arising before the Effective Time; (x) all production, proceeds, income, receipts and credits to which Seller is entitled under Section 2.3, except to the extent relating to an Assumed Obligation; (y) originals of all Records that are not related to the Assets (subject to Buyer’s right to obtain a copy of such Records at its sole cost and expense; provided, however, that Buyer shall have no right to receive copies of (i) Tax Records unless such Tax Records are solely related to the Assets or (ii) any Records that are otherwise excluded herein); (y) all abandoned and unclaimed property reportable under any state or local unclaimed property, escheat or similar Law where such property relates to or arose under periods prior to the Effective Time and (z) all assets set forth in Schedule 1.

Appendix 1-5

“Execution Date” shall have the meaning set forth in the preamble to this Agreement.

“Fee Interests” shall have the meaning set forth in Section 2.1(a).

“Final Price” shall have the meaning set forth in Section 3.5.

“Final Settlement Statement” shall have the meaning set forth in Section 3.5.

“Fundamental Representations” shall mean the representations and warranties set forth in Section 4.1, Section 4.2, Section 5.1 and Section 5.2.

“Governmental Authority” shall mean any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

“Hazardous Substances” shall mean any pollutants, contaminants, toxic, hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals including Hydrocarbons that are regulated by, or may form the basis of liability under, any Environmental Laws, including NORM and other substances referenced in Section 11.2.

“Hedging Transactions” shall have the meaning set forth in Section 14.16.

“Hondo” shall have the meaning set forth in the preamble to this Agreement.

“Hydrocarbons” shall mean oil and gas and other hydrocarbons produced or processed in association therewith.

“Imbalances” shall mean (a) any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Seller therein and the shares of production from the relevant Well to which Seller is entitled and (b) any marketing imbalance between the quantity of Hydrocarbons required to be delivered by Seller under any Contract relating to the purchase and sale, gathering, transportation, storage, processing or marketing of Hydrocarbons and the quantity of Hydrocarbons actually delivered by Seller pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning future in-kind and/or cash balancing at the wellhead and production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility.

“Indemnified Party” shall have the meaning set forth in Section 12.7(a).

“Indemnifying Party” shall have the meaning set forth in Section 12.7(a).

“Individual Environmental Threshold” shall have the meaning set forth in Section 11.1(f).

“Individual Title Benefit Threshold” shall mean $25,000.

Appendix 1-6

“Individual Title Defect Threshold” shall have the meaning set forth in Section 10.2(e).

“Interim Period” shall mean that period of time commencing at the Effective Time and ending at 12:01 a.m. (Central Standard Time) on the Closing Date.

“Knowledge” shall mean, with respect to Seller, the actual knowledge, after due inquiry, of the following Persons: Brad Fisher, Andy Agosto and Sheldon Lowery; and with respect to Buyer, the actual knowledge, after due inquiry, of the following Persons: Phil C. DeLozier, Stephen A. McDaniel, Lloyd Bruce, and John Marrs.

“Lands” shall have the meaning set forth in Section 2.1(b).

“Law” shall mean any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

“Leases” shall have the meaning set forth in Section 2.1(b).

“Liabilities” shall mean any and all claims, causes of actions, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines, costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury, death or property damage.

“Like-Kind Exchange” shall have the meaning set forth in Section 6.7.

“Material Adverse Effect” shall mean an event, effect or circumstance that, individually or in the aggregate, does or would reasonably be expected to have a material adverse effect on (a) the ownership, operations or condition of the Assets, taken as a whole, exceeding $500,000 or (b) the ability of Seller to consummate the transactions contemplated by this Agreement; provided, however, that, for the purpose of clause (a) hereof, none of the following effects, events or circumstances relating to or resulting from the following shall be deemed to constitute a Material Adverse Effect: (i) changes in generally applicable market, economic, financial or political conditions (including changes in fuel supply or transportation markets, credit and equity markets, interest or rates) in Texas, the United States or worldwide, or any outbreak of hostilities, war or terrorist acts; (ii) changes in the prices of Hydrocarbons; (iii) acts or failures to act of Governmental Authorities or a change in Laws (or interpretations thereof) from and after the Execution Date; (iv) generally applicable to the oil and gas industry or to the sector of the industry as to which the Assets relate, (v) entering into this Agreement or the announcement or proposed consummation of the transactions contemplated herein; (vi) acts of God, including storms, drought or meteorological events; (vii) matters that are cured or no longer exist by the earlier of the Closing or the termination of this Agreement; (viii) reclassification or recalculation of reserves in the ordinary course of business; or (ix) declines in well performance due to natural causes, except in the cases of clauses (i) through (iv), to the extent disproportionately affecting the Assets as compared with other Persons or businesses in the oil and gas exploration and production industry generally and then only such disproportionate impact shall be considered.

“Material Contract” shall have the meaning set forth in Section 4.7(a).

Appendix 1-7

“Mescalero” shall have the meaning set forth in the preamble to this Agreement.

“Net Acres” shall mean, as computed separately with respect to each Lease, (a) the number of gross acres in the lands covered by such Lease, multiplied by (b) the undivided percentage interest in oil, gas or other minerals covered by such Lease in such lands, multiplied by (c) Seller’s Working Interest in such Lease; provided that if items (b) and/or (c) vary as to different areas of such lands (including depths) covered by such Lease, a separate calculation shall be done for each such area as if it were a separate Lease.

“Net Revenue Interest” with respect to any Well, Undrilled Location or Fee Interest, shall mean the interest in and to all Hydrocarbons produced, saved, and sold from or allocated to such Well, Undrilled Location or Fee Interest, after giving effect to all Royalties.

“NGA” shall have the meaning set forth in Section 4.21.

“NORM” shall mean naturally occurring radioactive material.

“Operating Data” shall mean operations, environmental and production data, including division of interest decks, joint interest billings, payout statements, plant statements, lease operating statements and receipts or other records kept with respect to payment of invoices.

“Operating Expenses” shall have the meaning set forth in Section 2.3(a).

“Permitted Encumbrances” shall have the meaning set forth on Appendix 2.

“Permitted Liens” shall mean, with respect to each Asset, all Encumbrances set forth on Schedule 2.

“Person” shall mean any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Authority or any other entity.

“Personal Property” shall have the meaning set forth in Section 2.1(g).

“Post-Closing Deductible” shall mean 1.5% of the Final Price.

“Preferential Right to Purchase” shall mean any Third Party’s preferential right to purchase any of the Assets or any interest in any Asset or any portion of any Asset.

“Preliminary Settlement Statement” shall have the meaning set forth in Section 3.4.

“Production Taxes” shall have the meaning set forth in Section 4.17.

“Properties” shall have the meaning set forth in Section 2.1(c).

“QEAT” shall have the meaning set forth in Section 6.7.

“QI” shall have the meaning set forth in Section 6.7.

Appendix 1-8

“Purchase Price” shall have the meaning set forth in Section 3.1.

“Records” shall have the meaning set forth in Section 2.1(j).

“Remediation” shall mean, with respect to an Environmental Condition, the implementation and completion of any and all investigatory, cleanup, monitoring, remedial, removal, response, construction, closure, disposal, treatment, containment, mitigation or other corrective actions required under Environmental Laws in effect on the Closing Date conducted after the identification of an Environmental Condition pursuant to Section 11.1 and to correct or remove such Environmental Condition to a degree sufficient to meet the requirements of Section 11.1.

“Remediation Amount” shall mean, with respect to an Environmental Condition, the present value as of the Closing Date (using an annual discount rate of 10%) of the reasonable cost (net to Seller’s interest) of the Remediation of such Environmental Condition, so as to allow for the continued operation of the Asset in the same manner in which it is operated on the Closing Date, and by methods of Remediation that are consistent with customary industry practices in the State of Texas as accepted by Governmental Authorities under Environmental Laws.

“Response” shall have the meaning set forth in Section 14.12(b).

“Retained Obligations” shall have the meaning set forth in Section 12.2(b).

“Royalties” shall mean royalties, overriding royalties, production payments, carried interests, net profits interests, reversionary interests and other burdens upon, measured by or payable out of production therefrom.

“Securities Act” shall mean the Securities Act of 1933, as amended.

“Seismic Data and Information” shall have the meaning set forth in Section 2.1(i).

“Senior Manager” shall have the meaning set forth in Section 14.12(b).

“Seller” shall have the meaning set forth in the preamble to this Agreement.

“Seller Indemnified Parties” shall have the meaning set forth in Section 12.3(a).

“Seller’s Representatives” shall have the meaning set forth in Section 9.2.

“Settlement Statement Dispute Notice” shall have the meaning set forth in Section 3.5.

“Tax Allocation” shall have the meaning set forth in Section 3.7.

“Taxes” shall mean any taxes, imposed by any Governmental Authority, including income, profits, franchise, withholding, employment, social security, disability, occupation, ad valorem, property, severance, production and excise taxes, together with any interest, penalties or additions thereto.

Appendix 1-9

“Third Party” shall mean any Person other than a party to this Agreement or an Affiliate of a party to this Agreement.

“Title Arbitrator” shall have the meaning set forth in Section 10.2(g).

“Title Claim Date” shall have the meaning set forth in Section 10.2(a).

“Title Benefit” shall mean any right, circumstance or condition that entitles Seller to a larger Net Revenue Interest or a smaller Working Interest (without a decrease in the Net Revenue Interest that is either proportionate or proportionately greater than such decrease in the Working Interest) than that shown on Schedule 3.8.

“Title Benefit Amount” shall mean:

(i)if Seller and Buyer agree on the Title Benefit Amount, then that amount will be the Title Benefit Amount;

(ii)if the Title Benefit represents a discrepancy between (A) the Net Revenue Interest for any Title Benefit Property and (B) the Net Revenue Interest described in Schedule 3.8, for such Title Benefit Property, then the Title Benefit Amount will be the product of the Allocated Value of the affected Title Benefit Property multiplied by a fraction, the numerator of which is the Net Revenue Interest increase for such Title Benefit Property and the denominator of which is the Net Revenue Interest of such Title Benefit Property described in Schedule 3.8 for such Title Benefit Property; provided that if the increased Net Revenue Interest does not affect the Title Benefit Property throughout the entire life of the Title Benefit Property, then the Title Benefit Amount will be reduced to take into account the applicable time period only; and

(iii)if the Title Benefit represents a benefit to title to the Title Benefit Property of a type not described in (i) or (ii) above, the Title Benefit Amount will be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of the Title Benefit Property benefited by the Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of the Title Benefit Property, the values placed upon the Title Benefit by Buyer and Seller and such other factors as are necessary to make a proper evaluation.

“Title Benefit Notice” shall have the meaning set forth in Section 10.2(f).

“Title Benefit Property” shall have the meaning set forth in Section 10.2(f).

“Title Defect” shall mean any Encumbrance (other than a Permitted Encumbrance), defect or other matter that causes Seller not to have Defensible Title in and to the Wells, Undrilled Locations or Fee Interests as of the Closing Date; provided that the items set forth on Appendix 3 shall not be considered Title Defects.

Appendix 1-10

“Title Defect Amount” shall have the meaning set forth in Section 10.2(d).

“Title Defect Deductible” shall mean 1.5% of the Purchase Price.

“Title Defect Notice” shall have the meaning set forth in Section 10.2(a).

“Title Defect Property” shall have the meaning set forth in Section 10.2(a).

“Transaction Documents” shall mean those documents executed pursuant to or in connection with this Agreement.

“Transfer Taxes” shall have the meaning set forth in Section 14.1(b).

“Treasury Regulations” shall mean the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed or final Treasury Regulations.

“Undrilled Locations” shall mean the undrilled wells and locations identified on Schedule 3.8 as either a PUD, PROB or POSS.

“Wells” shall have the meaning set forth in Section 2.1(c).

“Working Interest” with respect to any Well, Undrilled Location or Fee Interest, shall mean the interest in and to such Well, Undrilled Location or Fee Interest that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Well, Undrilled Location or Fee Interest, but without regard to the effect of any royalties, overriding royalties, production payments, net profits interests and other similar burdens upon, measured by or payable out of production therefrom.

Appendix 1-11

Appendix 2

Permitted Encumbrances

Permitted Encumbrances shall mean:

(a)    lessor’s royalties, non-participating royalties, overriding royalties, reversionary interests and similar burdens upon, measured by or payable out of production, if the net cumulative effect of such burdens does not (i) operate to reduce the Net Revenue Interest of Seller in any Well, Undrilled Location or Fee Interest to an amount less than the Net Revenue Interest set forth on Schedule 3.8; or (ii) obligate Seller to bear a Working Interest for such Well, Undrilled Location or Fee Interest in any amount greater than the Working Interest set forth on Schedule 3.8 (or the specified zone(s) therein) (unless the Net Revenue Interest for such Well, Undrilled Location or Fee Interest is greater than the Net Revenue Interest set forth on Schedule 3.8, in the same proportion as any increase in such Working Interest);

(b)    liens for Taxes or assessments not yet due or delinquent or if due that are being contested in good faith in the normal course of business and liens for Taxes on the sale of Hydrocarbons relating to the Assets and payable to owners of Working Interests, Royalties and other similar interests that, in each case, are held by Seller in suspense as of the Effective Time;

(c)    Customary Post-Closing Consents, including those set forth on Schedule 4.4(b);

(d)    Preferential Rights to Purchase as set forth on Schedule 4.9 and Third Party consents as set forth on Schedule 4.4(a);

(e)    such Title Defects as Buyer may have waived in writing;

(f)    all applicable Laws, and rights reserved to or vested in any Governmental Authority (i) to control or regulate any Asset in any manner; and (ii) to enforce any obligations or duties affecting the Assets to any Governmental Authority, with respect to any franchise, grant, license, or permit;

(g)    easements, servitudes, permits, rights-of-way, surface leases and other rights in respect of surface operations on the Assets which do not individually or in the aggregate materially impair the use of the Assets as currently owned and operated or would reasonably be expected to materially impair the ability of Buyer to develop a future or planned location identified by Seller in its data room presented by Evercore Partners;

(h)    vendor’s, carrier’s, warehousemen’s, repairmen’s, mechanic’s, workmen’s, materialmen’s, contractor’s, construction or other similar liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due or if due that are being contested in good faith in the ordinary course of business;

(i)    liens created under Leases and/or an Applicable Contract or by operation of Law in respect of obligations that are not yet due;

Appendix 2-1

(j)    the terms and conditions of this Agreement or any other Transaction Document;

(k)    the terms and conditions of any Lease or Applicable Contract which individually and in the aggregate as of the Closing Date do not (i) reduce the Net Revenue Interest of Seller in any Well, Undrilled Location or Fee Interest to an amount less than the Net Revenue Interest set forth on Schedule 3.8; or (ii) obligate Seller to bear a Working Interest for such Well, Undrilled Location or Fee Interest in any amount greater than the Working Interest set forth on Schedule 3.8 (unless the Net Revenue Interest for such Well, Undrilled Location or Fee Interest is greater than the Net Revenue Interest set forth on Schedule 3.8, in the same proportion as any increase in such Working Interest);

(l)    any Encumbrance affecting the Assets that is discharged by Seller at or prior to Closing;

(m)    unsubordinated liens for purchase money mortgages or similar types of financing securing residential property included in a non-wellbore tract or a wellbore tract associated with an Undrilled Location;

(n)    rights of reassignment arising upon final intention to abandon or release any of the Assets;

(o)    Imbalances set forth on Schedule 4.11;

(p)    all Permitted Liens;

(q)    all other liens, charges, encumbrances, defects or irregularities which do not, individually or in the aggregate, materially detract from the value of or materially interfere with the use or ownership of the Wells, Undrilled Locations or Fee Interests subject thereto or affected thereby (as currently used or owned), which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties, and which do not (i) reduce Seller’s Net Revenue Interest below that shown on Schedule 3.8; or (ii) increase Seller’s Working Interest above that shown on Schedule 3.8, without a corresponding increase in Net Revenue Interest;

(r)    rights of a common owner of any interest in rights-of-way or easements currently held by Seller and such common owner as tenants in common or through common ownership; and

(s)    zoning and planning ordinances and municipal regulations.

Appendix 2-2

Appendix 3

Illustrative List of Items that are not Title Defects

For the avoidance of doubt, the existence of any of the following with respect to any Asset shall not be a “Title Defect”:

(a)    defects in the chain of title or in the Lease itself consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Buyer provides affirmative evidence that such failure or omission has resulted in another Person’s superior claim of title to the relevant Asset;

(b)    defects arising out of lack of survey or lack of metes and bounds descriptions, unless a survey or metes and bounds description is expressly required by applicable Laws;

(c)    defects arising out of lack of corporate or other entity authorization unless Buyer provides affirmative evidence that such corporate or other entity action was not authorized and such lack of authorization results in another Person’s superior claim to title of the applicable Well or Fee Interest;

(d)    defects that have been cured by applicable Laws of limitations or prescription;

(e)    defects based on a gap in Seller’s chain of title in the applicable county records, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain;

(f)    any Encumbrance or loss of title resulting from Seller’s conduct of business after the Execution Date in compliance with this Agreement;

(g)    the fact that CLLR is the beneficial owner and Carrizo is the record owner of certain Properties;

(h)    defects arising from any change in applicable Law after the Execution Date, including changes that would raise the minimum landowner royalty;

(i)    defects or irregularities resulting from or related to probate proceedings or the lack thereof, which defects or irregularities have been outstanding for seven and a half years or more;

(j)    defects arising from prior oil and gas leases relating to the Leases that are terminated, expired or invalid but not surrendered of record;

(k)    any Asset subject to executed and recorded landowner consents for surface mining on such Asset to the extent the same does not materially impair Buyer’s use or ownership of the Asset;

(l)    any preferential purchase right attached to a Well or Fee Interest that (in connection with the transactions contemplated by this Agreement) either has been waived in writing or for

Appendix 3-1

which the time period during which such preferential purchase right must be exercised has expired (without the exercise of such preferential purchase right);

(m)    any lessor consent under a Lease that (in connection with the transactions contemplated by this Agreement) has been granted in writing;

(n)    in the case of any wells to be drilled in the future, any permits, easements (other than subsurface easements), or rights-of-way, in each case, not yet required to be obtained; and

(o)    any defect that affects only which person has the right to receive royalty payments (rather than the amount of such royalty) and that does not affect the validity of the underlying Well, Undrilled Location or Fee Interest; and to the extent the same does not (i) reduce the Net Revenue Interest of Seller in any Well, Undrilled Location or Fee Interest below the Net Revenue Interest set forth on Schedule 3.8 (unless the Working Interest for such Well, Undrilled Location or Fee Interest is lesser than the Working Interest set forth on Schedule 3.8, in the same proportion as any increase in such Net Revenue Interest); or (ii) obligate Seller to bear a Working Interest for any Well, Undrilled Location or Fee Interest that is greater than the Working Interest set forth on Schedule 3.8 (unless the Net Revenue Interest for such Well, Undrilled Location or Fee Interest is greater than the Net Revenue Interest set forth on Schedule 3.8, in the same proportion as any increase in such Working Interest).

Appendix 3-2

EX-2.2

Exhibit 2.2

FIRST AMENDMENT TO PURCHASE AND SALE AGREEMENT

This First Amendment to Purchase and Sale Agreement (as may be amended, restated, supplemented or otherwise modified from time to time, this “Amendment”) is executed as of this 5th day of September, 2013 (the “Execution Date”), and is among Carrizo Oil & Gas, Inc., a Texas corporation (“Carrizo”), CLLR, Inc., a Delaware corporation (“CLLR”) and Hondo Pipeline, Inc., a Delaware corporation (“Hondo”), and Mescalero Pipeline, LLC, a Delaware limited liability company (“Mescalero,” and together with Carrizo, and CLLR and Hondo, “Seller”) and 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., each a Delaware limited partnership, (collectively, “Buyer”) and EnerVest Holding, L.P., a Texas limited partnership (“EV Holding”). Each of Seller and Buyer and EV Holding may be referred to herein as a “Party” or collectively as the Parties.

Recitals

A.The Parties except for EV Properties, L.P. entered into that certain Purchase and Sale Agreement dated as of September 3, 2013 (the “Purchase Agreement”); and

B.Pursuant to Section 14.2 of the Purchase Agreement, EV Holding has conveyed all of its rights, benefits, duties and obligations in, to and arising from the Purchase Agreement to EV Properties, L.P. resulting in the new proportionate shares as shown on the amended Exhibit F discussed below.

C.The Parties hereto desire to amend the Purchase Agreement and acknowledge certain matters as provided herein.

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, the Parties hereby agree as follows:

AMENDMENTS AND ACKNOWLEDGMENTS

1.Definitions. Capitalized terms used herein and not otherwise defined herein shall have the meanings set forth for such terms in the Purchase Agreement.

2.Amendment to Preamble. The preamble to the Purchase Agreement is hereby amended by deleting the same and substituting in lieu and replacement thereof the following:

THIS PURCHASE AND SALE AGREEMENT (as may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is executed as of this 3rd day of September, 2013 (the “Execution Date”), and is among Carrizo Oil & Gas, Inc., a Texas corporation (“Carrizo”), CLLR, Inc., a Delaware corporation (“CLLR”) and Hondo Pipeline, Inc., a Delaware corporation (“Hondo”), and Mescalero Pipeline, LLC, a Delaware limited liability company (“Mescalero,” and together with Carrizo, CLLR and Hondo, “Seller”) and EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy

1

Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P., and EV Properties, L.P., each a Delaware limited partnership (collectively, “Buyer”).

3.Section 14.2. Section 14.2 of the Purchase Agreement is hereby amended and restated in its entirety as follows:

Except as otherwise set forth in Section 6.7, this Agreement may not be assigned by either party without prior written consent of the other. No assignment of any rights hereunder by a party shall relieve such party of any obligations and responsibilities hereunder.

4.Exhibit F. Exhibit F of the Purchase Agreement is hereby amended in its entirety by deleting the Exhibit F attached to the Purchase Agreement and replacing it with the attached Exhibit F.

5.Liability and Release. Upon execution of this Amendment, the Parties agree that EV Holding will no longer be liable for any duties or obligations under the Purchase Agreement, nor entitled to any rights or benefits. Buyer will assume all duties and obligations for full performance of the Purchase Agreement, and Seller releases EV Holding from any duties or obligations related to the Purchase Agreement.

6.References. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

7.Miscellaneous Provisions. The provisions of Article XIV of the Purchase Agreement are incorporated herein by this reference as if set out fully herein and shall apply in all respects to this Amendment.

8.Counterparts. This Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute.

[THE NEXT SUCCEEDING PAGE IS THE EXECUTION PAGE]

2

IN WITNESS WHEREOF, the Parties have executed this First Amendment to Purchase and Sale Agreement on the date first above written.

SELLER:
CARRIZO OIL & GAS, INC.
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary
CLLR, INC.
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary
HONDO PIPELINE, INC.
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary
MESCALERO PIPELINE, LLC
By:	/s/ Paul F. Boling
	Paul F. Boling
	Vice President, Chief Financial Officer, Treasurer and Secretary

Signature Page to First Amendment to Purchase and Sale Agreement

BUYER:
ENERVEST ENERGY INSTITUTIONAL FUND XIII-A, L.P. ENERVEST ENERGY INSTITUTIONAL FUND XIII-WIB, L.P.
By:	EnerVest, Ltd., its Managing General Partner
By:	EnerVest Management GP, L.C., its General Partner
By:	/s/ John B. Walker
	John B. Walker
	President and Chief Executive Officer
ENERVEST ENERGY INSTITUTIONAL FUND XIII-WIC, L.P.
By:	EnerVest Holding XIII, LLC, its General Partner
By:	EnerVest Ltd., its Sole Member
By:	EnerVest Management GP, L.C., its General Partner
By:	/s/ John B. Walker
	John B. Walker
	President and Chief Executive Officer
ENERVEST HOLDING, L.P.
By:	EnerVest Operating, L.L.C., its General Partner
By:	/s/ Mark A. Houser
	Mark A. Houser
	Executive Vice President

Signature Page to First Amendment to Purchase and Sale Agreement

EV PROPERTIES, L.P.
By:	EV Properties GP, LLC, its General Partner
By:	/s/ Mark A. Houser
	Mark A. Houser
	President and Chief Executive Officer

Signature Page to First Amendment to Purchase and Sale Agreement

Exhibit F

PROPORTIONATE SHARES

EnerVest Energy Institutional Fund XIII-A, L.P.	29.92724	%
EnerVest Energy Institutional Fund XIII-WIB, L.P.	0.99809	%
EnerVest Energy Institutional Fund XIII-WIC, L.P.	38.07467	%
EV Properties, L.P.	31.00000	%
	100.00000	%

EX-31.1

Exhibit 31.1

CERTIFICATION

PRINCIPAL EXECUTIVE OFFICER

I, S.P. Johnson, IV, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 4, 2013	/s/ S.P. Johnson, IV
		S.P. Johnson, IV President, Chief Executive Officer and Director

EX-31.2

Exhibit 31.2

CERTIFICATION

PRINCIPAL FINANCIAL OFFICER

I, Paul F. Boling, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 4, 2013	/s/ Paul F. Boling
		Paul F. Boling Chief Financial Officer, Vice President, Secretary and Treasurer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson, IV, President and Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

1. the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 4, 2013	/s/ S.P. Johnson, IV
		S.P. Johnson, IV President, Chief Executive Officer and Director

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Paul F. Boling, Vice President, Chief Financial Officer and Secretary of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

1. the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2013 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 4, 2013	/s/ Paul F. Boling
		Paul F. Boling Chief Financial Officer, Vice President, Secretary and Treasurer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

CARRIZO OIL & GAS, INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

	September 30, 2013
	Historical		Pro Forma Adjustments for Sale to EnerVest				Pro Forma
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,728	$	101,930		(1)	$	107,658
Accounts receivable, net and other current assets	131,437		15,837			(1)	147,274
Total current assets	137,165		117,767				254,932
TOTAL PROPERTY AND EQUIPMENT, NET	1,901,072		(249,495		)	(2)	1,651,577
OTHER ASSETS	33,758		—				33,758
TOTAL ASSETS	$	2,071,995	$	(131,728	)		$	1,940,267
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES	354,064		—				354,064
LONG-TERM DEBT, NET OF DEBT DISCOUNT	987,074		(87,000		)	(1)	900,074
ASSET RETIREMENT OBLIGATIONS	6,341		(445		)	(3)	5,896
DEFERRED INCOME TAXES	32,796		(15,499		)	(4)	17,297
OTHER LIABILITIES	23,642		—				23,642
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY	668,078		(28,784		)	(5)	639,294
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,071,995	$	(131,728	)		$	1,940,267

See the accompanying notes to the unaudited pro forma condensed consolidated financial statements.

CARRIZO OIL & GAS, INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

	For the Nine Months Ended September 30, 2013
	Historical			Pro Forma Adjustments for Sale to EnerVest				Pro Forma
	(In thousands, except per share amounts)
OIL AND GAS REVENUES	$	390,454		$	(30,624	)	(1)	$	359,830
COSTS AND EXPENSES
Lease operating	34,926			(5,649		)	(1)	29,277
Production tax	14,687			(503		)	(1)	14,184
Ad valorem tax	6,848			(298		)	(1)	6,550
Depreciation, depletion and amortization	151,232			7,573			(2)	158,805
General and administrative	53,722			—				53,722
Accretion expense related to asset retirement obligations	355			(31		)	(3)	324
TOTAL COSTS AND EXPENSES	261,770			1,092				262,862
OPERATING INCOME (LOSS)	128,684			(31,716		)		96,968
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net	(16,486		)	—				(16,486		)
Interest expense	(64,158		)	527			(4)	(63,631		)
Capitalized interest	21,791			(2,761		)	(5)	19,030
Other income (expense), net	95			—				95
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	69,926			(33,950		)		35,976
INCOME TAX (EXPENSE) BENEFIT	(25,853		)	11,883			(6)	(13,970		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	$	44,073		$	(22,067	)		$	22,006
NET INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON SHARE
Basic	$	1.10						$	0.55
Diluted	$	1.09						$	0.54
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	40,083							40,083
Diluted	40,601							40,601

See the accompanying notes to the unaudited pro forma condensed consolidated financial statements.

CARRIZO OIL & GAS, INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

	For the Year Ended December 31, 2012
	Historical			Pro Forma Adjustments for Sale to Atlas				Pro Forma Adjustments for Sale to EnerVest				Pro Forma
	(In thousands, except per share amounts)
OIL AND GAS REVENUES	$	368,180		$	(6,878	)	(1)	$	(34,340	)	(1)	$	326,962
COSTS AND EXPENSES
Lease operating	31,471			(3,664		)	(1)	(9,560		)	(1)	18,247
Production tax	13,542			(67		)	(1)	(537		)	(1)	12,938
Ad valorem tax	9,813			(547		)	(1)	(2,679		)	(1)	6,587
Depreciation, depletion and amortization	165,621			(715		)	(2)	(75		)	(2)	164,831
General and administrative	48,708			—				—				48,708
Accretion expense related to asset retirement obligations	372			(26		)	(3)	(42		)	(3)	304
TOTAL COSTS AND EXPENSES	269,527			(5,019		)		(12,893		)		251,615
OPERATING INCOME (LOSS)	98,653			(1,859		)		(21,447		)		75,347
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net	31,371			—				—				31,371
Interest expense	(73,006		)	1,431				1,431			(4)	(70,144		)
Capitalized interest	24,848			(755		)		(3,021		)	(5)	21,072
Other income (expense), net	267			—				—				267
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	82,133			(1,183		)		(23,037		)		57,913
INCOME TAX (EXPENSE) BENEFIT	(30,956		)	414			(6)	8,063			(6)	(22,479		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	$	51,177		$	(769	)		$	(14,974	)		$	35,434
NET INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON SHARE
Basic	$	1.29										$	0.90
Diluted	$	1.28										$	0.89
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	39,591											39,591
Diluted	40,026											40,026

See the accompanying notes to the unaudited pro forma condensed consolidated financial statements.

CARRIZO OIL & GAS, INC.

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

On October 31, 2013, the Company closed on the previously announced definitive agreement to sell, effective July 1, 2013, substantially all of its remaining oil and gas assets in the Barnett Shale (the “EnerVest Properties”) 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., EV Properties, L.P., and EnerVest Holding, L.P. (collectively, “Enervest”). The effective date of this sale was July 1, 2013. The Company received net cash proceeds of approximately $188.9 million at the closing and, as a consequence of certain post-closing adjustments and holdbacks, the Company could receive up to an additional $20.2 million in cash proceeds. EnerVest also agreed to assume certain liabilities and contractual obligations. The following unaudited pro forma financial information is presented to illustrate the effect of the Company’s disposition of these properties on its historical financial position and operating results. The unaudited pro forma balance sheet as of September 30, 2013 is based on the historical statements of the Company as of September 30, 2013 after giving effect to the sale of the EnerVest Properties as if the disposition had occurred on September 30, 2013. The unaudited pro forma statements of operations for the nine months ended September 30, 2013 and the year ended December 31, 2012 are based on the historical financial statements of the Company after giving effect to the transaction as if the disposition had occurred on January 1, 2012. The unaudited pro forma statements of operations for the year ended December 31, 2012 also give effect to the sale of a significant portion of the Company's Barnett Shale properties to Atlas Resource Partners, L.P. ("Atlas Properties") which closed in the second quarter of 2012, as if the disposition had occurred on January 1, 2012. The unaudited pro forma financial information should be read in conjunction with the Company’s historical consolidated financial statements and notes thereto contained in the Company’s 2012 Annual Report on Form 10-K, filed on February 27, 2013, and its quarterly reports filed on May 10, 2013 and August 7, 2013.

The preparation of the unaudited pro forma consolidated financial information is based on financial statements prepared in accordance with accounting principles generally accepted in the United States of America. These principles require the use of estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from those estimates.

The unaudited pro forma consolidated financial information is provided for illustrative purposes only and does not purport to represent what the actual results of operations would have been had the transaction occurred on the respective date assumed, nor is it necessarily indicative of the Company’s future operating results. However, the pro forma adjustments reflected in the accompanying unaudited pro forma consolidated financial information reflect estimates and assumptions that the Company’s management believes to be reasonable.

The proved reserves attributable to the EnerVest Properties represented 40% of the Company's proved reserves as of September 30, 2013 and therefore the sale significantly altered the relationship between capitalized costs and proved oil and gas reserves attributable to our U.S. cost center, resulting in a pro forma $44.3 million pre-tax loss on the sale of the EnerVest Properties as of September 30, 2013. The loss on the sale has been reflected as a $28.8 million after-tax adjustment to equity in the pro forma balance sheet, rather than an adjustment to the pro forma statements of operations. In addition, the sale of the EnerVest Properties resulted in an increase in the pro forma depreciation, depletion and amortization rate to $28.88 per Boe and $31.79 per Boe for the nine months ended September 30, 2013 and for the year ended December 31, 2012, respectively, as compared to the Company's historical depreciation, depletion and amortization rate of $19.59 per Boe and $17.55 per Boe for the nine months ended September 30, 2013 and for the year ended December 31, 2012, respectively.

2. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

The unaudited pro forma condensed consolidated balance sheet at September 30, 2013 reflects the following pro forma adjustments:

(1) Reflect the expected net proceeds to be received from the divestiture of EnerVest Properties and the use of a portion of those net proceeds to repay the amounts outstanding under the Company’s senior secured revolving credit facility with the remaining proceeds invested in cash and cash equivalents.

(2) Eliminate the unproved and allocated proved oil and gas property costs of the EnerVest Properties.

(3) Eliminate the asset retirement obligations associated with the EnerVest Properties.

(4) Eliminate the deferred income taxes associated with the disposition of the EnerVest Properties.

(5) Reflect the estimated $28.8 million after-tax loss on the sale of the EnerVest Properties.

3. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

The unaudited pro forma condensed consolidated statement of operations for the nine months ended September 30, 2013 reflects the following pro forma adjustments:

(1) Eliminate the revenues and direct operating expenses of the EnerVest Properties.

(2) Adjust depreciation, depletion and amortization to give effect to the sale of the EnerVest Properties.

(3) Eliminate the accretion expense related to asset retirement obligations associated with the EnerVest Properties.

(4) Reduce interest expense resulting from the application of a portion of the net proceeds as a reduction of the amounts outstanding under the Company’s senior secured revolving credit facility.

(5) Reduce capitalized interest resulting from the reduction in unproved property costs associated with the EnerVest Properties.

(6) Record income tax effect of the pro forma adjustments using the U.S. federal statutory rate of 35%.

4. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2012 reflects the following pro forma adjustments:

(1) Eliminate the revenues and direct operating expenses of the Atlas Properties and EnerVest Properties.

(2) Adjust depreciation, depletion and amortization to give effect to the sale of the Atlas Properties and EnerVest Properties.

(3) Eliminate the accretion expense related to asset retirement obligations associated with the Atlas Properties and EnerVest Properties.

(4) Reduce interest expense resulting from the application of a portion of the net proceeds as a reduction of the amounts outstanding under the Company’s senior secured revolving credit facility.

(5) Reduce capitalized interest resulting from the reduction in unproved property costs associated with the Atlas Properties and EnerVest Properties.

(6) Record income tax effect of the pro forma adjustments using the U.S. federal statutory rate of 35%.

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Subsequent Events (Notes)

3 Months Ended

Sep. 30, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

11. Subsequent Events

During the third quarter of 2013, the Company agreed in three separate transactions to sell certain non-core assets, including substantially all of its remaining Barnett Shale assets, certain non-core assets in East Texas, and acreage in non-core areas of the Marcellus Shale, for an aggregate agreed upon sales price of $248.5 million and the assumption of certain liabilities and contractual obligations, subject to customary closing conditions and purchase price adjustments. In one of these transactions, the Company agreed to sell substantially all of its remaining Barnett Shale assets (the "Barnett Transaction") to affiliates of EnerVest Ltd. ("EnerVest") for an agreed upon purchase price of $218.0 million, subject to closing and post-closing purchase price adjustments and the assumption by EnerVest of certain liabilities and contractual obligations. The Barnett Transaction had an effective date of July 1, 2013. The Company closed the sale of its non-core East Texas assets in early September for $8.7 million. The Company closed the Barnett Transaction and the sale of its non-core Marcellus Shale assets in late October and as of October 31, 2013, the Company has received aggregate net proceeds related to these two asset sales totaling approximately $209.7 million. In addition, as a consequence of certain post-closing adjustments and holdbacks, the Company could receive up to an additional $23.8 million in cash proceeds related to such sales.

In connection with the Barnett Transaction, the Company entered into derivative instruments on behalf of EnerVest. These derivative instruments were novated to EnerVest upon the closing of the Barnett Transaction. As of September 30, 2013, these derivative instruments were in a net asset position and had a fair market value of $0.5 million.

Avista Transaction. Effective September 2011, the Company entered into a joint venture in the Utica Shale with Avista. On October 31, 2013, the Company completed the acquisition of acreage located primarily in Guernsey and Noble counties, Ohio from Avista. The transaction had an effective date of July 1, 2013, and the Company paid Avista $73.2 million in cash, subject to post-closing adjustments. The Company had an ownership in the working interest of the properties acquired through the Avista Utica Shale Joint Venture. The properties in the Avista Utica Joint Venture were held with an equal interest by the Company and Avista. The agreement provides for post-closing price and acreage adjustments and indemnities.

In connection with the Avista Transaction, the Company terminated the previously existing Avista Utica Shale Joint Venture agreements. After giving effect to the Avista Transaction, the Company and Avista remain working interest partners in the Utica Shale with the Company acting as the operator of the jointly owned properties which are now subject to standard joint operating agreements. The Company and Avista have established a new area of mutual interest that has been significantly reduced in coverage area and now applies only to certain of those areas in which the Company and Avista jointly own properties.

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Consolidated Statements Of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
OIL AND GAS REVENUES	$ 144,329	$ 96,197	$ 390,454	$ 260,730
COSTS AND EXPENSES
Lease operating	12,934	7,145	34,926	22,599
Production tax	5,590	3,449	14,687	9,676
Ad valorem tax	2,125	2,327	6,848	8,238
Depreciation, depletion and amortization	55,234	46,518	151,232	121,459
General and administrative (inclusive of stock-based compensation expense of $9,872 and $5,091 for the three months ended September 30, 2013 and 2012, respectively, and $19,338 and $10,622 for the nine months ended September 30, 2013 and 2012, respectively)	19,715	12,354	53,722	36,974
Accretion related to asset retirement obligations	128	86	355	280
TOTAL COSTS AND EXPENSES	95,726	71,879	261,770	199,226
OPERATING INCOME	48,603	24,318	128,684	61,504
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net	(27,658)	(14,718)	(16,486)	26,975
Interest expense	(20,887)	(18,074)	(64,158)	(51,298)
Capitalized interest	7,485	5,917	21,791	17,951
Other income, net	28	20	95	254
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	7,571	(2,537)	69,926	55,386
INCOME TAX (EXPENSE) BENEFIT	(1,859)	592	(25,853)	(20,972)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	5,712	(1,945)	44,073	34,414
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	(1,191)	1,015	23,599	2,583
NET INCOME (LOSS)	$ 4,521	$ (930)	$ 67,672	$ 36,997
NET INCOME (LOSS) PER COMMON SHARE - BASIC
Net income from continuing operations - basic (in dollars per share)	$ 0.14	$ (0.05)	$ 1.10	$ 0.87
Net income from discontinued operations - basic (in dollars per share)	$ (0.03)	$ 0.03	$ 0.59	$ 0.07
Net income per share, basic (in dollars per share)	$ 0.11	$ (0.02)	$ 1.69	$ 0.94
NET INCOME (LOSS) PER COMMON SHARE - DILUTED
Net income from continuing operations - diluted (in dollars per share)	$ 0.14	$ (0.05)	$ 1.09	$ 0.86
Net income from discontinued operations - diluted (in dollars per share)	$ (0.03)	$ 0.03	$ 0.58	$ 0.07
Net income per share, diluted (in dollars per share)	$ 0.11	$ (0.02)	$ 1.67	$ 0.93
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic (in shares)	40,386	39,634	40,083	39,559
Diluted (in shares)	40,927	39,634	40,601	39,992

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Property And Equipment, Net

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property And Equipment, Net

4. Property and Equipment, Net

At September 30, 2013 and December 31, 2012, property and equipment, net consisted of the following:

	September 30, 2013			December 31, 2012
	(In thousands)
Proved oil and gas properties	$	2,207,220		$	1,713,827
Accumulated depreciation, depletion and amortization	(711,239		)	(561,279		)
Proved oil and gas properties, net	1,495,981			1,152,548
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	302,391			238,833
Exploratory wells in progress	41,926			43,803
Capitalized interest	50,974			41,052
Total unproved properties, not being amortized	395,291			323,688
Other property and equipment	16,323			17,079
Accumulated depreciation	(6,523		)	(5,641		)
Other property and equipment, net	9,800			11,438
Total property and equipment, net	$	1,901,072		$	1,487,674

Utica Shale Joint Venture. On January 15, 2013, we exercised our option for an additional 40% in the remaining properties held through our joint venture 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 Holdings, LP, a private equity firm (collectively with ACP II and ACP III, “Avista”) by paying $63.1 million. Following the option exercise, the Company elected 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.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position Fair Value

The following sets forth a summary of the distribution of net fair value of the Company’s derivative instruments for each counterparty in a net asset position:

Counterparty	September 30, 2013		December 31, 2012
Credit Suisse	57	%	40	%
Societe Generale	27	%	22	%
BNP Paribas	13	%	33	%
Regions	2	%	—	%
BBVA Compass	1	%	3	%
Wells Fargo	—	%	2	%
Total	100	%	100	%

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 September 30, 2013:

Period	Type of Contract	Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q4 2013	Swaps	55,000	$	4.58
FY 2014	Swaps	40,000	$	4.07
	Calls	10,000			$	5.50
FY 2015	Swaps	10,000	$	4.33

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 September 30, 2013:

Period	Type of Contract	Volumes (in Bbls/d)	Weighted Average Floor  Price ($/Bbl)		Weighted Average Ceiling  Price ($/Bbl)		Weighted Average Short Put  Price ($/Bbl)		Weighted Average Put Spread ($/Bbl)
Q4 2013	Swaps	4,000	$	94.15
	Collars	6,100	$	87.75	$	105.68
FY 2014	Swaps	5,996	$	92.36
	Collars	3,000	$	88.33	$	104.26
	Three-way collars	500	$	85.00	$	107.75	$	65.00	$	20.00
FY 2015	Swaps	3,250	$	90.64
	Collars	700	$	90.00	$	100.65
	Three-way collars	1,000	$	85.00	$	105.00	$	65.00	$	20.00
FY 2016	Three-way collars	667	$	85.00	$	104.00	$	65.00	$	20.00

Schedule Of Derivative Instruments

For the three and nine months ended September 30,2013 and 2012, the Company recorded the following related to its oil and gas derivative instruments:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Realized gain on derivative instruments, net	$	1,313		$	9,450		$	9,320		$	30,544
Unrealized loss on derivative instruments, net	(28,971		)	(24,168		)	(25,806		)	(3,569		)
Gain (loss) on derivative instruments, net	$	(27,658	)	$	(14,718	)	$	(16,486	)	$	26,975

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Summary Of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 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. The consolidated financial statements reflect all necessary adjustments, all of which were of a normal recurring nature and are in the opinion of management necessary for a fair presentation of the Company’s interim financial position, results of operations and cash flows. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The operating results for the three and nine months ended September 30,2013 are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Reclassifications

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

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. Beginning March 31, 2013, the Company classified the remaining assets and liabilities associated with the U.K. North Sea as assets of discontinued operations and liabilities of discontinued operations in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations, net of income taxes, in the consolidated statements of operations, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to assets held for sale and discontinued operations is included in “Note 3. Discontinued Operations” and “Note 10. Condensed Consolidating Financial Information.”

Use Of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating 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 timing of 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 include impairments of unproved properties, fair values of derivative instruments, stock-based compensation, collectability of receivables, disputed claims, interpretation of 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, 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 September 30, 2013 and December 31, 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 8. Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments.

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 costs centers established on a country-by-country basis. Internal costs, including payroll and stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized and totaled $3.8 million and $2.5 million for the three months ended September 30,2013 and 2012, respectively, and $10.1 million and $9.5 million for the nine months ended September 30,2013 and 2012, 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 $20.01 and $19.76 for the three months ended September 30,2013 and 2012, respectively, and $19.59 and $17.21 for the nine months ended September 30,2013 and 2012, 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 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 capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved leasehold within the next five years and exploratory wells in progress within the next year. Individually insignificant costs of unevaluated properties 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 $7.5 million and $5.9 million for the three months ended September 30,2013 and 2012, respectively, and $21.8 million and $18.0 million for the nine months ended September 30,2013 and 2012, respectively. Interest is capitalized 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 oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. On February 22, 2013, the Company closed on 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 gain in “net income (loss) from discontinued operations, net of income taxes” in the consolidated statements of operations. Other than the sale of Carrizo UK noted above, the Company has not had any sales of oil and gas properties that significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center through September 30, 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 market 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

Deferred financing costs 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, net of amounts capitalized using the effective interest method over the terms of the debt securities or credit facility.

Financial Instruments

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 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 9. Fair Value Measurements.”

Asset Retirement Obligations

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells and restore the surface after the reserves have been depleted. The asset retirement obligation is recognized as a liability at its fair value when the well is drilled with an associated increase in oil and gas property costs. Asset retirement obligations require estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligations are discounted using a credit-adjusted risk-free interest rate which is accreted to their expected settlement values over the estimated productive lives of the oil and gas properties. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in estimated costs to plug and abandon wells and restore the surface and changes in the estimated remaining lives of the oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement, which is included in proved oil and gas property costs. On an interim basis, the Company reassesses the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

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

Revenue Recognition

Oil and gas revenues are recognized when the products are 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 for oil and gas revenues whereby revenue is recognized for all oil and gas 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 oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production and as of September 30, 2013 and December 31, 2012, the Company did not have any material production imbalances.

Derivative Instruments

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are recognized at their balance sheet date fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with a portion of its forecasted oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized 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 operations. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty and subject to master netting agreements.

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 8. Derivative Instruments” for further discussion of the Company’s derivative instruments.

Stock-Based Compensation

Stock-Based Compensation

The Company grants 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 for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Stock Appreciation Rights	$	6,752		$	1,536		$	10,691		$	226
Restricted Stock Awards and Units	5,232			4,598			13,551			13,179
	11,984			6,134			24,242			13,405
Less: amounts capitalized	(2,112		)	(1,043		)	(4,904		)	(2,783		)
Total Stock-Based Compensation Expense	$	9,872		$	5,091		$	19,338		$	10,622
Income Tax Benefit	$	(3,627	)	$	(1,937	)	$	(7,097	)	$	(4,042	)

Stock Options and SARs. For stock options and SARs that the Company expects to settle in 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 expects to settle 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 other long-term 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 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.

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

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments by taxing jurisdiction. If the Company concludes that it is more likely than not that some portion or all of the 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 (Loss) From Continuing Operations Per Common Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
	(In thousands, except per share amounts)
Net income (loss) from continuing operations	$	5,712	$	(1,945	)	$	44,073	$	34,414
Basic weighted average common shares outstanding	40,386		39,634			40,083		39,559
Effect of dilutive instruments	541		—			518		433
Diluted weighted average common shares outstanding	40,927		39,634			40,601		39,992
Net income (loss) from continuing operations per common share
Basic	$	0.14	$	(0.05	)	$	1.10	$	0.87
Diluted	$	0.14	$	(0.05	)	$	1.09	$	0.86

Basic net income (loss) 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 (loss) from continuing operations per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock awards and units, stock options, SARs expected to be settled in common stock, warrants and convertible debt. The Company excludes shares related to restricted stock awards, units and stock options from the calculation of diluted weighted average shares outstanding when the grant date prices are greater than the average market prices of the common shares for the period as the effect would be antidilutive to the computation. The shares excluded for the three and nine months ended September 30, 2013 and nine months ended September 30, 2012 were not significant. The Company did not include 402,750 shares in the calculation of dilutive shares for the three months ended September 30, 2012 due to the net loss reported in the period. 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 three and nine months ended September 30,2013 or 2012, because the conversion price was in excess of the market price of the common stock for those periods.

Recently Adopted Accounting Pronouncements

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.

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Net cash provided by operating activities - continuing operations	$ 310,253	$ 176,639
Net cash used in investing activities - continuing operations	(503,401)	(436,220)
Net cash provided by financing activities - continuing operations	17,439	247,069
Net cash provided by (used in) discontinued operations	128,823	(1,312)
Net increase (decrease) in cash and cash equivalents	(46,886)	(13,824)
CASH AND CASH EQUIVALENTS, beginning of period	52,614	28,112
CASH AND CASH EQUIVALENTS, end of period	5,728	14,288
Parent Company [Member]
Net cash provided by operating activities - continuing operations	(22,222)	31,974
Net cash used in investing activities - continuing operations	(170,725)	(306,682)
Net cash provided by financing activities - continuing operations	17,439	264,344
Net cash provided by (used in) discontinued operations	129,342
Net increase (decrease) in cash and cash equivalents	(46,166)	(10,364)
CASH AND CASH EQUIVALENTS, beginning of period	51,894	19,134
CASH AND CASH EQUIVALENTS, end of period	5,728	8,770
Combined Guarantor Subsidiaries [Member]
Net cash provided by operating activities - continuing operations	332,475	144,665
Net cash used in investing activities - continuing operations	(601,936)	(379,182)
Net cash provided by financing activities - continuing operations	269,260	232,369
Net cash provided by (used in) discontinued operations	0	0
Net increase (decrease) in cash and cash equivalents	(201)	(2,148)
CASH AND CASH EQUIVALENTS, beginning of period	201	7,263
CASH AND CASH EQUIVALENTS, end of period	0	5,115
Combined Non-Guarantor Subsidiaries [Member]
Net cash provided by operating activities - continuing operations	0	0
Net cash used in investing activities - continuing operations	(1,624)	0
Net cash provided by financing activities - continuing operations	1,624	0
Net cash provided by (used in) discontinued operations	(519)	(1,312)
Net increase (decrease) in cash and cash equivalents	(519)	(1,312)
CASH AND CASH EQUIVALENTS, beginning of period	519	1,715
CASH AND CASH EQUIVALENTS, end of period	0	403
Eliminations [Member]
Net cash provided by operating activities - continuing operations	0	0
Net cash used in investing activities - continuing operations	270,884	249,644
Net cash provided by financing activities - continuing operations	(270,884)	(249,644)
Net cash provided by (used in) discontinued operations	0	0
Net increase (decrease) in cash and cash equivalents	0	0
CASH AND CASH EQUIVALENTS, beginning of period	0	0
CASH AND CASH EQUIVALENTS, end of period	$ 0	$ 0

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Derivative Instruments (Narrative) (Details)	Sep. 30, 2013
Derivatives, Fair Value [Line Items]
Current Long-Term Derivative Instrument Strategy	60 months

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Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended			9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]	Sep. 30, 2013 Stock Options And SARs [Member]	Sep. 30, 2013 Stock Options [Member]	Sep. 30, 2013 Stock Appreciation Rights (SARs) [Member] Minimum [Member]	Sep. 30, 2013 Stock Appreciation Rights (SARs) [Member] Maximum [Member]	Sep. 30, 2013 Restricted Stock Awards And Units [Member] Minimum [Member]	Sep. 30, 2013 Restricted Stock Awards And Units [Member] Maximum [Member]	Sep. 30, 2013 Restricted Stock Granted To Contractors [Member]	Dec. 27, 2012 Carrizo United Kingdom [Member]
Summary Of Significant Accounting Policies [Line Items]
shares excluded from the calculation of dilutive shares		402,750
Internal costs capitalized, Oil and Gas Producing Activities	$ 3,800,000	$ 2,500,000	$ 10,100,000	$ 9,500,000
Percentage of non-operating working interest and overriding royalty interests															15.00%
Allowance for doubtful accounts	600,000		600,000		1,400,000
Average DD&A Per Boe (in USD per BOE)	20.01	19.76	19.59	17.21
Oil and Gas, Exploratory Period			5 years
Capitalized interest	7,485,000	5,917,000	21,791,000	17,951,000
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	$ 0	$ 0	$ 37,294,000	$ 0
Reserves discount factor			10.00%
Estimated useful life, years						5 years	10 years
Vesting period, in years								3 years				1 year	3 years	3 years
Expiration period after date of grant, in years									10 years	4 years	7 years

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Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2013

Condensed Consolidating Financial Information [Abstract]

Schedule Of Condensed Consolidating Balance Sheets

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

	September 30, 2013
	Parent Company		Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,799,935	$	182,326	$	—	$	(1,845,096	)	$	137,165
Property and equipment, net	652		1,877,367		1,624		21,429			1,901,072
Investments in subsidiaries	61,297		—		—		(61,297		)	—
Other assets	51,136		—		—		(17,378		)	33,758
Total assets	$	1,913,020	$	2,059,693	$	1,624	$	(1,902,342	)	$	2,071,995
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	234,737	$	1,952,129	$	1,624	$	(1,845,096	)	$	343,394
Current liabilities of discontinued operations	10,670		—		—		—			10,670
Long-term liabilities	993,043		46,267		—		(7,199		)	1,032,111
Long-term liabilities of discontinued operations	17,742		—		—		—			17,742
Shareholders’ equity (deficit)	656,828		61,297		—		(50,047		)	668,078
Total liabilities and shareholders’ equity	$	1,913,020	$	2,059,693	$	1,624	$	(1,902,342	)	$	2,071,995

	December 31, 2012
	Parent Company		Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(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
Investments 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 (deficit)	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

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	For the Three Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	2,428		$	141,901		$	—	$	—		$	144,329
Cost and expenses	20,994			74,640			—		92			95,726
Operating income (loss)	(18,566		)	67,261			—		(92		)	48,603
Other income (expense), net	(36,314		)	(4,718		)	—		—			(41,032		)
Income (loss) from continuing operations before income taxes	(54,880		)	62,543			—		(92		)	7,571
Income tax (expense) benefit	19,208			(21,784		)	—		717			(1,859		)
Equity in income (loss) of subsidiaries	40,759			—			—		(40,759		)	—
Net income (loss) from continuing operations	5,087			40,759			—		(40,134		)	5,712
Net income from discontinued operations, net of income taxes	(1,191		)	—			—		—			(1,191		)
Net income (loss)	$	3,896		$	40,759		$	—	$	(40,134	)	$	4,521

	For the Three Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	4,459		$	91,738		$	—	$	—		$	96,197
Cost and expenses	15,256			56,135			—		488			71,879
Operating income (loss)	(10,797		)	35,603			—		(488		)	24,318
Other income (expense), net	(16,407		)	(10,448		)	—		—			(26,855		)
Income (loss) from continuing operations before income taxes	(27,204		)	25,155			—		(488		)	(2,537		)
Income tax (expense) benefit	9,531			(8,796		)	—		(143		)	592
Equity in income (loss) of subsidiaries	17,374			—			—		(17,374		)	—
Net income (loss) from continuing operations	(299		)	16,359			—		(18,005		)	(1,945		)
Net income from discontinued operations, net of income taxes	—			—			1,015		—			1,015
Net income (loss)	$	(299	)	$	16,359		$	1,015	$	(18,005	)	$	(930	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	For the Nine Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	6,075		$	384,379		$	—	$	—		$	390,454
Cost and expenses	57,427			204,204			—		139			261,770
Operating income (loss)	(51,352		)	180,175			—		(139		)	128,684
Other income (expense), net	(41,995		)	(16,763		)	—		—			(58,758		)
Income (loss) from continuing operations before income taxes	(93,347		)	163,412			—		(139		)	69,926
Income tax (expense) benefit	32,671			(57,194		)	—		(1,330		)	(25,853		)
Equity in income (loss) of subsidiaries	106,218			—			—		(106,218		)	—
Net income (loss) from continuing operations	45,542			106,218			—		(107,687		)	44,073
Net income from discontinued operations, net of income taxes	23,599			—			—		—			23,599
Net income (loss)	$	69,141		$	106,218		$	—	$	(107,687	)	$	67,672

	For the Nine Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	15,856		$	244,874		$	—	$	—		$	260,730
Cost and expenses	62,608			150,242			—		(13,624		)	199,226
Operating income (loss)	(46,752		)	94,632			—		13,624			61,504
Other income (expense), net	18,890			(25,008		)	—		—			(6,118		)
Income (loss) from continuing operations before income taxes	(27,862		)	69,624			—		13,624			55,386
Income tax (expense) benefit	9,760			(24,360		)	—		(6,372		)	(20,972		)
Equity in income (loss) of subsidiaries	47,847			—			—		(47,847		)	—
Net income (loss) from continuing operations	29,745			45,264			—		(40,595		)	34,414
Net income from discontinued operations, net of income taxes	—			—			2,583		—			2,583
Net income (loss)	$	29,745		$	45,264		$	2,583	$	(40,595	)	$	36,997

Schedule Of Condensed Consolidating Statements Of Cash Flows

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	For the Nine Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities - continuing operations	$	(22,222	)	$	332,475		$	—		$	—		$	310,253
Net cash provided by (used in) investing activities - continuing operations	(170,725		)	(601,936		)	(1,624		)	270,884			(503,401		)
Net cash provided by (used in) financing activities - continuing operations	17,439			269,260			1,624			(270,884		)	17,439
Net cash provided by (used in) discontinued operations	129,342			—			(519		)	—			128,823
Net increase (decrease) in cash and cash equivalents	(46,166		)	(201		)	(519		)	—			(46,886		)
Cash and cash equivalents, beginning of period	51,894			201			519			—			52,614
Cash and cash equivalents, end of period	$	5,728		$	—		$	—		$	—		$	5,728

	For the Nine Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities - continuing operations	$	31,974		$	144,665		$	—		$	—		$	176,639
Net cash provided by (used in) investing activities - continuing operations	(306,682		)	(379,182		)	—			249,644			(436,220		)
Net cash provided by (used in) financing activities - continuing operations	264,344			232,369			—			(249,644		)	247,069
Net cash used in discontinued operations				—			(1,312		)	—			(1,312		)
Net increase (decrease) in cash and cash equivalents	(10,364		)	(2,148		)	(1,312		)	—			(13,824		)
Cash and cash equivalents, beginning of period	19,134			7,263			1,715			—			28,112
Cash and cash equivalents, end of period	$	8,770		$	5,115		$	403		$	—		$	14,288

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets	$ 137,165	$ 206,823
Current assets held for sale	0	1,882
Assets of discontinued operations	0	0
Property and equipment, net	1,901,072	1,487,674
Investments in subsidiaries	0	0
LONG-TERM ASSETS HELD FOR SALE	0	132,626
Other assets	33,758	54,991
TOTAL ASSETS	2,071,995	1,883,996
Current liabilities	343,394	250,255
Current liabilities associated with assets held for sale	0	48,663
Liabilities of discontinued operations	10,670	0
Long-term liabilities	1,032,111	976,515
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE	0	23,547
LIABILITIES OF DISCONTINUED OPERATIONS	17,742	0
Shareholders’ equity (deficit)	668,078	585,016
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	2,071,995	1,883,996
Parent Company [Member]
Current assets	1,799,935	1,689,430
Current assets held for sale		0
Assets of discontinued operations
Property and equipment, net	652	23,041
Investments in subsidiaries	61,297	14,588
LONG-TERM ASSETS HELD FOR SALE		12,670
Other assets	51,136	46,913
TOTAL ASSETS	1,913,020	1,786,642
Current liabilities	234,737	179,221
Current liabilities associated with assets held for sale		9,880
Liabilities of discontinued operations	10,670
Long-term liabilities	993,043	973,003
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE		0
LIABILITIES OF DISCONTINUED OPERATIONS	17,742
Shareholders’ equity (deficit)	656,828	624,538
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	1,913,020	1,786,642
Combined Guarantor Subsidiaries [Member]
Current assets	182,326	130,487
Current assets held for sale		0
Assets of discontinued operations
Property and equipment, net	1,877,367	1,443,064
Investments in subsidiaries	0	0
LONG-TERM ASSETS HELD FOR SALE		0
Other assets	0	16,928
TOTAL ASSETS	2,059,693	1,590,479
Current liabilities	1,952,129	1,631,887
Current liabilities associated with assets held for sale		0
Liabilities of discontinued operations	0
Long-term liabilities	46,267	3,512
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE		0
LIABILITIES OF DISCONTINUED OPERATIONS	0
Shareholders’ equity (deficit)	61,297	(44,920)
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	2,059,693	1,590,479
Combined Non-Guarantor Subsidiaries [Member]
Current assets	0	0
Current assets held for sale		1,882
Assets of discontinued operations
Property and equipment, net	1,624	0
Investments in subsidiaries	0	0
LONG-TERM ASSETS HELD FOR SALE		119,956
Other assets	0	0
TOTAL ASSETS	1,624	121,838
Current liabilities	1,624	0
Current liabilities associated with assets held for sale		38,783
Liabilities of discontinued operations	0
Long-term liabilities	0	0
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE		23,547
LIABILITIES OF DISCONTINUED OPERATIONS	0
Shareholders’ equity (deficit)	0	59,508
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	1,624	121,838
Eliminations [Member]
Current assets	(1,845,096)	(1,613,094)
Current assets held for sale		0
Assets of discontinued operations
Property and equipment, net	21,429	21,569
Investments in subsidiaries	(61,297)	(14,588)
LONG-TERM ASSETS HELD FOR SALE		0
Other assets	(17,378)	(8,850)
TOTAL ASSETS	(1,902,342)	(1,614,963)
Current liabilities	(1,845,096)	(1,560,853)
Current liabilities associated with assets held for sale		0
Liabilities of discontinued operations	0
Long-term liabilities	(7,199)	0
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE		0
LIABILITIES OF DISCONTINUED OPERATIONS	0
Shareholders’ equity (deficit)	(50,047)	(54,110)
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ (1,902,342)	$ (1,614,963)

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Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Income Taxes [Line Items]
U.S. federal statutory corporate pretax rate	35.00%
Minimum [Member]
Income Taxes [Line Items]
Net operating loss carryforward expiration dates	2019
Maximum [Member]
Income Taxes [Line Items]
Net operating loss carryforward expiration dates	2032
United States Of America [Member]
Income Taxes [Line Items]
Operating loss carry forwards subject to expiration	$ 174.4

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Derivative Instruments (Schedule Of U.S. Natural Gas Derivative Positions) (Details) (Natural Gas Derivative Positions [Member])	Sep. 30, 2013 MMBTU
Swaps [Member] | 2013 [Member]
Derivative [Line Items]
Volume (in MMBtu/d)	55,000
Weighted Average Floor Price ($/MMBtu)	4.58
Weighted Average Ceiling Price ($/MMBtu)
Swaps [Member] | 2014 [Member]
Derivative [Line Items]
Volume (in MMBtu/d)	40,000
Weighted Average Floor Price ($/MMBtu)	4.07
Weighted Average Ceiling Price ($/MMBtu)
Swaps [Member] | 2015 [Member]
Derivative [Line Items]
Volume (in MMBtu/d)	10,000
Weighted Average Floor Price ($/MMBtu)	4.33
Weighted Average Ceiling Price ($/MMBtu)
Calls [Member] | 2014 [Member]
Derivative [Line Items]
Volume (in MMBtu/d)	10,000
Weighted Average Ceiling Price ($/MMBtu)	5.50

XML

Subsequent Events (Details) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended
	Oct. 31, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
Subsequent Event [Line Items]
Sale Price of Oil and Gas Property and Equipment		$ 248,500,000
Payments to Acquire Oil and Gas Property	73,200,000
Proceeds from sales of oil and gas properties, net	209,700,000		20,753,000	207,250,000
Potential Post-Close Proceeds From Sale Of Oil And Gas Properties	23,800,000
Fair Value Of Derivative Assets Entered Into On Behalf Of Buyer		500,000	500,000
Barnett Transaction [Member]
Subsequent Event [Line Items]
Sale Price of Oil and Gas Property and Equipment		218,000,000
East Texas Transaction [Member]
Subsequent Event [Line Items]
Sale Price of Oil and Gas Property and Equipment		$ 8,700,000

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Discontinued Operations Discontinued Operations (Statements of Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
OIL AND GAS REVENUES	$ 0	$ 0	$ 0	$ 0
General and administrative	408	56	709	68
Accretion related to asset retirement obligations	0	104	36	258
TOTAL COST AND EXPENSES	408	160	745	326
OPERATING LOSS	(408)	(160)	(745)	(326)
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	0	0	37,294	0
Discontinued Operations, Changes in Estimated Future Obligations	(1,187)	0	1,378	0
Gain (loss) on derivative instruments, net	(18)	(135)	(93)	(543)
Interest expense	0	(871)	(253)	(2,669)
Capitalized interest	0	871	253	2,669
Other income (expense), net	106	4	438	(590)
INCOME (LOSS) BEFORE INCOME TAXES	(1,507)	(291)	38,272	(1,459)
INCOME TAX (EXPENSE) BENEFIT	316	1,306	(14,673)	4,042
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$ (1,191)	$ 1,015	$ 23,599	$ 2,583

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Fair Value Measurements (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Level 2 [Member] Portion at Fair Value, Fair Value Disclosure [Member]	Dec. 31, 2012 Level 2 [Member] Portion at Fair Value, Fair Value Disclosure [Member]
Derivative Asset, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset			$ 17,679,000	$ 36,452,000
Derivative Asset, Fair Value, Gross Liability			(10,269,000)	(7,291,000)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral			7,410,000	29,161,000
Derivative Liability, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability			13,793,000	7,291,000
Derivative Liability, Fair Value, Gross Asset			10,269,000	7,291,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral			3,524,000	0
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset (Liability)			3,886,000	29,161,000
Derivative Asset (Liability), Fair Value, Gross Liability (Asset)			0	0
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net			3,886,000	29,161,000
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	$ 0	$ 0

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Offsetting Assets

	December 31, 2012
Description	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Derivative instruments	$	36,452		$	(7,291	)	$	29,161
Liabilities:
Derivative instruments	(7,291		)	7,291			—
Total	$	29,161		$	—		$	29,161

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. All items included in the tables below are Level 2 inputs within the fair value hierarchy:

	September 30, 2013
Description	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Derivative instruments	$	17,679		$	(10,269	)	$	7,410
Liabilities:
Derivative instruments	(13,793		)	10,269			(3,524		)
Total	$	3,886		$	—		$	3,886

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 September 30, 2013 and December 31, 2012.

	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
8.625% Senior Notes	$	595,649	$	647,768	$	595,151	$	645,000
7.50% Senior Notes	300,000		316,500		300,000		308,250
4.375% Convertible Senior Notes	4,425		4,436		72,657		73,842

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Net Income	$ 67,672	$ 36,997
Net income from discontinued operations, net of income taxes	(23,599)	(2,583)
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities-
Depreciation, depletion and amortization	151,232	121,459
Unrealized loss on derivative instruments, net	25,806	3,569
Accretion related to asset retirement obligations	355	280
Stock-based compensation, net of amounts capitalized	19,338	10,622
Allowance for doubtful accounts	(105)	(391)
Deferred income taxes	25,853	20,972
Amortization of debt discount and deferred financing costs, net of amounts capitalized	3,217	3,236
Other, net	1,894	2,646
Changes in operating assets and liabilities-
Accounts receivable	1,910	(71,215)
Accounts payable	38,843	31,699
Accrued liabilities	2,049	23,325
Other, net	(4,212)	(3,977)
Net cash provided by operating activities - continuing operations	310,253	176,639
Net cash used in operating activities - discontinued operations	(400)	(402)
Net cash provided by operating activities	309,853	176,237
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures - oil and gas properties	(571,069)	(575,971)
Capital expenditures - other property and equipment	(687)	(3,689)
Increase (decrease) in capital expenditure payables and accruals	23,020	(14,583)
Proceeds from sales of oil and gas properties, net	20,753	207,250
Advances to operators	1,537	(852)
Advances for joint operations	26,459	(42,986)
Other, net	(3,414)	(5,389)
Net cash used in investing activities - continuing operations	(503,401)	(436,220)
Net cash provided by (used in) investing activities - discontinued operations	126,223	(29,442)
Net cash used in investing activities	(377,178)	(465,662)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings and issuances	437,000	1,036,000
Debt repayments	(419,325)	(783,000)
Payments of costs associated with revolving credit facility and debt issuance	(1,075)	(6,005)
Proceeds from stock options exercised	839	74
Net cash provided by financing activities - continuing operations	17,439	247,069
Net cash provided by financing activities - discontinued operations	3,000	28,532
Net cash provided by financing activities	20,439	275,601
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(46,886)	(13,824)
CASH AND CASH EQUIVALENTS, beginning of period	52,614	28,112
CASH AND CASH EQUIVALENTS, end of period	$ 5,728	$ 14,288

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Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 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. The consolidated financial statements reflect all necessary adjustments, all of which were of a normal recurring nature and are in the opinion of management necessary for a fair presentation of the Company’s interim financial position, results of operations and cash flows. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The operating results for the three and nine months ended September 30,2013 are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

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. Beginning March 31, 2013, the Company classified the remaining assets and liabilities associated with the U.K. North Sea as assets of discontinued operations and liabilities of discontinued operations in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations, net of income taxes, in the consolidated statements of operations, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to assets held for sale and discontinued operations is included in “Note 3. Discontinued Operations” and “Note 10. Condensed Consolidating Financial Information.”

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating 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 timing of 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 include impairments of unproved properties, fair values of derivative instruments, stock-based compensation, collectability of receivables, disputed claims, interpretation of 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, 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 September 30, 2013 and December 31, 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 8. Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments.

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 costs centers established on a country-by-country basis. Internal costs, including payroll and stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized and totaled $3.8 million and $2.5 million for the three months ended September 30,2013 and 2012, respectively, and $10.1 million and $9.5 million for the nine months ended September 30,2013 and 2012, 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 $20.01 and $19.76 for the three months ended September 30,2013 and 2012, respectively, and $19.59 and $17.21 for the nine months ended September 30,2013 and 2012, 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 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 capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved leasehold within the next five years and exploratory wells in progress within the next year. Individually insignificant costs of unevaluated properties 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 $7.5 million and $5.9 million for the three months ended September 30,2013 and 2012, respectively, and $21.8 million and $18.0 million for the nine months ended September 30,2013 and 2012, respectively. Interest is capitalized 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 oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. On February 22, 2013, the Company closed on 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 gain in “net income (loss) from discontinued operations, net of income taxes” in the consolidated statements of operations. Other than the sale of Carrizo UK noted above, the Company has not had any sales of oil and gas properties that significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center through September 30, 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 market 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 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, net of amounts capitalized 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 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 9. Fair Value Measurements.”

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells and restore the surface after the reserves have been depleted. The asset retirement obligation is recognized as a liability at its fair value when the well is drilled with an associated increase in oil and gas property costs. Asset retirement obligations require estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligations are discounted using a credit-adjusted risk-free interest rate which is accreted to their expected settlement values over the estimated productive lives of the oil and gas properties. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in estimated costs to plug and abandon wells and restore the surface and changes in the estimated remaining lives of the oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement, which is included in proved oil and gas property costs. On an interim basis, the Company reassesses the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

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 the products are 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 for oil and gas revenues whereby revenue is recognized for all oil and gas 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 oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production and as of September 30, 2013 and December 31, 2012, the Company did not have any material production imbalances.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are recognized at their balance sheet date fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with a portion of its forecasted oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized 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 operations. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty and subject to master netting agreements.

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 8. Derivative Instruments” for further discussion of the Company’s derivative instruments.

Stock-Based Compensation

The Company grants 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 for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Stock Appreciation Rights	$	6,752		$	1,536		$	10,691		$	226
Restricted Stock Awards and Units	5,232			4,598			13,551			13,179
	11,984			6,134			24,242			13,405
Less: amounts capitalized	(2,112		)	(1,043		)	(4,904		)	(2,783		)
Total Stock-Based Compensation Expense	$	9,872		$	5,091		$	19,338		$	10,622
Income Tax Benefit	$	(3,627	)	$	(1,937	)	$	(7,097	)	$	(4,042	)

Stock Options and SARs. For stock options and SARs that the Company expects to settle in 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 expects to settle 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 other long-term 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 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.

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

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments by taxing jurisdiction. If the Company concludes that it is more likely than not that some portion or all of the 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) From Continuing Operations Per Common Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
	(In thousands, except per share amounts)
Net income (loss) from continuing operations	$	5,712	$	(1,945	)	$	44,073	$	34,414
Basic weighted average common shares outstanding	40,386		39,634			40,083		39,559
Effect of dilutive instruments	541		—			518		433
Diluted weighted average common shares outstanding	40,927		39,634			40,601		39,992
Net income (loss) from continuing operations per common share
Basic	$	0.14	$	(0.05	)	$	1.10	$	0.87
Diluted	$	0.14	$	(0.05	)	$	1.09	$	0.86

Basic net income (loss) 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 (loss) from continuing operations per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock awards and units, stock options, SARs expected to be settled in common stock, warrants and convertible debt. The Company excludes shares related to restricted stock awards, units and stock options from the calculation of diluted weighted average shares outstanding when the grant date prices are greater than the average market prices of the common shares for the period as the effect would be antidilutive to the computation. The shares excluded for the three and nine months ended September 30, 2013 and nine months ended September 30, 2012 were not significant. The Company did not include 402,750 shares in the calculation of dilutive shares for the three months ended September 30, 2012 due to the net loss reported in the period. 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 three and nine months ended September 30,2013 or 2012, 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.

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

5. Income Taxes

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates are applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate will impact future income tax expense. Income tax expense differs from 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:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
	(In thousands)
Income tax expense (benefit) at the statutory rate	$	2,650		$	(889	)	$	24,474	$	19,384
State income taxes, net of U.S. federal income tax effect	(791		)	334			1,275		1,421
Other, net	—			(37		)	104		167
Income tax expense (benefit)	$	1,859		$	(592	)	$	25,853	$	20,972

As of September 30, 2013, the Company had U.S. income tax loss carryforwards of approximately $174.4 million. The U.S. loss carryforwards expire between 2019 and 2032 if not utilized in earlier periods. The realization of the deferred tax assets related to the U.S. loss carryforwards is dependent on the Company’s ability to generate sufficient future taxable income, which the Company expects to be able to generate within the applicable carryforward periods. Accordingly, the Company believes that it is more likely than not that its deferred tax assets related to the U.S. loss carryforwards will be fully realized.

At September 30, 2013, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

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Discontinued Operations

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

3. Discontinued Operations

On February 22, 2013, the Company closed on the sale of Carrizo UK, and all of its interest in the Huntington Field discovery, including a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) for an agreed-upon price of $184.0 million, including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding under Carrizo UK's senior secured multicurrency credit facility as of the closing date.

During the third quarter, the Company received the remaining $6.8 million of deferred consideration, which was previously presented in assets of discontinued operations in the consolidated balance sheets. The liabilities of discontinued operations of $28.4 million relate to an accrual for estimated future obligations related to the sale. See “Note 2. Summary of Significant Accounting Policies—Use of Estimates” for further discussion of estimates and assumptions that may affect the reported amounts of assets and liabilities related to the sale of Carrizo UK.

The following table summarizes the amounts included in net income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of operations for the three and nine months ended September 30,2013 and 2012:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
OIL AND GAS REVENUES	$	—		$	—		$	—		$	—
COSTS AND EXPENSES
General and administrative	408			56			709			68
Accretion related to asset retirement obligations	—			104			36			258
TOTAL COST AND EXPENSES	408			160			745			326
OPERATING LOSS	(408		)	(160		)	(745		)	(326		)
OTHER INCOME AND EXPENSES
Gain on sale of discontinued operations	—			—			37,294			—
Decrease (increase) in estimated future obligations	(1,187		)	—			1,378			—
Gain (loss) on derivative instruments, net	(18		)	(135		)	(93		)	(543		)
Interest expense	—			(871		)	(253		)	(2,669		)
Capitalized interest	—			871			253			2,669
Other income (expense), net	106			4			438			(590		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	(1,507		)	(291		)	38,272			(1,459		)
INCOME TAX (EXPENSE) BENEFIT	316			1,306			(14,673		)	4,042
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(1,191	)	$	1,015		$	23,599		$	2,583

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. deferred income tax (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.

Foreign Currency

The U.S. dollar was the functional currency for the Company’s operations in the U.K. North Sea. Transaction gains or losses that occurred due to the realization of assets and the settlement of liabilities denominated in a currency other than the functional currency were recorded as Other income (expense), net.

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Derivative Instruments (Schedule Of U.S. Crude Oil Derivative Positions) (Details) (U.S. Crude Oil Derivative Positions [Member])	Sep. 30, 2013
2013 [Member]
Derivative [Line Items]
Weighted Average Ceiling Price ($/Bbls)
2014 [Member]
Derivative [Line Items]
Weighted Average Ceiling Price ($/Bbls)
Swaps [Member] | 2013 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	4,000
Weighted Average Floor Price ($/Bbls)	94.15
Swaps [Member] | 2014 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	5,996
Weighted Average Floor Price ($/Bbls)	92.36
Swaps [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	3,250
Weighted Average Floor Price ($/Bbls)	90.64
Weighted Average Ceiling Price ($/Bbls)
Collars [Member] | 2013 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	6,100
Weighted Average Floor Price ($/Bbls)	87.75
Weighted Average Ceiling Price ($/Bbls)	105.68
Collars [Member] | 2014 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	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/d)	700
Weighted Average Floor Price ($/Bbls)	90.00
Weighted Average Ceiling Price ($/Bbls)	100.65
Three-way Collars [Member] | 2014 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	500
Weighted Average Floor Price ($/Bbls)	85.00
Weighted Average Ceiling Price ($/Bbls)	107.75
Weighted Average Short Put Price ($/Bbl)	65.00
Weighted Average Put Spread ($/Bbl)	20.00
Three-way Collars [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	1,000
Weighted Average Floor Price ($/Bbls)	85.00
Weighted Average Ceiling Price ($/Bbls)	105.00
Weighted Average Short Put Price ($/Bbl)	65.00
Weighted Average Put Spread ($/Bbl)	20.00
Three-way Collars [Member] | 2016 [Member]
Derivative [Line Items]
Volumes (in Bbls/d)	667
Weighted Average Floor Price ($/Bbls)	85.00
Weighted Average Ceiling Price ($/Bbls)	104.00
Weighted Average Short Put Price ($/Bbl)	65.00
Weighted Average Put Spread ($/Bbl)	20.00

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Summary Of Significant Accounting Policies (Schedule Of Stock-Based Compensation Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 11,984	$ 6,134	$ 24,242	$ 13,405
Less: amounts capitalized	(2,112)	(1,043)	(4,904)	(2,783)
Total Stock-Based Compensation Expense	9,872	5,091	19,338	10,622
Income Tax Benefit	(3,627)	(1,937)	(7,097)	(4,042)
Stock Options And SARs [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	6,752	1,536	10,691	226
Restricted Stock Awards And Units [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share-based Compensation Expense	$ 5,232	$ 4,598	$ 13,551	$ 13,179

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Property And Equipment, Net (Narrative) (Details) (USD $)	1 Months Ended	9 Months Ended		0 Months Ended
	Oct. 31, 2013	Sep. 30, 2013	Sep. 30, 2012	Jan. 15, 2013 Corporate Joint Venture [Member] Utica [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 209,700,000	$ 20,753,000	$ 207,250,000
Joint venture, percentage of ownership increase (decrease)				40.00%
Payments to acquire interest in joint venture				$ 63,100,000

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Debt (Schedule Of Debt) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
LONG-TERM DEBT, NET OF DEBT DISCOUNT	$ 987,074	$ 967,808
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility amount outstanding	87,000	0
Eight Point Six Two Five Percent Senior Notes [Member]
Debt Instrument [Line Items]
Senior Notes	600,000	600,000
Unamortized discount	(4,351)	(4,849)
Seven Point Five Percent 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)
Convertible Senior Notes	$ 4,425	$ 73,750

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Condensed Consolidating Financial Information (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Condensed Consolidating Financial Information [Line Items]
Voting interest of the subsidiary owned by the registrant	100.00%
Eight Point Six Two Five Percent Senior Notes [Member]
Condensed Consolidating Financial Information [Line Items]
Senior Notes	$ 600,000	$ 600,000
Seven Point Five Percent Senior Notes [Member]
Condensed Consolidating Financial Information [Line Items]
Senior Notes	$ 300,000	$ 300,000

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 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	90,000
Common stock, shares issued (in shares)	40,879	40,165
Common stock, shares outstanding (in shares)	40,879	40,165

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Derivative Instruments

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

8. Derivative Instruments

The Company uses various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital expenditure plan. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at termination or expiration. The Company's current strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 60 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations for the period in which the changes occur.

The fair value of derivative instruments at September 30, 2013 and December 31, 2012 was a net asset of $3.9 million and $29.2 million, respectively. The following sets forth a summary of the distribution of net fair value of the Company’s derivative instruments for each counterparty in a net asset position:

Counterparty	September 30, 2013		December 31, 2012
Credit Suisse	57	%	40	%
Societe Generale	27	%	22	%
BNP Paribas	13	%	33	%
Regions	2	%	—	%
BBVA Compass	1	%	3	%
Wells Fargo	—	%	2	%
Total	100	%	100	%

Master netting agreements are in place with each of these counterparties. Because the counterparties are investment grade financial institutions, 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. Because Credit Suisse, Societe Generale, Regions, BBVA Compass and Wells Fargo are lenders in the Company’s revolving credit facility, the Company is not required to post collateral with respect to derivative instruments in a net liability position with these counterparties as the contracts are secured by the revolving credit facility.

The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of September 30, 2013:

Period	Type of Contract	Volumes (in Bbls/d)	Weighted Average Floor  Price ($/Bbl)		Weighted Average Ceiling  Price ($/Bbl)		Weighted Average Short Put  Price ($/Bbl)		Weighted Average Put Spread ($/Bbl)
Q4 2013	Swaps	4,000	$	94.15
	Collars	6,100	$	87.75	$	105.68
FY 2014	Swaps	5,996	$	92.36
	Collars	3,000	$	88.33	$	104.26
	Three-way collars	500	$	85.00	$	107.75	$	65.00	$	20.00
FY 2015	Swaps	3,250	$	90.64
	Collars	700	$	90.00	$	100.65
	Three-way collars	1,000	$	85.00	$	105.00	$	65.00	$	20.00
FY 2016	Three-way collars	667	$	85.00	$	104.00	$	65.00	$	20.00

The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of September 30, 2013:

Period	Type of Contract	Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q4 2013	Swaps	55,000	$	4.58
FY 2014	Swaps	40,000	$	4.07
	Calls	10,000			$	5.50
FY 2015	Swaps	10,000	$	4.33

For the three and nine months ended September 30,2013 and 2012, the Company recorded the following related to its oil and gas derivative instruments:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Realized gain on derivative instruments, net	$	1,313		$	9,450		$	9,320		$	30,544
Unrealized loss on derivative instruments, net	(28,971		)	(24,168		)	(25,806		)	(3,569		)
Gain (loss) on derivative instruments, net	$	(27,658	)	$	(14,718	)	$	(16,486	)	$	26,975

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Consolidated Statements Of Operations (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement [Abstract]
Stock-based compensation expense	$ 9,872	$ 5,091	$ 19,338	$ 10,622

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 5,728	$ 52,095
Accounts receivable, net	114,901	112,821
Accounts receivable - related party	5,930	9,815
Current assets held for sale	0	1,882
Assets of discontinued operations	0	0
Fair value of derivative instruments	0	23,981
Prepaids and other current assets	5,397	8,111
Total current assets	137,165	208,705
Oil and gas properties using the full cost method of accounting
Proved oil and gas properties, net	1,495,981	1,152,548
Unproved properties, not being amortized	395,291	323,688
Other property and equipment, net	9,800	11,438
TOTAL PROPERTY AND EQUIPMENT, NET	1,901,072	1,487,674
LONG-TERM ASSETS HELD FOR SALE	0	132,626
DEFERRED FINANCING COSTS, NET	21,728	23,914
FAIR VALUE OF DERIVATIVE INSTRUMENTS	7,410	5,180
DEFERRED INCOME TAXES	0	21,272
OTHER ASSETS	4,620	4,625
TOTAL ASSETS	2,071,995	1,883,996
CURRENT LIABILITIES
Accounts payable, trade	77,876	44,775
Revenue and royalties payable	103,250	82,300
Accrued drilling costs	57,161	60,729
Accrued interest	24,847	18,012
Other accrued liabilities	45,732	28,445
Advances for joint operations	34,528	8,069
Deferred income taxes	0	7,925
Current liabilities associated with assets held for sale	0	48,663
Liabilities of discontinued operations	10,670	0
Total current liabilities	354,064	298,918
LONG-TERM DEBT, NET OF DEBT DISCOUNT	987,074	967,808
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE	0	23,547
LIABILITIES OF DISCONTINUED OPERATIONS	17,742	0
ASSET RETIREMENT OBLIGATIONS	6,341	4,489
DEFERRED INCOME TAXES	32,796	0
OTHER LIABILITIES	5,900	4,218
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value (90,000 shares authorized, 40,879 and 40,165 shares issued and outstanding as of September 30, 2013 and December 31, 2012, respectively)	409	402
Additional paid-in capital	682,479	667,096
Accumulated deficit	(14,810)	(82,482)
Total shareholders’ equity	668,078	585,016
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 2,071,995	$ 1,883,996

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Summary Of Significant Accounting Policies (Schedule Of Supplemental Net Income Per Common Share) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accounting Policies [Abstract]
Net income (loss) from continuing operations	$ 5,712	$ (1,945)	$ 44,073	$ 34,414
Basic weighted average common shares outstanding	40,386	39,634	40,083	39,559
Effect of dilutive instruments	541	0	518	433
Diluted weighted average common shares outstanding	40,927	39,634	40,601	39,992
Net income (loss) from continuing operations per common share
Net income from continuing operations - basic (in dollars per share)	$ 0.14	$ (0.05)	$ 1.10	$ 0.87
Net income from continuing operations - diluted (in dollars per share)	$ 0.14	$ (0.05)	$ 1.09	$ 0.86

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Debt (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Schedule Of Debt

Long-term debt consisted of the following at September 30, 2013 and December 31, 2012:

	September 30, 2013			December 31, 2012
	(In thousands)
8.625% Senior Notes	$	600,000		$	600,000
Unamortized discount for 8.625% Senior Notes	(4,351		)	(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	87,000			—
	$	987,074		$	967,808

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Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Eight Point Six Two Five Percent Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Senior Notes	$ 600,000	$ 600,000
Seven Point Five Percent 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, Fair Value Disclosure [Member] | Eight Point Six Two Five Percent Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Fair value of Senior Notes	647,768	645,000
Portion at Fair Value, Fair Value Disclosure [Member] | Seven Point Five Percent Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Fair value of Senior Notes	316,500	308,250
Portion at Fair Value, Fair Value Disclosure [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	4,436	73,842
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Eight Point Six Two Five Percent Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Senior Notes	595,649	595,151
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Seven Point Five Percent 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

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Derivative Instruments (Schedule of Fair Value Holding Percentage) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Derivative Instruments, Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 3.9	$ 29.2
Derivative Instrument Holding Percentage	100.00%	100.00%
Credit Suisse [Member]
Derivative Instruments, Fair Value [Line Items]
Derivative Instrument Holding Percentage	57.00%	40.00%
Wells Fargo [Member]
Derivative Instruments, Fair Value [Line Items]
Derivative Instrument Holding Percentage	0.00%	2.00%
Bnp Paribas [Member]
Derivative Instruments, Fair Value [Line Items]
Derivative Instrument Holding Percentage	13.00%	33.00%
Regions [Member]
Derivative Instruments, Fair Value [Line Items]
Derivative Instrument Holding Percentage	2.00%	0.00%
Societe Generale [Member]
Derivative Instruments, Fair Value [Line Items]
Derivative Instrument Holding Percentage	27.00%	22.00%
Bbva Compass [Member]
Derivative Instruments, Fair Value [Line Items]
Derivative Instrument Holding Percentage	1.00%	3.00%

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the statutory rate	$ 2,650	$ (889)	$ 24,474	$ 19,384
State income taxes, net of U.S. federal income tax effect	(791)	334	1,275	1,421
Other, net	0	(37)	104	167
Income tax expense (benefit)	$ 1,859	$ (592)	$ 25,853	$ 20,972

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Debt (Narrative) (Details) (USD $)	3 Months Ended				3 Months Ended
	Sep. 30, 2013	Oct. 09, 2013	Sep. 30, 2013 Senior Secured Revolving Credit Facility [Member]	Dec. 31, 2012 Senior Secured Revolving Credit Facility [Member]	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]	Sep. 30, 2013 Convertible Senior Notes [Member]	Dec. 31, 2012 Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Convertible debt							$ 4,425,000	$ 73,750,000
Repurchase Price, Percentage Of Principal Amount							100.00%
Debt Instrument, Unamortized Discount							0	1,093,000
Debt instrument interest rate							4.375%
Redemption price, percentage of principal amount							100.00%
Line of credit facility, maximum borrowing capacity	750,000,000	1,000,000,000
Line of credit facility, current borrowing capacity	530,000,000	470,000,000
Ratio of total debt to EBITDA	2.44					4.00
Current ratio	1.73				1.00
Ratio of senior debt to EBITDA	0.2					2.5
Ratio of EBITDA to interest expense	5.02				2.5
Line of credit facility amount outstanding			87,000,000	0
Debt, Weighted Average Interest Rate	3.44%
Letters of credit outstanding amount			$ 900,000

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

7. 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.

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Discontinued Operations (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended			0 Months Ended	3 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Feb. 22, 2013 Carrizo United Kingdom [Member]	Sep. 30, 2013 Carrizo United Kingdom [Member]	Dec. 27, 2012 Carrizo United Kingdom [Member]	Feb. 22, 2013 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 and overriding royalty interests								15.00%
Sale price						$ 184,000,000
Line of credit facility amount outstanding									55,000,000
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	0	0	37,294,000	0
Liabilities of disposal group, including discontinued operation	28,400,000		28,400,000
Disposal Group, deferred consideration received							6,800,000
Assets of discontinued operations	$ 0		$ 0		$ 0

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Derivative Instruments (Schedule Of Derivative Instruments) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Realized gain (loss) on derivative instruments, net	$ 1,313	$ 9,450	$ 9,320	$ 30,544
Unrealized gain (loss) on derivative instruments, net	(28,971)	(24,168)	(25,806)	(3,569)
Gain (loss) on derivative instruments, net	$ (27,658)	$ (14,718)	$ (16,486)	$ 26,975

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Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2013

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

10. 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 September 30, 2013 and December 31, 2012, and for the three and nine months ended September 30,2013 and 2012 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

	September 30, 2013
	Parent Company		Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,799,935	$	182,326	$	—	$	(1,845,096	)	$	137,165
Property and equipment, net	652		1,877,367		1,624		21,429			1,901,072
Investments in subsidiaries	61,297		—		—		(61,297		)	—
Other assets	51,136		—		—		(17,378		)	33,758
Total assets	$	1,913,020	$	2,059,693	$	1,624	$	(1,902,342	)	$	2,071,995
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	234,737	$	1,952,129	$	1,624	$	(1,845,096	)	$	343,394
Current liabilities of discontinued operations	10,670		—		—		—			10,670
Long-term liabilities	993,043		46,267		—		(7,199		)	1,032,111
Long-term liabilities of discontinued operations	17,742		—		—		—			17,742
Shareholders’ equity (deficit)	656,828		61,297		—		(50,047		)	668,078
Total liabilities and shareholders’ equity	$	1,913,020	$	2,059,693	$	1,624	$	(1,902,342	)	$	2,071,995

	December 31, 2012
	Parent Company		Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(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
Investments 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 (deficit)	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 Three Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	2,428		$	141,901		$	—	$	—		$	144,329
Cost and expenses	20,994			74,640			—		92			95,726
Operating income (loss)	(18,566		)	67,261			—		(92		)	48,603
Other income (expense), net	(36,314		)	(4,718		)	—		—			(41,032		)
Income (loss) from continuing operations before income taxes	(54,880		)	62,543			—		(92		)	7,571
Income tax (expense) benefit	19,208			(21,784		)	—		717			(1,859		)
Equity in income (loss) of subsidiaries	40,759			—			—		(40,759		)	—
Net income (loss) from continuing operations	5,087			40,759			—		(40,134		)	5,712
Net income from discontinued operations, net of income taxes	(1,191		)	—			—		—			(1,191		)
Net income (loss)	$	3,896		$	40,759		$	—	$	(40,134	)	$	4,521

	For the Three Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	4,459		$	91,738		$	—	$	—		$	96,197
Cost and expenses	15,256			56,135			—		488			71,879
Operating income (loss)	(10,797		)	35,603			—		(488		)	24,318
Other income (expense), net	(16,407		)	(10,448		)	—		—			(26,855		)
Income (loss) from continuing operations before income taxes	(27,204		)	25,155			—		(488		)	(2,537		)
Income tax (expense) benefit	9,531			(8,796		)	—		(143		)	592
Equity in income (loss) of subsidiaries	17,374			—			—		(17,374		)	—
Net income (loss) from continuing operations	(299		)	16,359			—		(18,005		)	(1,945		)
Net income from discontinued operations, net of income taxes	—			—			1,015		—			1,015
Net income (loss)	$	(299	)	$	16,359		$	1,015	$	(18,005	)	$	(930	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	For the Nine Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	6,075		$	384,379		$	—	$	—		$	390,454
Cost and expenses	57,427			204,204			—		139			261,770
Operating income (loss)	(51,352		)	180,175			—		(139		)	128,684
Other income (expense), net	(41,995		)	(16,763		)	—		—			(58,758		)
Income (loss) from continuing operations before income taxes	(93,347		)	163,412			—		(139		)	69,926
Income tax (expense) benefit	32,671			(57,194		)	—		(1,330		)	(25,853		)
Equity in income (loss) of subsidiaries	106,218			—			—		(106,218		)	—
Net income (loss) from continuing operations	45,542			106,218			—		(107,687		)	44,073
Net income from discontinued operations, net of income taxes	23,599			—			—		—			23,599
Net income (loss)	$	69,141		$	106,218		$	—	$	(107,687	)	$	67,672

	For the Nine Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	15,856		$	244,874		$	—	$	—		$	260,730
Cost and expenses	62,608			150,242			—		(13,624		)	199,226
Operating income (loss)	(46,752		)	94,632			—		13,624			61,504
Other income (expense), net	18,890			(25,008		)	—		—			(6,118		)
Income (loss) from continuing operations before income taxes	(27,862		)	69,624			—		13,624			55,386
Income tax (expense) benefit	9,760			(24,360		)	—		(6,372		)	(20,972		)
Equity in income (loss) of subsidiaries	47,847			—			—		(47,847		)	—
Net income (loss) from continuing operations	29,745			45,264			—		(40,595		)	34,414
Net income from discontinued operations, net of income taxes	—			—			2,583		—			2,583
Net income (loss)	$	29,745		$	45,264		$	2,583	$	(40,595	)	$	36,997

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	For the Nine Months Ended September 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities - continuing operations	$	(22,222	)	$	332,475		$	—		$	—		$	310,253
Net cash provided by (used in) investing activities - continuing operations	(170,725		)	(601,936		)	(1,624		)	270,884			(503,401		)
Net cash provided by (used in) financing activities - continuing operations	17,439			269,260			1,624			(270,884		)	17,439
Net cash provided by (used in) discontinued operations	129,342			—			(519		)	—			128,823
Net increase (decrease) in cash and cash equivalents	(46,166		)	(201		)	(519		)	—			(46,886		)
Cash and cash equivalents, beginning of period	51,894			201			519			—			52,614
Cash and cash equivalents, end of period	$	5,728		$	—		$	—		$	—		$	5,728

	For the Nine Months Ended September 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities - continuing operations	$	31,974		$	144,665		$	—		$	—		$	176,639
Net cash provided by (used in) investing activities - continuing operations	(306,682		)	(379,182		)	—			249,644			(436,220		)
Net cash provided by (used in) financing activities - continuing operations	264,344			232,369			—			(249,644		)	247,069
Net cash used in discontinued operations				—			(1,312		)	—			(1,312		)
Net increase (decrease) in cash and cash equivalents	(10,364		)	(2,148		)	(1,312		)	—			(13,824		)
Cash and cash equivalents, beginning of period	19,134			7,263			1,715			—			28,112
Cash and cash equivalents, end of period	$	8,770		$	5,115		$	403		$	—		$	14,288

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Debt

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Debt

6. Long-Term Debt

Long-term debt consisted of the following at September 30, 2013 and December 31, 2012:

	September 30, 2013			December 31, 2012
	(In thousands)
8.625% Senior Notes	$	600,000		$	600,000
Unamortized discount for 8.625% Senior Notes	(4,351		)	(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	87,000			—
	$	987,074		$	967,808

Convertible Senior Notes

On June 3, 2013, the Company completed a required tender offer to repurchase the 4.375% convertible senior notes due 2028, with $4.4 million aggregate principal amount of convertible senior notes remaining outstanding. The holders of the Company's remaining $4.4 million aggregate principal amount of convertible senior notes may require it to repurchase the remaining 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 also 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 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 revolving credit facility).

On October 9, 2013, a fourth amendment to the senior secured revolving credit facility (the "Fourth Amendment") 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 substantially all of the Company's Barnett Shale assets, 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.

As of September 30, 2013, the Company was 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 to 1.00; (2) a Current Ratio of not less than 1.00 to 1.00; (3) a ratio of Senior Debt to EBITDA of not more than 2.50 to 1.00; and (4) a ratio of EBITDA to Interest Expense of not less than 2.50 to 1.00 (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the credit agreement governing the revolving credit facility). As of September 30, 2013, the ratio of Total Debt to EBITDA was 2.44 to 1.00, the Current Ratio was 1.73 to 1.00, the ratio of Senior Debt to EBITDA was 0.20 to 1.00 and the ratio of EBITDA to Interest Expense was 5.02 to 1.00. Total Debt and Senior Debt, as defined in the credit agreement governing the revolving credit facility, is net of cash and cash equivalents. 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.

At September 30, 2013, the Company had $87.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 3.44%. At September 30, 2013, the Company also had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Upon closing of the Company's Barnett Shale assets on October 31, 2013, the borrowing base was automatically reduced to $470.0 million. Future availability under the borrowing base is subject to the terms and covenants of 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.

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Nature Of Operations

9 Months Ended

Sep. 30, 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, the Barnett Shale in North Texas, and the Utica Shale in Ohio.

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Oil and gas revenues	$ 144,329	$ 96,197	$ 390,454	$ 260,730
Cost and expenses	95,726	71,879	261,770	199,226
OPERATING INCOME	48,603	24,318	128,684	61,504
Other income (expense), net	(41,032)	(26,855)	(58,758)	(6,118)
Income (loss) from continuing operations before income taxes	7,571	(2,537)	69,926	55,386
Income tax (expense) benefit	(1,859)	592	(25,853)	(20,972)
Equity in income (loss) of subsidiaries	0	0	0	0
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	5,712	(1,945)	44,073	34,414
Net income from discontinued operations, net of income taxes	(1,191)	1,015	23,599	2,583
NET INCOME (LOSS)	4,521	(930)	67,672	36,997
Parent Company [Member]
Oil and gas revenues	2,428	4,459	6,075	15,856
Cost and expenses	20,994	15,256	57,427	62,608
OPERATING INCOME	(18,566)	(10,797)	(51,352)	(46,752)
Other income (expense), net	(36,314)	(16,407)	(41,995)	18,890
Income (loss) from continuing operations before income taxes	(54,880)	(27,204)	(93,347)	(27,862)
Income tax (expense) benefit	19,208	9,531	32,671	9,760
Equity in income (loss) of subsidiaries	40,759	17,374	106,218	47,847
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	5,087	(299)	45,542	29,745
Net income from discontinued operations, net of income taxes	(1,191)	0	23,599	0
NET INCOME (LOSS)	3,896	(299)	69,141	29,745
Combined Guarantor Subsidiaries [Member]
Oil and gas revenues	141,901	91,738	384,379	244,874
Cost and expenses	74,640	56,135	204,204	150,242
OPERATING INCOME	67,261	35,603	180,175	94,632
Other income (expense), net	(4,718)	(10,448)	(16,763)	(25,008)
Income (loss) from continuing operations before income taxes	62,543	25,155	163,412	69,624
Income tax (expense) benefit	(21,784)	(8,796)	(57,194)	(24,360)
Equity in income (loss) of subsidiaries	0	0	0	0
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	40,759	16,359	106,218	45,264
Net income from discontinued operations, net of income taxes	0	0	0	0
NET INCOME (LOSS)	40,759	16,359	106,218	45,264
Combined Non-Guarantor Subsidiaries [Member]
Oil and gas revenues	0	0	0	0
Cost and expenses	0	0	0	0
OPERATING INCOME	0	0	0	0
Other income (expense), net	0	0	0	0
Income (loss) from continuing operations before income taxes	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Equity in income (loss) of subsidiaries	0	0	0	0
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	0	0	0	0
Net income from discontinued operations, net of income taxes	0	1,015	0	2,583
NET INCOME (LOSS)	0	1,015	0	2,583
Eliminations [Member]
Oil and gas revenues	0	0	0	0
Cost and expenses	92	488	139	(13,624)
OPERATING INCOME	(92)	(488)	(139)	13,624
Other income (expense), net	0	0	0	0
Income (loss) from continuing operations before income taxes	(92)	(488)	(139)	13,624
Income tax (expense) benefit	717	(143)	(1,330)	(6,372)
Equity in income (loss) of subsidiaries	(40,759)	(17,374)	(106,218)	(47,847)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(40,134)	(18,005)	(107,687)	(40,595)
Net income from discontinued operations, net of income taxes	0	0	0	0
NET INCOME (LOSS)	$ (40,134)	$ (18,005)	$ (107,687)	$ (40,595)

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Property And Equipment, Net (Schedule Of Property And Equipment) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	$ 2,207,220	$ 1,713,827
Accumulated depreciation, depletion and amortization	(711,239)	(561,279)
Proved oil and gas properties, net	1,495,981	1,152,548
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	302,391	238,833
Exploratory wells in progress	41,926	43,803
Capitalized interest	50,974	41,052
Total unproved properties, not being amortized	395,291	323,688
Other property and equipment	16,323	17,079
Accumulated depreciation	(6,523)	(5,641)
Other property and equipment, net	9,800	11,438
TOTAL PROPERTY AND EQUIPMENT, NET	$ 1,901,072	$ 1,487,674

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Summary Of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Schedule Of Stock-Based Compensation Expense

The Company recognized the following stock-based compensation expense for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Stock Appreciation Rights	$	6,752		$	1,536		$	10,691		$	226
Restricted Stock Awards and Units	5,232			4,598			13,551			13,179
	11,984			6,134			24,242			13,405
Less: amounts capitalized	(2,112		)	(1,043		)	(4,904		)	(2,783		)
Total Stock-Based Compensation Expense	$	9,872		$	5,091		$	19,338		$	10,622
Income Tax Benefit	$	(3,627	)	$	(1,937	)	$	(7,097	)	$	(4,042	)

Schedule Of Supplemental Net Income Per Common Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
	(In thousands, except per share amounts)
Net income (loss) from continuing operations	$	5,712	$	(1,945	)	$	44,073	$	34,414
Basic weighted average common shares outstanding	40,386		39,634			40,083		39,559
Effect of dilutive instruments	541		—			518		433
Diluted weighted average common shares outstanding	40,927		39,634			40,601		39,992
Net income (loss) from continuing operations per common share
Basic	$	0.14	$	(0.05	)	$	1.10	$	0.87
Diluted	$	0.14	$	(0.05	)	$	1.09	$	0.86

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Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

9. 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 September 30, 2013 and December 31, 2012. All items included in the tables below are Level 2 inputs within the fair value hierarchy:

	September 30, 2013
Description	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Derivative instruments	$	17,679		$	(10,269	)	$	7,410
Liabilities:
Derivative instruments	(13,793		)	10,269			(3,524		)
Total	$	3,886		$	—		$	3,886

	December 31, 2012
Description	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Derivative instruments	$	36,452		$	(7,291	)	$	29,161
Liabilities:
Derivative instruments	(7,291		)	7,291			—
Total	$	29,161		$	—		$	29,161

The fair values of the Company’s derivative instruments are based on a third-party 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 assets and liabilities for derivative instruments included in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to master netting agreements. The derivative instruments assets are classified in fair value of derivative instruments and the derivative instruments liabilities are classified in other accrued liabilities on the consolidated balance sheets. The Company had no transfers in or out of Levels 1 or 2 for the nine months ended September 30,2013 or 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 September 30, 2013 and December 31, 2012.

	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
8.625% Senior Notes	$	595,649	$	647,768	$	595,151	$	645,000
7.50% Senior Notes	300,000		316,500		300,000		308,250
4.375% Convertible Senior Notes	4,425		4,436		72,657		73,842

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Schedule Of Effective Income Tax Rate Reconciliation

Income tax expense differs from 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:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
	(In thousands)
Income tax expense (benefit) at the statutory rate	$	2,650		$	(889	)	$	24,474	$	19,384
State income taxes, net of U.S. federal income tax effect	(791		)	334			1,275		1,421
Other, net	—			(37		)	104		167
Income tax expense (benefit)	$	1,859		$	(592	)	$	25,853	$	20,972

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 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 operations for the three and nine months ended September 30,2013 and 2012:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
OIL AND GAS REVENUES	$	—		$	—		$	—		$	—
COSTS AND EXPENSES
General and administrative	408			56			709			68
Accretion related to asset retirement obligations	—			104			36			258
TOTAL COST AND EXPENSES	408			160			745			326
OPERATING LOSS	(408		)	(160		)	(745		)	(326		)
OTHER INCOME AND EXPENSES
Gain on sale of discontinued operations	—			—			37,294			—
Decrease (increase) in estimated future obligations	(1,187		)	—			1,378			—
Gain (loss) on derivative instruments, net	(18		)	(135		)	(93		)	(543		)
Interest expense	—			(871		)	(253		)	(2,669		)
Capitalized interest	—			871			253			2,669
Other income (expense), net	106			4			438			(590		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	(1,507		)	(291		)	38,272			(1,459		)
INCOME TAX (EXPENSE) BENEFIT	316			1,306			(14,673		)	4,042
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(1,191	)	$	1,015		$	23,599		$	2,583

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Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
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		40,921,395

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Property And Equipment, Net (Tables)

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Schedule Of Property And Equipment

At September 30, 2013 and December 31, 2012, property and equipment, net consisted of the following:

	September 30, 2013			December 31, 2012
	(In thousands)
Proved oil and gas properties	$	2,207,220		$	1,713,827
Accumulated depreciation, depletion and amortization	(711,239		)	(561,279		)
Proved oil and gas properties, net	1,495,981			1,152,548
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	302,391			238,833
Exploratory wells in progress	41,926			43,803
Capitalized interest	50,974			41,052
Total unproved properties, not being amortized	395,291			323,688
Other property and equipment	16,323			17,079
Accumulated depreciation	(6,523		)	(5,641		)
Other property and equipment, net	9,800			11,438
Total property and equipment, net	$	1,901,072		$	1,487,674