Edgar Filing: CARRIZO OIL & GAS INC

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Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

CRZO 6.30.13 10Q

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 June 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

_________________________________________________

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):

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 July 31, 2013 was 40,869,047.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013

INDEX



		PAGE
PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements	2
	Consolidated Balance Sheets (Unaudited) as of June 30, 2013 and December 31, 2012	2
	Consolidated Statements of Income (Unaudited) for the three and six months ended June 30, 2013 and 2012	3
	Consolidated Statements of Cash Flows (Unaudited) for the six months ended June 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	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Mine Safety Disclosures	31
Item 5.	Other Information	31
Item 6.	Exhibits	32
SIGNATURES		33

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (Unaudited)

	June 30, 2013			December 31, 2012
	(In thousands, except per share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,847		$	52,095
Accounts receivable, net	119,851			112,821
Accounts receivable - related party	7,717			9,815
Current assets held for sale	—			1,882
Assets of discontinued operations	6,875			—
Fair value of derivative instruments	14,091			23,981
Prepaids and other current assets	7,562			8,111
Total current assets	159,943			208,705
PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full cost method of accounting
Proved oil and gas properties, net	1,429,801			1,152,548
Unproved properties, not being amortized	360,534			323,688
Other property and equipment, net	12,527			11,438
TOTAL PROPERTY AND EQUIPMENT, NET	1,802,862			1,487,674
LONG-TERM ASSETS HELD FOR SALE	—			132,626
DEFERRED FINANCING COSTS, NET	22,739			23,914
FAIR VALUE OF DERIVATIVE INSTRUMENTS	18,235			5,180
DEFERRED INCOME TAXES	—			21,272
OTHER ASSETS	6,518			4,625
TOTAL ASSETS	$	2,010,297		$	1,883,996
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	96,428		$	44,775
Revenue and royalties payable	124,111			82,300
Accrued drilling costs	66,193			60,729
Accrued interest	17,502			18,012
Other accrued liabilities	36,435			28,445
Advances for joint operations	18,414			8,069
Deferred income taxes	1,284			7,925
Current liabilities associated with assets held for sale	—			48,663
Liabilities of discontinued operations	9,936			—
Total current liabilities	370,303			298,918
LONG-TERM DEBT, NET OF DEBT DISCOUNT	927,904			967,808
LONG-TERM LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE	—			23,547
LIABILITIES OF DISCONTINUED OPERATIONS	17,999			—
ASSET RETIREMENT OBLIGATIONS	6,499			4,489
DEFERRED INCOME TAXES	24,763			—
OTHER LIABILITIES	4,577			4,218
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value (90,000 shares authorized, 40,864 and 40,165 shares issued and outstanding at June 30, 2013 and December 31, 2012, respectively)	409			402
Additional paid-in capital	677,173			667,096
Accumulated deficit	(19,330		)	(82,482		)
Total shareholders’ equity	658,252			585,016
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,010,297		$	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 INCOME

(Unaudited)



	For The Three Months Ended June 30,						For The Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands, except per share amounts)
OIL AND GAS REVENUES	$	134,224		$	83,818		$	246,125		$	164,533
COSTS AND EXPENSES
Lease operating	11,797			7,031			21,992			15,454
Production tax	4,584			3,128			9,097			6,227
Ad valorem tax	2,863			2,296			4,723			5,911
Depreciation, depletion and amortization	50,408			43,380			95,998			74,941
General and administrative (inclusive of stock-based compensation expense of $2,983 and $1,516 for the three months ended June 30, 2013 and 2012, respectively, and $9,466 and $5,532 for the six months ended June 30, 2013 and 2012, respectively)	17,834			13,085			34,007			24,620
Accretion related to asset retirement obligations	120			92			227			194
TOTAL COSTS AND EXPENSES	87,606			69,012			166,044			127,347
OPERATING INCOME	46,618			14,806			80,081			37,186
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net	25,726			37,890			11,172			41,693
Interest expense	(21,519		)	(16,767		)	(43,271		)	(33,224		)
Capitalized interest	7,530			6,011			14,306			12,034
Other income, net	27			22			67			234
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	58,382			41,962			62,355			57,923
INCOME TAX EXPENSE	(22,545		)	(16,279		)	(23,994		)	(21,564		)
NET INCOME FROM CONTINUING OPERATIONS	$	35,837		$	25,683		$	38,361		$	36,359
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	1,132			2,821			24,790			1,568
NET INCOME	$	36,969		$	28,504		$	63,151		$	37,927

NET INCOME PER COMMON SHARE - BASIC
Net income from continuing operations	$	0.89		$	0.65		$	0.96		$	0.92
Net income from discontinued operations	0.03			0.07			0.62			0.04
Net income	$	0.92		$	0.72		$	1.58		$	0.96

NET INCOME PER COMMON SHARE - DILUTED
Net income from continuing operations	$	0.88		$	0.64		$	0.95		$	0.91
Net income from discontinued operations	0.03			0.07			0.61			0.04
Net income	$	0.91		$	0.71		$	1.56		$	0.95

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	40,078			39,596			39,928			39,520
Diluted	40,610			40,042			40,469			39,987

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 Six Months Ended June 30,
	2013			2012
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	63,151		$	37,927
Net income from discontinued operations, net of income taxes	(24,790		)	(1,568		)
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities-
Depreciation, depletion and amortization	95,998			74,941
Unrealized (gain) loss on derivative instruments, net	(3,166		)	(20,598		)
Accretion related to asset retirement obligations	227			194
Stock-based compensation, net of amounts capitalized	9,466			5,532
Allowance for doubtful accounts	7			41
Deferred income taxes	23,994			21,564
Amortization of debt discount and deferred financing costs, net of amounts capitalized	2,386			2,091
Other, net	244			1,793
Changes in operating assets and liabilities-
Accounts receivable	(4,938		)	(31,279		)
Accounts payable	73,771			50,896
Accrued liabilities	(19,035		)	6,366
Other, net	(3,593		)	(2,592		)
Net cash provided by operating activities - continuing operations	213,722			145,308
Net cash used in operating activities - discontinued operations	(80		)	(209		)
Net cash provided by operating activities	213,642			145,099
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures - oil and gas properties	(409,928		)	(385,611		)
Capital expenditures - other property and equipment	(1,196		)	(3,388		)
Increase in capital expenditure payables and accruals	37,346			619
Proceeds from sales of U.S. oil and gas properties, net	10,681			190,892
Advances to operators	282			(431		)
Advances for joint operations	10,345			(33,342		)
Other, net	403			(2,655		)
Net cash used in investing activities - continuing operations	(352,067		)	(233,916		)
Net cash provided by (used in) investing activities - discontinued operations	128,179			(19,824		)
Net cash used in investing activities	(223,888		)	(253,740		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings and issuances	165,000			520,412
Debt repayments	(206,325		)	(438,000		)
Payments of costs associated with revolving credit facility and debt issuance	(962		)	(239		)
Proceeds from stock options exercised	766			6
Net cash provided by (used in) financing activities - continuing operations	(41,521		)	82,179
Net cash provided by financing activities - discontinued operations	3,000			19,119
Net cash provided by (used in) financing activities	(38,521		)	101,298
NET DECREASE IN CASH AND CASH EQUIVALENTS	(48,767		)	(7,343		)
CASH AND CASH EQUIVALENTS, beginning of period	52,614			28,112
CASH AND CASH EQUIVALENTS, end of period	$	3,847		$	20,769

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 six months ended June 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 income, 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 our 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 June 30, 2013 and December 31, 2012, the Company’s allowance for doubtful accounts was $0.7 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 $4.2 million and $4.1 million for the three months ended June 30, 2013 and 2012, respectively, and $6.3 million and $7.5 million for the six months ended June 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 oil and natural gas liquids to gas equivalents at the ratio of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, 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 $19.65 and $18.13 for the three months ended June 30, 2013 and 2012, respectively, and $19.36 and $15.93 for the six months ended June 30, 2013 and 2012, respectively.

Unproved properties, which are 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 $6.0 million for the three months ended June 30, 2013 and 2012, respectively, and $14.3 million and $12.0 million for the six months ended June 30, 2013 and 2012, respectively. Interest is capitalized on the average

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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 from discontinued operations, net of income taxes” in the consolidated statements of income. 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 June 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 properties not subject to amortization, 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 average quoted 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 the debt securities and costs associated with revolving credit facilities. 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 facilities.

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, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. 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 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 over the estimated productive lives of the oil and gas properties to their expected settlement values. 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 changes in estimated timing of oil and gas property retirement. 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 oil and gas property costs. On an interim basis, the Company reassesses

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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 June 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 income. 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 income. 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 income:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
Stock Appreciation Rights	$	7		$	(2,975	)	$	3,939		$	(1,309	)
Restricted Stock Awards and Units	4,462			5,476			8,319			8,581
	4,469			2,501			12,258			7,272
Less: amounts capitalized	(1,486		)	(985		)	(2,792		)	(1,740		)
Total Stock-Based Compensation Expense	$	2,983		$	1,516		$	9,466		$	5,532
Income Tax Benefit	$	(1,107	)	$	(562	)	$	(3,470	)	$	(2,052	)

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 From Continuing Operations Per Common Share

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands, except per share amounts)
Net income from continuing operations	$	35,837	$	25,683	$	38,361	$	36,359
Basic weighted average common shares outstanding	40,078		39,596		39,928		39,520
Effect of dilutive instruments	532		446		541		467
Diluted weighted average common shares outstanding	40,610		40,042		40,469		39,987
Net income from continuing operations per common share
Basic	$	0.89	$	0.65	$	0.96	$	0.92
Diluted	$	0.88	$	0.64	$	0.95	$	0.91

Basic net income from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted net income from continuing operations per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock awards and units, stock options, SARs 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 periods ending June 30, 2013 and 2012 were not significant. Shares of common stock subject to issuance upon the conversion of the Company's convertible senior notes did not have an effect on the calculation of dilutive shares for the three and six months ended June 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. We adopted this new disclosure requirement effective January 1, 2013. The adoption did not have a material effect on our consolidated financial statements.

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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.

The assets of discontinued operations of $6.9 million primarily relate to the remaining deferred consideration which the Company expects to receive during 2013. The liabilities of discontinued operations of $27.9 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 from discontinued operations, net of income taxes presented in the consolidated statements of income for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
OIL AND GAS REVENUES	$	—		$	—		$	—		$	—
COSTS AND EXPENSES
General and administrative	296			9			301			12
Accretion related to asset retirement obligations	—			78			36			154
TOTAL COST AND EXPENSES	296			87			337			166
OPERATING LOSS	(296		)	(87		)	(337		)	(166		)
OTHER INCOME AND EXPENSES
Gain on sale of discontinued operations	—			—			37,294			—
Decrease in estimated future obligations	2,565			—			2,565			—
Gain (loss) on derivative instruments, net	(31		)	357			(75		)	(408		)
Interest expense	—			(919		)	(253		)	(1,798		)
Capitalized interest	—			1,798			253			1,798
Other income (expense), net	308			203			332			(594		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	2,546			1,352			39,779			(1,168		)
INCOME TAX (EXPENSE) BENEFIT	(1,414		)	1,469			(14,989		)	2,736
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	1,132		$	2,821		$	24,790		$	1,568

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 sheet.

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



	June 30, 2013			December 31, 2012
	(In thousands)
Proved oil and gas properties	$	2,086,461		$	1,713,827
Accumulated depreciation, depletion and amortization	(656,660		)	(561,279		)
Proved oil and gas properties, net	1,429,801			1,152,548
Unproved properties, not being amortized
Unevaluated leasehold costs	284,362			238,833
Exploratory wells in progress	30,936			43,803
Capitalized interest	45,236			41,052
Total unproved properties, not being amortized	360,534			323,688
Other property and equipment	18,975			17,079
Accumulated depreciation	(6,448		)	(5,641		)
Other property and equipment, net	12,527			11,438
Total property and equipment, net	$	1,802,862		$	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 has elected to acquire additional properties on a 50/50 basis with Avista. The Company's right to receive distributions associated with the properties owned by ACP III through its B Units in ACP III terminated upon the consummation of the Company’s January 15, 2013 option to increase its interest in the Avista Utica joint venture properties.

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
Income tax expense at the statutory rate	$	20,427	$	14,687	$	21,824	$	20,273
State income taxes, net of U.S. federal income tax benefit	2,049		843		2,063		1,087
Other, net	69		749		107		204
Income tax expense	$	22,545	$	16,279	$	23,994	$	21,564

As of June 30, 2013, the Company had U.S. income tax loss carryforwards of approximately $179.6 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

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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 June 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 June 30, 2013 and December 31, 2012:



	June 30, 2013			December 31, 2012
	(In thousands)
8.625% Senior Notes	$	600,000		$	600,000
Unamortized discount for 8.625% Senior Notes	(4,521		)	(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	28,000			—
	$	927,904		$	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, at par plus accrued but unpaid interest to but excluding June 1, 2013, for aggregate consideration of $69.3 million (approximately 94% of the convertible senior notes outstanding prior to the tender offer). Each holder received $1,000 for each $1,000 principal amount of convertible senior notes repurchased in the tender offer. Due to the Company repurchasing the convertible senior notes on June 1, 2013, which is the date the semi-annual interest payment was due and after the record date, the Company paid only the regular interest payment as there was no accrued or unpaid interest due as part of the repurchase price. As of June 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.

Senior Secured Revolving Credit Facility

The Company is party to a senior secured revolving credit facility with Wells Fargo Bank, National Association as the administrative agent. The revolving credit facility provides for a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the senior credit agreement governing the revolving credit facility) and (ii) $750.0 million. The revolving credit facility matures on January 27, 2016. 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 subsidiaries (other than Monument Exploration LLC, Carrizo UK Bardolph Ltd, and Carrizo (Permian) LLC).

As a result of the Spring 2013 borrowing base redetermination, effective April 29, 2013, the borrowing base was increased to $530.0 million from $365.0 million after considering the addition of proved reserves as a result of the Company’s successful ongoing drilling program. 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 the Fall of 2013. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement governing the revolving credit facility.

The Company is subject to certain covenants under the terms of the revolving credit facility which include the maintenance of the following financial covenants: (1) a ratio of Total Debt to EBITDA of not more than 4.00 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). At June 30, 2013, the ratio of Total Debt to EBITDA was 2.50 to 1.00, the Current Ratio was 1.83 to 1.00, the ratio of Senior Debt to EBITDA was 0.07 to 1.00 and the ratio of EBITDA to Interest Expense was 5.31 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 of the Company. 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 June 30, 2013, the Company had $28.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 2.19%. At June 30, 2013, the Company also had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Future availability under the $530.0 million borrowing base is subject to

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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.

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 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, expiration or exchanged for physical delivery contracts. The Company’s current long-term 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 income for the period in which the changes occur.

The fair value of derivative instruments at June 30, 2013 and December 31, 2012 was a net asset of $32.3 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:



Counterparty	June 30, 2013		December 31, 2012
Credit Suisse	38	%	40	%
Societe Generale	35	%	22	%
Wells Fargo	13	%	2	%
BNP Paribas	13	%	33	%
BBVA Compass	1	%	3	%
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 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, BBVA Compass, Wells Fargo, and Societe Generale 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. BNP Paribas may require the Company to post collateral with respect to derivative instruments in a net liability position. The Company had no derivative instruments in a net liability position with any counterparty at June 30, 2013 and December 31, 2012.

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



Period	Volumes (in MMBtu)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
2013	10,120,000	$	4.58	$	4.58
2014	18,250,000	$	4.07	$	4.36
2015	3,650,000	$	4.33	$	4.33

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



Period	Volumes (in Bbls)	Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
2013	1,766,400	$	90.17	$	100.87
2014	3,375,500	$	90.59	$	96.99
2015	1,806,750	$	89.41	$	94.96
2016	244,000	$	85.00	$	104.00

In connection with the crude oil derivative instruments above, the Company has entered into protective put spreads. For example, during 2014, at market prices below the short put price of $65.00, the floor price becomes the market price plus the put spread of $20.00 on 182,500 of the 3,375,500 Bbls and the remaining 3,193,000 Bbls would have a floor price of $90.59.



Period	Volumes (in Bbls)	Weighted Average Short Put Price ($/Bbl)		Weighted Average Put Spread ($/Bbl)
2014	182,500	$	65.00	$	20.00
2015	365,000	$	65.00	$	20.00
2016	244,000	$	65.00	$	20.00

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
Realized gain (loss) on derivative instruments, net	$	2,291	$	9,962	$	8,006	$	21,095
Unrealized gain (loss) on derivative instruments, net	23,435		27,928		3,166		20,598
Gain (loss) on derivative instruments, net	$	25,726	$	37,890	$	11,172	$	41,693

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



	June 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	$	37,768		$	(5,442	)	$	32,326
Liabilities:
Derivative instruments	(5,442		)	5,442			—
Total	$	32,326		$	—		$	32,326



	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, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. 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 Company had no transfers in or out of Levels 1 or 2 for the six months ended June 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 June 30, 2013 and December 31, 2012.



	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
8.625% Senior Notes	$	595,479	$	640,140	$	595,151	$	645,000
7.50% Senior Notes	300,000		312,000		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

In November 2010 and November 2011, the Company and certain of the Company’s wholly-owned subsidiaries issued in private placements $400.0 million and $200.0 million, respectively, aggregate principal amount of the Company’s 8.625% Senior Notes. Certain, but not all, of the Company’s wholly-owned subsidiaries have issued full, unconditional and joint and several guarantees of the 8.625% Senior Notes and may guarantee future issuances of debt securities. In June 2011 and February 2012, the Company completed the exchange of registered 8.625% Senior Notes for any and all of its unregistered $400.0 million and $200.0 million aggregate principal amount of 8.625% Senior Notes, respectively. In September 2012, the Company and certain of the Company’s wholly-owned subsidiaries issued in a public offering, $300.0 million aggregate principal amount of the Company’s 7.50% Senior Notes.

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 June 30, 2013 and December 31, 2012, and for the three and six months ended June 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



	June 30, 2013
	Parent Company		Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,779,723	$	153,382	$	—	$	(1,780,037	)	$	153,068
Assets of discontinued operations	6,875		—		—		—			6,875
Property and equipment, net	469		1,780,872		—		21,521			1,802,862
Investments in subsidiaries	20,539		—		—		(20,539		)	—
Other assets	52,108		—		—		(4,616		)	47,492
Total assets	$	1,859,714	$	1,934,254	$	—	$	(1,783,671	)	$	2,010,297

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	250,191	$	1,890,213	$	—	$	(1,780,037	)	$	360,367
Current liabilities of discontinued operations	9,936		—		—		—			9,936
Long-term liabilities	933,960		23,502		—		6,281			963,743
Long-term liabilities of discontinued operations	17,999		—		—		—			17,999
Shareholders’ equity (deficit)	647,628		20,539		—		(9,915		)	658,252
Total liabilities and shareholders’ equity	$	1,859,714	$	1,934,254	$	—	$	(1,783,671	)	$	2,010,297



	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 June 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	2,086		$	132,138		$	—	$	—		$	134,224
Cost and expenses	19,315			68,474			—		(183		)	87,606
Operating income (loss)	(17,229		)	63,664			—		183			46,618
Other income (expense), net	17,544			(5,780		)	—		—			11,764
Income (loss) from continuing operations before income taxes	315			57,884			—		183			58,382
Income tax (expense) benefit	(110		)	(20,365		)	—		(2,070		)	(22,545		)
Equity in income (loss) of subsidiaries	37,519			—			—		(37,519		)	—
Net income (loss) from continuing operations	37,724			37,519			—		(39,406		)	35,837
Net income from discontinued operations, net of income taxes	1,132			—			—		—			1,132
Net income (loss)	$	38,856		$	37,519		$	—	$	(39,406	)	$	36,969



	For the Three Months Ended June 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	4,608		$	79,210		$	—	$	—		$	83,818
Cost and expenses	32,806			51,429			—		(15,223		)	69,012
Operating income (loss)	(28,198		)	27,781			—		15,223			14,806
Other income (expense), net	34,170			(7,014		)	—		—			27,156
Income (loss) from continuing operations before income taxes	5,972			20,767			—		15,223			41,962
Income tax (expense) benefit	(2,041		)	(7,268		)	—		(6,970		)	(16,279		)
Equity in income (loss) of subsidiaries	16,320			—			—		(16,320		)	—
Net income (loss) from continuing operations	20,251			13,499			—		(8,067		)	25,683
Net income from discontinued operations, net of income taxes	—			—			2,821		—			2,821
Net income (loss)	$	20,251		$	13,499		$	2,821	$	(8,067	)	$	28,504

-18-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME



	For the Six Months Ended June 30, 2013
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	3,647		$	242,478		$	—	$	—		$	246,125
Cost and expenses	36,433			129,564			—		47			166,044
Operating income (loss)	(32,786		)	112,914			—		(47		)	80,081
Other income (expense), net	(5,681		)	(12,045		)	—		—			(17,726		)
Income (loss) from continuing operations before income taxes	(38,467		)	100,869			—		(47		)	62,355
Income tax (expense) benefit	13,463			(35,410		)	—		(2,047		)	(23,994		)
Equity in income (loss) of subsidiaries	65,459			—			—		(65,459		)	—
Net income (loss) from continuing operations	40,455			65,459			—		(67,553		)	38,361
Net income from discontinued operations, net of income taxes	24,790			—			—		—			24,790
Net income (loss)	$	65,245		$	65,459		$	—	$	(67,553	)	$	63,151



	For the Six Months Ended June 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Oil and gas revenues	$	11,397		$	153,136		$	—	$	—		$	164,533
Cost and expenses	47,352			94,107			—		(14,112		)	127,347
Operating income (loss)	(35,955		)	59,029			—		14,112			37,186
Other income (expense), net	35,297			(14,560		)	—		—			20,737
Income (loss) from continuing operations before income taxes	(658		)	44,469			—		14,112			57,923
Income tax (expense) benefit	229			(15,564		)	—		(6,229		)	(21,564		)
Equity in income (loss) of subsidiaries	30,473			—			—		(30,473		)	—
Net income (loss) from continuing operations	30,044			28,905			—		(22,590		)	36,359
Net income from discontinued operations, net of income taxes	—			—			1,568		—			1,568
Net income (loss)	$	30,044		$	28,905		$	1,568	$	(22,590	)	$	37,927

-19-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS



	For the Six Months Ended June 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	$	4,319		$	209,403		$	—		$	—		$	213,722
Net cash provided by (used in) investing activities - continuing operations	(142,476		)	(428,774		)	—			219,183			(352,067		)
Net cash provided by (used in) financing activities - continuing operations	(41,521		)	219,183			—			(219,183		)	(41,521		)
Net cash provided by (used in) discontinued operations	131,618			—			(519		)	—			131,099
Net increase (decrease) in cash and cash equivalents	(48,060		)	(188		)	(519		)	—			(48,767		)
Cash and cash equivalents, beginning of period	51,894			201			519			—			52,614
Cash and cash equivalents, end of period	$	3,834		$	13		$	—		$	—		$	3,847



	For the Six Months Ended June 30, 2012
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities - continuing operations	$	43,723		$	101,585		$	—		$	—		$	145,308
Net cash provided by (used in) investing activities - continuing operations	(165,100		)	(188,743		)	—			119,927			(233,916		)
Net cash provided by (used in) financing activities - continuing operations	108,986			93,120			—			(119,927		)	82,179
Net cash used in discontinued operations	(18		)	—			(896		)	—			(914		)
Net increase (decrease) in cash and cash equivalents	(12,409		)	5,962			(896		)	—			(7,343		)
Cash and cash equivalents, beginning of period	19,134			7,263			1,715			—			28,112
Cash and cash equivalents, end of period	$	6,725		$	13,225		$	819		$	—		$	20,769

-20-

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 second quarter 2013 included oil and gas revenues of $134.2 million and production of 2.6 MMBoe. The key drivers affecting our results for the three months ended June 30, 2013 included the following:

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



	For The Three Months Ended June 30, 2013				As of June 30, 2013
	Drilled		Completed		Waiting on Completion		Producing		Rig count
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford Shale	15	10.9	12	9.8	24	17.5	95	74.5	3
Niobrara Formation	13	4.3	10	3.3	6	2.0	50	20.6	2
Marcellus Shale	9	2.8	12	3.3	28	9.3	50	16.6	1
Barnett Shale	—	—	—	—	—	—	86	55.9	—
Total	37	18.0	34	16.4	58	28.8	281	167.6	6

Production. Our second quarter 2013 production of 2.6 MMBoe increased 7% from the second quarter 2012 production of 2.4 MMBoe. The increase in production from the second quarter of 2012 to the second quarter of 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”) in April 2012, and our Niobrara joint venture transactions in the fourth quarter of 2012.

Commodity prices. Our average realized oil price during the second quarter of 2013 was $98.98 per barrel, essentially flat compared to $98.96 for the second quarter of 2012. Our average realized natural gas price during the second quarter of 2013 was $3.07 per Mcf, or 133% higher than the $1.32 during the second 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.

Results of Operations

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

Revenues from oil and gas production for the three months ended June 30, 2013 increased 60% to $134.2 million from $83.8 million for the same period in 2012 primarily due to the significant increase in oil production and gas prices. Production volumes for the three months ended June 30, 2013 and 2012 were 2.6 MBoe and 2.4 MBoe, respectively. The increase in production from the second quarter of 2012 to the second quarter of 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, and our Niobrara joint venture transactions in the fourth quarter of 2012. Average realized oil prices remained essentially flat at $98.98 per barrel from $98.96 per barrel in the same period in 2012. Average realized gas prices increased 133% to $3.07 per Mcf in the second quarter of 2013 from $1.32 per Mcf in the same period in 2012.

-21-

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



	Three Months Ended June 30,				2013 Period Compared to 2012 Period
	2013		2012		Increase (Decrease)			% Increase (Decrease)
Production volumes -
Crude oil (MBbls)	1,069		693		376			54	%
NGLs (MBbls)	105		65		40			62	%
Natural gas (MMcf)	8,348		9,808		(1,460		)	(15	)%
Total Natural gas and NGLs (MMcfe)	8,978		10,198		(1,220		)	(12	)%
Total barrels of oil equivalent (MBoe)	2,565		2,393		172			7	%

Daily production volumes by product -
Crude oil (Bbls/d)	11,747		7,615		4,132			54	%
NGLs (Bbls/d)	1,154		714		440			62	%
Natural gas (Mcf/d)	91,736		107,780		(16,044		)	(15	)%
Total Natural gas and NGLs (Mcfe/d)	98,659		112,066		(13,407		)	(12	)%
Total barrels of oil equivalent (Boe/d)	28,187		26,297		1,890			7	%

Daily production volumes by region (Boe/d) -
Eagle Ford Shale	12,239		7,603		4,636			61	%
Niobrara Formation	1,839		1,041		798			77	%
Barnett Shale	8,136		12,380		(4,244		)	(34	)%
Marcellus Shale	5,647		3,772		1,875			50	%
Other	326		1,501		(1,175		)	(78	)%
Total barrels of oil equivalent (Boe/d)	28,187		26,297		1,890			7	%

Average realized prices -
Crude oil ($ per Bbl)	$	98.98	$	98.96	$	0.02		—	%
NGLs ($ per Bbl)	26.34		35.05		(8.71		)	(25	)%
Natural gas ($ per Mcf)	3.07		1.32		1.75			133	%
Total Natural gas and NGLs average realized price ($ per Mcfe)	$	3.17	$	1.49	$	1.68		113	%
Total average realized price ($ per Boe)	$	52.33	$	35.03	$	17.30		49	%

Oil and gas revenues (In thousands) -
Crude oil	$	105,805	$	68,576	$	37,229		54	%
NGLs	2,766		2,278		488			21	%
Natural gas	25,653		12,964		12,689			98	%
Total oil and gas revenues	$	134,224	$	83,818	$	50,406		60	%

Lease operating expenses were $11.8 million ($4.60 per Boe) for the three months ended June 30, 2013 as compared to lease operating expenses of $7.0 million ($2.94 per Boe) for the same period in 2012. The $4.8 million increase in lease operating expenses is primarily due to increased production from new wells partially offset by the sale of Barnett properties to Atlas on May 1, 2012. 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 $4.6 million (or 3.4% of oil and gas revenues) for the three months ended June 30, 2013 as compared to $3.1 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 decrease in production taxes as a percentage of oil and gas revenues was primarily due to increased Marcellus revenues, which are not subject to production tax and the sale to Atlas which had higher production tax rates than our remaining Barnett Shale assets.

Ad valorem taxes increased to $2.9 million ($1.12 per Boe) for the three months ended June 30, 2013 from $2.3 million ($0.96 per Boe) for the same period in 2012. The increase in ad valorem taxes is due primarily to new oil wells drilled during

-22-

2012. The increase in ad valorem taxes per Boe is due primarily to new oil wells drilled in 2012, which have higher property tax valuations as compared to our natural gas wells.

Depreciation, depletion and amortization (“DD&A”) expense for the second quarter of 2013 increased $7.0 million to $50.4 million ($19.65 per Boe) from the DD&A expense for the second quarter of 2012 of $43.4 million ($18.13 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 $17.8 million for the three months ended June 30, 2013 from $13.1 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 as well as increased stock-based compensation expense which was primarily driven by an increase in the fair value of cash-settled stock appreciation rights.

The net gain on derivative instruments of $25.7 million in the second quarter of 2013 consisted of a $23.4 million unrealized gain on derivatives and a $2.3 million realized gain on derivatives. The net gain on derivative instruments of $37.9 million in the second quarter of 2012 was comprised of a $27.9 million unrealized gain on derivatives and a $10.0 million realized gain on derivatives.

Interest expense and capitalized interest for the three months ended June 30, 2013 were $21.5 million and $7.5 million, respectively, as compared to $16.8 million and $6.0 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 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 income tax rate was 37.1% for 2013 and 2012. The effective income tax rates for the second quarter of 2013 and 2012 were 38.6% and 38.7%, respectively, which was higher than the estimated annual effective income tax rate due to changes in state tax estimates.

Six Months Ended June 30, 2013, Compared to the Six Months Ended June 30, 2012

Revenues from oil and gas production for the six months ended June 30, 2013 increased 50% to $246.1 million from $164.5 million for the same period in 2012 primarily due to the significant increase in oil production and gas prices. Production volumes for the six months ended June 30, 2013 and 2012 were 5.0 MBoe and 4.7 MBoe, respectively. The increase in production from the six months ended June 30, 2012 to the six months ended June 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, and our Niobrara joint venture transactions in the fourth quarter of 2012. Average realized oil prices decreased 2% to $101.36 per barrel from $103.68 per barrel in the same period in 2012. Average realized gas prices increased 73% to $2.77 per Mcf for the six months ended June 30, 2013 from $1.60 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 six months ended June 30, 2013 and 2012:



	Six Months Ended June 30,				2013 Period Compared to 2012 Period
	2013		2012		Increase (Decrease)			% Increase (Decrease)
Production volumes -
Crude oil (MBbls)	1,907		1,234		673			55	%
NGLs (MBbls)	206		114		92			81	%
Natural gas (MMcf)	17,077		20,135		(3,058		)	(15	)%
Total Natural gas and NGLs (MMcfe)	18,313		20,819		(2,506		)	(12	)%
Total barrels of oil equivalent (MBoe)	4,959		4,704		255			5	%

Daily production volumes by product -
Crude oil (Bbls/d)	10,536		6,780		3,756			55	%
NGLs (Bbls/d)	1,138		626		512			82	%
Natural gas (Mcf/d)	94,348		110,632		(16,284		)	(15	)%
Total Natural gas and NGLs (Mcfe/d)	101,177		114,390		(13,213		)	(12	)%
Total barrels of oil equivalent (Boe/d)	27,398		25,846		1,552			6	%

Daily production volumes by region (Boe/d) -
Eagle Ford Shale	11,280		6,617		4,663			70	%
Niobrara Formation	1,397		983		414			42	%
Barnett Shale	8,399		14,038		(5,639		)	(40	)%
Marcellus Shale	5,989		2,604		3,385			130	%
Other	333		1,604		(1,271		)	(79	)%
Total barrels of oil equivalent (Boe/d)	27,398		25,846		1,552			6	%

Average realized prices -
Crude oil ($ per Bbl)	$	101.36	$	103.68	$	(2.32	)	(2	)%
NGLs ($ per Bbl)	26.73		38.92		(12.19		)	(31	)%
Natural gas ($ per Mcf)	2.77		1.60		1.17			73	%
Total Natural gas and NGLs average realized price ($ per Mcfe)	$	2.89	$	1.76	$	1.13		64	%
Total average realized price ($ per Boe)	$	49.63	$	34.98	$	14.65		42	%

Oil and gas revenues (In thousands) -
Crude oil	$	193,287	$	127,945	$	65,342		51	%
NGLs	5,507		4,437		1,070			24	%
Natural gas	47,331		32,151		15,180			47	%
Total oil and gas revenues	$	246,125	$	164,533	$	81,592		50	%

Lease operating expenses were $22.0 million ($4.43 per Boe) for the six months ended June 30, 2013 as compared to lease operating expenses of $15.5 million ($3.29 per Boe) for the same period in 2012. The $6.5 million increase in lease 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 $9.1 million (or 3.7% of oil and gas revenues) for the six months ended June 30, 2013 as compared to $6.2 million (or 3.8% of oil and gas revenues) for the same period in 2012. The increase in production taxes is due primarily to increased oil production. The decrease in production taxes as a percentage of oil and gas revenues was primarily due to increased Marcellus revenues, which are not subject to production tax and the sale to Atlas which had higher production tax rates than our remaining Barnett Shale assets.

Ad valorem taxes decreased to $4.7 million ($0.95 per Boe) for the six months ended June 30, 2013 from $5.9 million ($1.26 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.

-24-

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 six months ended June 30, 2013 increased $21.1 million to $96.0 million ($19.36 per Boe) from the DD&A expense for the six months ended June 30, 2012 of $74.9 million ($15.93 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 $34.0 million for the six months ended June 30, 2013 from $24.6 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 cash-settled stock appreciation rights.

The net gain on derivative instruments of $11.2 million in the six months ended June 30, 2013 consisted of a $3.2 million unrealized gain on derivatives and an $8.0 million realized gain on derivatives. The net gain on derivative instruments of $41.7 million in the six months ended June 30, 2012 was comprised of a $20.6 million unrealized gain on derivatives and a $21.1 million realized gain on derivatives.

Interest expense and capitalized interest for the six months ended June 30, 2013 were $43.3 million and $14.3 million, respectively, as compared to $33.2 million and $12.0 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 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 six months ended June 30, 2013.

The estimated annual effective tax rate was 37.1% for 2013 and 2012. The effective income tax rates for the six months ended June 30, 2013 and 2012 were 38.5% and 37.2%, respectively, which was higher than the estimated annual effective income tax rate due to change in state tax estimates.

Included in net income of $63.2 million for the six months ended June 30, 2013 was $23.7 million, net of income taxes, related to a gain on the sale of Carrizo UK, which is included in net income from discontinued operations, net of income taxes in the accompanying consolidated statements of income.

-25-

Liquidity and Capital Resources

2013 Capital Expenditure Plan and Funding Strategy. The 2013 capital expenditures plan currently includes $530.0 to $540.0 million for drilling and completion and $140.0 million for leasehold and seismic. We intend to finance the remainder of our 2013 capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital expenditure 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 June 30, 2013:



	Capital Expenditures for the Three Months Ended
	March 31, 2013		June 30, 2013
	(In thousands)
Eagle Ford Shale	$	101,735	$	88,210
Marcellus Shale	18,888		19,459
Niobrara Formation	11,817		22,106
Barnett Shale and Other	4,257		3,460
Total drilling and completion	136,697		133,235

Total leasehold and seismic	89,274		30,182

Total	$	225,971	$	163,417

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

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. During the second quarter of 2013, we also used cash to retire approximately $69.3 million aggregate principal amount of our convertible senior notes. For the six months ended June 30, 2013, we funded our capital expenditures with cash provided by operations, cash on hand, net proceeds from the sale of assets, including the Carrizo UK sale, 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 our forecasted production to mitigate the risk of a decline in oil and gas prices.

•

Revolving credit facility. At July 31, 2013, we had $43.0 million 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 expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us. We are currently marketing the sale of substantially all of our Barnett Shale assets.


•	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.

Overview of Cash Flow Activities. Net cash provided by operating activities from continuing operations were $213.7 million and $145.3 million for the six months ended June 30, 2013 and 2012, respectively. The increase was primarily due to increased crude oil production and gas prices as well as the net changes in operating assets and liabilities in the first six months of 2013 as compared to the same period in 2012.

Net cash used in investing activities from continuing operations were $352.1 million and $233.9 million for the six months ended June 30, 2013 and 2012, respectively. Net cash used in investing activities from continuing operations for the six months ended June 30, 2013 and 2012 related primarily to capital expenditures associated with our Eagle Ford drilling and completion program.

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Net cash provided by (used in) financing activities from continuing operations were $(41.5) million and $82.2 million for the six months ended June 30, 2013 and 2012, respectively. The decrease related primarily to a decrease in net borrowings under our revolving credit facility during the first six months of 2013 as compared to the first six months of 2012 as well as the repurchase of the convertible senior notes in the second quarter of 2013.

Liquidity/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 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 June 30, 2013, we had hedged approximately 10,120,000 MMBtus of natural gas for the remainder of 2013. Additionally, we had hedged approximately 1,766,400 Bbls of oil for the remainder of 2013. Our borrowing base under our revolving credit facility is currently $530.0 million. As of July 31, 2013, we had $43.0 million 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. The next borrowing base redetermination is scheduled to occur in the Fall of 2013.

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.

Contractual Obligations

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



	2013		2014		2015		2016		2017		2018 and Beyond		Total
Long-term debt (1)	$	—	$	—	$	—	$	28,000	$	—	$	904,425	$	932,425
Interest on long-term debt (2)	37,545		75,057		75,057		74,489		74,443		119,330		455,921
Operating leases	919		1,819		1,792		1,770		1,770		7,963		16,033
Drilling and completion services (3)	37,079		38,692		11,322		1,165		—		—		88,258
Pipeline volume commitments	9,759		16,935		16,272		9,824		4,409		13,595		70,794
Asset retirement obligations and other (4)	5,021		11,225		7,764		3,310		1,459		6,566		35,345
Total Contractual Obligations	$	90,323	$	143,728	$	112,207	$	118,558	$	82,081	$	1,051,879	$	1,598,776


(1)	At June 30, 2013, we had $28.0 million of borrowings outstanding under the revolving credit facility which matures in 2016.


(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 2.19%.

(3) Drilling and completion services represent gross contractual obligations. However, other joint owners in the properties operated by the Company will incur their relative share of the costs, which will reduce the Company's share of such contractual obligations.

(4)

Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of June 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.

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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, at par plus accrued but unpaid interest to but excluding June 1, 2013, for aggregate consideration of $69.3 million (approximately 94% of the outstanding convertible senior notes). Each holder received $1,000 for each $1,000 principal amount of convertible senior notes repurchased in the tender offer. Due to the Company repurchasing the convertible senior notes on June 1, 2013, which is the date the semi-annual interest payment was due and after the record date, we paid only the regular interest payment as there was no accrued or unpaid interest due as part of the repurchase price. As of June 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 have a senior secured revolving credit facility that permits us to borrow up to the lesser of (i) the borrowing base (as defined in the credit agreement governing the revolving credit facility) and (ii) $750.0 million. The revolving credit facility matures on January 27, 2016. The revolving credit facility is secured by substantially all of our U.S. assets and is guaranteed by all of our existing subsidiaries (other than Monument Exploration LLC, Carrizo UK Bardolph Ltd, and Carrizo (Permian) LLC). 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.

As a result of the Spring 2013 borrowing base redetermination, effective April 29, 2013, the borrowing base was increased to $530.0 million from $365.0 million after considering the addition of proved reserves as a result of our successful ongoing drilling and completion program. 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 Fall 2013. 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.

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). At June 30, 2013, the ratio of Total Debt to EBITDA was 2.50 to 1.00, the Current Ratio was 1.83 to 1.00, the ratio of Senior Debt to EBITDA was 0.07 to 1.00 and the ratio of EBITDA to Interest Expense was 5.31 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 June 30, 2013, we had $28.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 2.19%. At June 30, 2013, we had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Future availability under the $530.0 million borrowing base is subject to the terms and covenants

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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.

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



	12 Month Average		Cushion/(Impairment)
U.S. Full Cost Pool Scenarios	Oil Price ($/Bbl)	Gas Price ($/Mcf)	(in millions)
June 30, 2013 Actual	$100.41	$2.62	$137

Oil and Gas Price Sensitivity
Oil and Gas +10%	$109.55	$2.96	$306
Oil and Gas -10%	$91.27	$2.28	$(33)

Oil Price Sensitivity
Oil +10%	$109.55	$2.62	$263
Oil -10%	$91.27	$2.62	$10

Gas Price Sensitivity
Gas +10%	$100.41	$2.96	$179
Gas -10%	$100.41	$2.28	$94

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, expiration or exchanged for physical delivery contracts. Our current long-term 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 income for the period in which the changes occur.

The fair value of derivative instruments at June 30, 2013 and December 31, 2012 was a net asset of $32.3 million and $29.2 million, respectively. The following sets forth a summary of the net fair value of our derivative instruments by counterparty:



Counterparty	June 30, 2013		December 31, 2012
Credit Suisse	38	%	40	%
Societe Generale	35	%	22	%
Wells Fargo	13	%	2	%
BNP Paribas	13	%	33	%
BBVA Compass	1	%	3	%
Total	100	%	100	%

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 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, BBVA Compass, Wells Fargo, and Societe Generale 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. BNP Paribas may require the Company, if the Company is in a net liability position, to post collateral for the outstanding derivatives instruments as of the applicable valuation date. The Company had no net liability positions with any counterparty at June 30, 2013 and December 31, 2012. Therefore, the Company had no collateral posted during either of these respective periods.

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



Period	Volumes (in MMBtu)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
2013	10,120,000	$	4.58	$	4.58
2014	18,250,000	$	4.07	$	4.36
2015	3,650,000	$	4.33	$	4.33

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



Period	Volumes (in Bbls)	Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
2013	1,766,400	$	90.17	$	100.87
2014	3,375,500	$	90.59	$	96.99
2015	1,806,750	$	89.41	$	94.96
2016	244,000	$	85.00	$	104.00

In connection with the crude oil derivative instruments above, we entered into protective put spreads. For 2014, at market prices below the short put price of $65.00, the floor price becomes the market price plus the put spread of $20.00 on 182,500 of the 3,375,500 Bbls and the remaining 3,193,000 Bbls would have a floor price of $90.59.



Period	Volumes (in Bbls)	Weighted Average Short Put Price ($/Bbl)		Weighted Average Put Spread ($/Bbl)
2014	182,500	$	65.00	$	20.00
2015	365,000	$	65.00	$	20.00
2016	244,000	$	65.00	$	20.00

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
Realized gain (loss) on derivative instruments, net	$	2,291	$	9,962	$	8,006	$	21,095
Unrealized gain (loss) on derivative instruments, net	23,435		27,928		3,166		20,598
Gain (loss) on derivative instruments, net	$	25,726	$	37,890	$	11,172	$	41,693

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, acquisition of 3-D seismic data (including number, timing and size of projects), 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 facilities, 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 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 facilities, evaluations of the Company by lenders under our credit facilities, 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.

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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 June 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 June 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

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.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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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
10.1	–	Form of Director Restricted Stock Unit Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 17, 2013).
10.2	–	Form of Employee Restricted Stock Award Agreement (Officer) under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed June 17, 2013).
10.3	–	Form of Employee Restricted Stock Unit Award Agreement (Officer) under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed June 17, 2013).
10.4	–	Form of Employee Stock Appreciation Rights Agreement (Officer) under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed June 17, 2013).
10.5	–	Form of Employee Stock Appreciation Rights Agreement (Officer) under the Carrizo Oil & Gas, Inc. Cash-Settled Appreciation Rights Plan (incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed June 17, 2013).
*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.
*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:	August 7, 2013	By:	/s/ Paul F. Boling
		Chief Financial Officer, Vice President, Secretary and Treasurer (Principal Financial Officer)

Date:	August 7, 2013	By:	/s/ David L. Pitts
		Vice President and Chief Accounting Officer (Principal Accounting Officer)

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