Edgar Filing: CARRIZO OIL & GAS INC

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

¨	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.)


1000 Louisiana Street, Suite 1500, 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 ¨ 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 April 29, 2011 was 38,936,978.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011

INDEX


		PAGE
PART I. FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets As of March 31, 2011 (Unaudited) and December 31, 2010		2

	Consolidated Statements of Operations (Unaudited) For the three months ended March 31, 2011 and 2010		3

	Consolidated Statements of Cash Flows (Unaudited) For the three months ended March 31, 2011 and 2010		4

	Notes to Consolidated Financial Statements (Unaudited)		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		28

Item 4.	Controls and Procedures		28

PART II. OTHER INFORMATION

Items 1-6.			29

SIGNATURES			31

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS


	March 31, 2011			December 31, 2010
	(Unaudited)
	(In thousands, except per share amount)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	21,956		$	4,128
Accounts receivable, net
Oil and gas sales		15,788			16,027
Joint interest billing		16,329			14,309
Related party		525			—
Other		1,031			560
Advances to operators		521			487
Fair value of derivative instruments		12,723			17,698
Prepaids and other current assets		10,261			7,123

Total current assets		79,134			60,332

PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full cost method of accounting:
Proved oil and gas properties, net		686,630			626,665
Costs not subject to amortization		381,903			352,479
Other property and equipment, net		3,870			3,913

TOTAL PROPERTY AND EQUIPMENT, NET		1,072,403			983,057

DEFERRED FINANCING COSTS, NET		20,588			14,670
INVESTMENTS		2,523			3,392
FAIR VALUE OF DERIVATIVE INSTRUMENTS		4,208			7,257
DEFERRED INCOME TAXES		69,807			72,587
INVENTORY		1,646			1,646
OTHER ASSETS		1,350			1,193

TOTAL ASSETS	$	1,251,659		$	1,144,134


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	24,041		$	33,653
Revenue and royalties payable		30,284			23,864
Current state tax payable		4,093			4,052
Accrued drilling costs		51,239			26,884
Accrued interest		15,786			5,953
Other accrued liabilities		14,453			11,838
Advances for joint operations		43			3,407
Current maturities of long-term debt		—			160
Deferred income taxes		3,570			5,286
Other current liabilities		2,944			3,907

Total current liabilities		146,453			119,004

LONG-TERM DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT		631,297			558,094
ASSET RETIREMENT OBLIGATIONS		6,516			6,369
FAIR VALUE OF DERIVATIVE INSTRUMENTS		2,003			715
OTHER LIABILITIES		5,755			3,316
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value (90,000 shares authorized, 38,922 and 38,906 shares issued and outstanding at March 31, 2011 and December 31, 2010, respectively)		389			389
Additional paid-in capital		633,108			630,845
Accumulated deficit		(173,862	)		(174,598	)

Total shareholders’ equity		459,635			456,636

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,251,659		$	1,144,134

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended March 31,
	2011			2010
	(In thousands except
	per share amounts)

OIL AND GAS REVENUES	$	44,058		$	38,956

COSTS AND EXPENSES
Lease operating		6,666			5,077
Production tax		941			905
Ad valorem tax		691			1,204
Depreciation, depletion and amortization		16,676			9,841
General and administrative (inclusive of stock-based compensation of $3,850 and $2,164 for the three months ended March 31, 2011 and 2010, respectively)		9,245			6,936
Accretion related to asset retirement obligations		74			51

TOTAL COSTS AND EXPENSES		34,293			24,014

OPERATING INCOME		9,765			14,942
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net		(187	)		22,802
Loss on extinguishment of debt		(897	)		—
Interest expense		(12,208	)		(9,810	)
Capitalized interest		5,260			4,469
Other income, net		62			30

INCOME BEFORE INCOME TAXES		1,795			32,433
INCOME TAX EXPENSE		(1,060	)		(12,697	)

NET INCOME	$	735		$	19,736

OTHER COMPREHENSIVE LOSS, NET OF INCOME TAXES
Decrease in market value of investment in Pinnacle Gas Resources, Inc.		—			(15	)

COMPREHENSIVE INCOME	$	735		$	19,721


INCOME PER COMMON SHARE
BASIC	$	0.02		$	0.64

DILUTED	$	0.02		$	0.63


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC		38,783			31,071
DILUTED		39,406			31,515

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 Three Months Ended March 31,
	2011			2010
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	735		$	19,736
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation, depletion and amortization		16,676			9,841
Unrealized (gain) loss on derivative instruments		10,194			(17,847	)
Accretion related to asset retirement obligations		74			51
Loss on extinguishment of debt		897			—
Stock-based compensation		3,850			2,164
Allowance for doubtful accounts		(32	)		123
Deferred income taxes		1,064			12,682
Amortization of discount and deferred financing costs, net of amounts capitalized		865			1,695
Other, net		1,860			674
Changes in operating assets and liabilities-
Accounts receivable		(1,922	)		(3,072	)
Accounts payable		9,452			(326	)
Accrued liabilities		11,192			1,361
Other, net		(2,628	)		(119	)

Net cash provided by operating activities		52,277			26,963

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(107,565	)		(60,994	)
Change in capital expenditure payables and accruals		11,869			(3,458	)
Proceeds from sales of oil and gas properties		362			592
Advances to operators		(34	)		142
Advances for joint operations		(3,364	)		(1,716	)
Other, net		(210	)		(156	)

Net cash used in investing activities		(98,942	)		(65,590	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		219,000			52,600
Debt repayments		(146,660	)		(16,000	)
Proceeds from stock options exercised		9			557
Payments of debt issuance costs		(7,856	)		—

Net cash provided by financing activities		64,493			37,157

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		17,828			(1,470	)
CASH AND CASH EQUIVALENTS, beginning of period		4,128			3,837

CASH AND CASH EQUIVALENTS, end of period	$	21,956		$	2,367

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 an independent energy company which, together with its subsidiaries (collectively referred to herein as the “Company”), is engaged in the exploration, development and production of oil and gas in the United States and the U.K. North Sea. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, New York and West Virginia, the Eagle Ford Shale in South Texas, the Niobrara Formation in Colorado and the Huntington Field located in the U.K. North Sea.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and LLCs where the Company, as a partner or member, has undivided interests in the oil and gas properties. The consolidated financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. 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, 2010.

Unconsolidated Investments

The Company accounts for its investment in Pinnacle Gas Resources, Inc. as available-for-sale and adjusts the book value to fair value through other comprehensive income (loss), net of income taxes. This fair value is assessed quarterly for other than temporary impairment based on publicly available information. If the impairment is deemed other than temporary, it is recognized in earnings. Subsequent recoveries in fair value are reflected as increases to investments and other comprehensive income (loss), net of income taxes.

The Company accounts for its investment in Oxane Materials, Inc. using the cost method of accounting and adjusts the carrying amount of its investment for contributions to and distributions from the entity.

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, shareholders’ equity, net income, comprehensive income or net cash provided by/used in operating, investing or financing activities.

Use of Estimates

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 financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. The operating results for the three months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full year. 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 asset retirement obligations. Other significant estimates include the, impairment of unproved properties, fair values of derivative instruments, stock-based compensation, the collectability of outstanding

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receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data. Subsequent drilling results, testing and production may justify revisions of such estimates. Accordingly, proved oil and gas reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. In addition, proved oil and gas reserve estimates are vulnerable to changes in market prices of oil and gas. Such prices have been volatile in the past and can be expected to be volatile in the future

Estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices of oil and gas, the credit worthiness of counterparties, interest rates and the market value and volatility of the Company’s common stock. Future changes in these assumptions may affect these significant estimates materially in the near term.

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 directly associated with acquisition, exploration and development activities are capitalized and totaled $3.0 million and $1.2 million for the three months ended March 31, 2011 and 2010, respectively. Costs related to production, general corporate overhead or 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 which is applied 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 Mcfe was $1.53 and $1.16 for the three months ended March 31, 2011 and 2010, respectively.

Costs not subject to amortization include unevaluated leasehold costs, seismic costs associated with specific unevaluated properties, related capitalized interest and the cost of exploratory wells in progress. Significant costs 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 properties within the next two to five years. Insignificant costs 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 of $5.3 million and $4.5 million for the three months ended March 31, 2011 and 2010, respectively. Interest is capitalized on the average balance of unproved properties 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. The Company has not had any sales of oil and gas properties that significantly alter that relationship.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (1) 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 (2) 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.

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

Stock-Based Compensation

The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock (“Stock SARs”), SARs that may only be settled in cash (“Cash SARs”), restricted stock awards and restricted stock units to directors, employees and independent contractors. The Company recognized the following stock-based compensation expenses for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Stock Options and SARs	$	2,000		$	421
Restricted Stock Awards and Units		3,119			1,743

		5,119			2,164
Less: amounts capitalized		(1,269	)		—

Total Stock-Based Compensation Expense		3,850			2,164

Stock Options and SARs. For stock options and Stock 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 Cash SARs and any Stock 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. 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 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 awards 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 average of the high and low 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.

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 when the well is drilled with an associated increase in oil and gas property costs. The asset retirement obligation is recorded at fair value and requires 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 obligation is discounted using a credit-adjusted risk-free interest rate which is accreted over time to its expected settlement value. 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. On a quarterly basis, the Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with original maturities of three months or less.

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Revenue Recognition

Oil and gas sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue 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 March 31, 2010 and December 31, 2010, the Company did not have any material production imbalances.

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 instruments and costs associated with revolving credit facilities. The capitalized costs are amortized to interest expense using the effective interest method over the terms of the debt instruments or credit facilities.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative instruments and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amounts of long-term debt under the Prior Credit Facility and the Revolving Credit Facility approximate fair value as these borrowings bear interest at variable rates of interest. The carrying amounts of the Senior Notes and Convertible Senior Notes do not approximate fair value because the notes bear interest at fixed rates of interest. See Note 9. Fair Value Measurements.

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 current 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 oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty.

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.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third parties in the oil and gas industry or drilling and completion advances to third-party operators for development 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.

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 on a quarterly basis and adjusts the allowance as necessary using the specific identification method. At March 31, 2011 and December 31, 2010, the Company’s allowance for doubtful accounts was $2.4 million and $2.5 million, respectively.

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Income Per Common Share

Supplemental income per common share information is provided below:


	Three Months Ended March 31,
	2011		2010
	(In thousands, except per share amounts)
Net income (loss)	$	735	$	19,736


Average common shares outstanding
Weighted average common shares outstanding		38,783		31,071
Restricted stock, stock options and warrants		623		444

Diluted weighted average common shares outstanding		39,406		31,515


Net income (loss) per common share
Basic	$	0.02	$	0.64
Diluted	$	0.02	$	0.63

Basic income per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted income 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 units, stock options, Stock SARs expected to be settled in common stock, warrants and convertible debt. The Company excluded 2,396 and 39,121 shares related to restricted stock units, stock options and warrants from the calculation of dilutive shares for the three months ended March 31, 2011 and 2010, respectively because the grant prices were greater than the average market prices of the common shares for the period and would be antidilutive to the computation. Shares of common stock subject to issuance upon the conversion of the Convertible Senior Notes did not have an effect on the calculation of dilutive shares for the three months ended March 31, 2011 or 2010, because the conversion price was in excess of the market price of the common stock for those periods.

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. 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.

Commitments and Contingencies

Liabilities are recognized for contingencies when it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

Foreign Currency

The U.S. dollar is the functional currency for the Company’s operations in the U.K. North Sea. Transaction gains or losses that occur due to the realization of assets and the settlement of liabilities using a currency denominated in other than the functional currency are recorded as other income, net in the consolidated statements of operations.

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3. INVESTMENTS

Investments consisted of the following at March 31, 2011 and December 31, 2010:


	March 31, 2011		December 31, 2010
	(In thousands)
Pinnacle Gas Resources, Inc.	$	—	$	869
Oxane Materials, Inc.		2,523		2,523

	$	2,523	$	3,392

Pinnacle Gas Resources, Inc.

On January 25, 2011, Pinnacle Gas Resources, Inc. (“Pinnacle”) announced that it had been acquired by Powder Holdings, LLC, an entity controlled by SW Energy Capital LP. Under the terms of the merger agreement, the Company will receive $0.9 million, or $0.34 per share, in cash for its 2,555,825 shares of Pinnacle common stock.

4. INCOME TAXES

For the three months ended March 31, 2011 and 2010, all of the Company’s income before income taxes is derived from activities within the United States. The Company’s estimated annual effective income tax rate is used to allocate expected annual income tax expense to interim periods. The rate is the ratio of estimated annual income tax expense to estimated annual income before income taxes, 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 rate is applied to the year-to-date income before income taxes 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. Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35% to income before income taxes as follows:


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Income tax expense at the statutory rate	$	628		$	11,352
State income taxes, net of federal benefit		1,575			1,334
Capital loss associated with investment in Pinnacle for which no income tax benefit was recognized in prior years		(1,135	)		—
Other, net		(8	)		11

Income tax expense	$	1,060		$	12,697

State income taxes for the three months ended March 31, 2011, were higher than the Company’s estimated annual effective income tax rate of 37% primarily as a result of providing for changes in the current year estimated and prior year actual effective state income tax rate. This increase was partially offset by the income tax benefit of a capital loss associated with the Company’s investment in Pinnacle which was sold in the first quarter of 2011 for which no income tax benefit was recognized in prior years. The Company expects to realize the benefit of this capital loss by offsetting it against the capital gain the Company expects to result from the sale of its non-core Barnett Shale properties in the second quarter of 2011. See Note 11, Subsequent Events for further discussion regarding the sale of these non-core Barnett Shale properties.

As of March 31, 2011, the Company had income tax net operating loss (“NOL”) carryforwards of approximately $188.2 million which expire between 2019 and 2031 if not utilized in earlier periods. The realization of the deferred tax assets related to NOL carryforwards is dependent on the Company’s ability to generate taxable income in the future. The Company believes it will be able to generate sufficient taxable income in the NOL carryforward period. As such, the Company believes that it is more likely than not that its deferred tax assets will be fully realized.

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At March 31, 2011, 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.

5. DEBT

Debt consisted of the following at March 31, 2011 and December 31, 2010:


	March 31, 2011			December 31, 2010
	(In thousands)
Senior Notes	$	400,000		$	400,000
Unamortized discount for Senior Notes		(2,690	)		(2,751	)
Convertible Senior Notes		73,750			73,750
Unamortized discount for Convertible Senior Notes		(5,763	)		(6,405	)
Senior Secured Revolving Credit Facility		166,000			93,500
Senior Secured Multicurrency Credit Facility		—			—
Other		—			160

		631,297			558,254
Less: Current maturities		—			(160	)

	$	631,297		$	558,094

Senior Notes

In connection with the issuance of the Senior Notes, the Company agreed to use its commercially reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange new registered notes having terms substantially identical to the Senior Notes for outstanding Senior Notes. In certain circumstances, the Company may be required to use commercially reasonable efforts to file a shelf registration statement to cover resales of the Senior Notes. The Company may be required to pay additional interest to holders of the Senior Notes under certain circumstances if it fails to meet these obligations by certain dates. On April 29, 2011, the Company filed a Form S-4 Registration Statement with the SEC relating to the offer to exchange registered 8.625% Senior Notes due 2018, for any and all of its unregistered 8.625% Senior Notes due 2018, that were issued pursuant to a private placement on November 2, 2010.

Prior Senior Secured Revolving Credit Facility

Prior to January 27, 2011, the Company had a senior secured revolving credit facility (the “Prior Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent. The Prior Credit Facility provided for a borrowing capacity up to the lesser of the borrowing base or $350 million. It was secured by substantially all of the Company’s proved oil and gas assets and was guaranteed by certain of the Company’s subsidiaries. In connection with the Company’s entrance into a new senior secured revolving credit facility with an increased borrowing capacity and extended maturity as discussed below, on January 27, 2011, the Company repaid its full indebtedness outstanding under the Senior Credit Agreement governing the Prior Credit Facility and terminated the Senior Credit Agreement. As a result, we recognized a $0.9 million non-cash pre-tax loss on extinguishment of debt, related to the deferred financing costs attributable to the commitments of two banks in the Prior Credit Facility who are not participating in the new credit facility.

Senior Secured Revolving Credit Facility

On January 27, 2011, the Company entered into a new $750 million secured revolving credit facility with a five-year term (“Revolving Credit Facility”) with BNP Paribas as the administrative agent, sole book runner and lead arranger. The Revolving Credit Facility provides for a borrowing capacity up to the lesser of (i) the Borrowing Base and (ii) $750 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of the Company’s assets and is guaranteed by certain of the Company’s subsidiaries. The initial Borrowing Base under the Revolving Credit Facility is $350 million. The Revolving Credit Facility provides that the Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, beginning May 1, 2011. The next borrowing base redetermination is currently expected to occur on or before June 1, 2011 following the sale of certain non-core Barnett Shale properties. See Note 11, Subsequent Events for further discussion regarding the sale.

The annual interest rate on each base rate borrowing is (a) the greatest of the Prime Rate, the Federal Funds Effective Rate plus 0.5% and the adjusted LIBO rate for a three-month interest period on such day plus 1.00%, plus (b) a margin between 1.00% and 2.00% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted LIBO rate for the applicable interest period plus a margin between 2.00% to 3.00% (depending on the then-current level of borrowing base usage).

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The Company is subject to certain covenants under the terms of the Revolving Credit Facility 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 (a) 4.75 to 1.00 for fiscal quarters ending March 31, 2011 through December 31, 2011, (b) 4.25 to 1.00 for fiscal quarters ending March 31, 2012 through June 30, 2012 and (c) 4.00 to 1.00 for fiscal quarters ending September 30, 2012 and thereafter; (2) a current ratio of not less than 1.0 to 1.0; (3) a Senior Debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to Interest Expense ratio of not less than 2.50 to 1.00. At March 31, 2011, the ratio of Total Debt to EBITDA was 3.71 to 1.00, the current ratio was 2.06 to 1.0, the Senior Debt to EBITDA ratio was .98 to 1.00 and the EBITDA to Interest Expense ratio was 5.13 to 1.00. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the Revolving Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

The Revolving Credit Facility also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

The Revolving Credit Facility is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the Majority Lenders 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).

On January 27, 2011, the Company borrowed $112 million under the Revolving Credit Facility, which was used to repay in full indebtedness outstanding under the Prior Credit Facility, to pay transaction costs associated with the entrance into the Revolving Credit Facility and for other general corporate purposes.

At March 31, 2011, the Company had $166 million of borrowings outstanding under the Revolving Credit Facility with a weighted average interest rate of 2.7%. At March 31, 2011, the Company also had $0.3 million in letters of credit outstanding which reduced the amounts available under the Revolving Credit Facility. Future availability under the $350 million borrowing base is subject to the terms and covenants of the Revolving Credit Facility. The Revolving Credit Facility is used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan only to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

UK Huntington Limited Recourse Credit Facility

On January 28, 2011, the Company and Carrizo UK Huntington Ltd., a wholly-owned subsidiary of the Company incorporated in England and Wales (“Carrizo UK”), as Borrower, entered into a limited recourse Senior Secured Multicurrency Credit Facility Agreement with BNP Paribas and Societe Generale, as lead arrangers and original lenders (the “Huntington Facility”). The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea. The Huntington Facility provides for a multicurrency credit facility consisting of (1) a $55 million term loan facility to be used to fund Carrizo UK’s share of project development costs, (2) a $6.5 million contingent cost overrun term loan facility and (3) a $22.5 million post-completion credit facility providing for loans and letters of credit to be used to fund certain abandonment and decommissioning costs following project completion.

Availability under each of the term loan facility and the cost overrun facility is subject to borrowing bases that are generally based on consolidated cash flow and debt service projections for Carrizo UK attributable to certain proved reserves in the Huntington Field project. The availability under the term loan facility and the cost overrun facility will be redetermined by the lenders at least semi-annually on each April 1 and October 1 in connection with the updating and recalculation of revenue and cash flow projections with respect to the Huntington Field project, except that the first such redetermination and recalculation took place on May 1, 2011, which confirmed the existing ultimate availability discussed above.

Initial borrowings under the term loan facility and cost overrun facility are conditioned on, among other things, the Company’s having made an approximately $22 million equity contribution to Carrizo UK, which was completed in February 2011. The annual interest rate on each borrowing is (a) LIBOR (EURIBOR for euro-denominated loans) for the applicable interest period, plus (b) a margin of (i) 3.50% until the completion of the Huntington Field development project and 3.0% thereafter for the term loan credit facility and post-completion revolving credit facility or (ii) 4.75% for the cost overrun facility.

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Borrowings under the term loan and cost overrun facilities are available until the earlier of December 31, 2012 or the achievement of certain project development milestones. The term loan and cost overrun facilities mature on December 31, 2014, subject to acceleration in the event that future projection estimates of remaining reserves in the project area have declined to less than 25% of the level initially projected by Carrizo UK and the lenders. Letters of credit under the post-completion revolving credit facility mature on December 31, 2016. Amounts outstanding under the term loan or cost overrun facility currently must be repaid according to the following schedule: (i) 45% will be due on December 31, 2012, (ii) 20% will be due on June 30, 2013, (iii) 20% will be due on December 31, 2013, (iv) 10% will be due on June 30, 2014 and (iv) the remaining 5% will be due on the final maturity date of December 31, 2014.

The Huntington Facility requires Carrizo UK to enter into certain hedging arrangements to hedge a specified portion of the Huntington Field project’s exposure to fluctuating petroleum prices as well as changes in interest rates or exchange rates, and permits Carrizo UK to enter into additional hedging arrangements. The Huntington Facility places restrictions on Carrizo UK with respect to additional indebtedness, liens, the extension of credit, dividends or other payments to the Company or its other subsidiaries, investments, acquisitions, mergers, asset dispositions, commodity transactions outside of the mandatory hedging program, transactions with affiliates and other matters.

The Huntington Facility is subject to customary events of default. If an event of default occurs and is continuing, the Majority Lenders may accelerate amounts due under the Huntington Facility.

As of March 31, 2011, no amounts were outstanding under the Huntington Facility and no letters of credit had been issued.

6. COMMITMENTS AND CONTINGENCIES

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a material adverse effect on the financial position or results of operations of the Company.

The financial position and results of operations of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

7. SHAREHOLDERS’ EQUITY

On November 24, 2009, the Company entered into a Land Agreement, as amended (the “Land Agreement”), with an unrelated third party and its affiliate. Under this arrangement, the Company may until May 31, 2011 acquire up to $20 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from the third party. In consideration of the Company’s receipt of an option to purchase the leases acquired by the third party, each time the third party purchases a lease group under the Land Agreement, if any, the Company will issue to the third party’s affiliate warrants to purchase a number of shares of the Company’s common stock equal to the quotient of (rounded up to the nearest whole number) (1) 20% of the purchase price of such lease group divided by (2) $13.00, with an exercise price of $22.09 and an expiration date of August 21, 2017. In addition, under certain circumstances where the Company reaches surface casing point on an initial well in one of the areas covered by the Land Agreement but has not achieved a specified lease up threshold for acreage in such area, the Company will issue additional warrants, on the same terms, to purchase a number of shares of the Company’s stock equal to the quotient (rounded up to the nearest whole number) of (1) 20% of the product of (A) the number of acres below the specified lease up threshold multiplied by (B) $5,000, divided by (2) $13.00. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis.

Under the Land Agreement, the Company issued warrants to purchase 57,461 shares of common stock in 2010 and warrants to purchase 8,297 and 10,311 shares of common stock on February 1, 2011 and March 4, 2011, respectively.

8. DERIVATIVE INSTRUMENTS

The Company relies on 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 program. 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. The Company’s current long-term strategy is to manage exposure for a substantial, but

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varying, portion of forecasted production up to 36 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations for the period in which the changes occur.

The fair value of derivative instruments at March 31, 2011, and December 31, 2010 was a net asset of $14.9 million and $24.1 million, respectively. At March 31, 2011, approximately 67% of the fair value of the Company’s derivative instruments were with Credit Suisse, 16% were with Shell Energy North America (US) LP, 10% were with BNP Paribas, 6% were with Credit Agricole, and the remaining 1% were with Societe Generale and master netting agreements are in place with these counterparties. Because the counterparties are either investment grade financial institutions or an investment grade international oil and gas company, 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, BNP Paribas, Credit Agricole, and Societe Generale are lenders in the Company’s Revolving Credit Facility, and BNP Paribas and Societe Generale are lenders in the Company’s Huntington Facility, the Company is not required to post collateral with respect to derivatives instruments in a net liability position with these counterparties as the contracts are secured by the Revolving Credit Facility or the Huntington Facility.

The following sets forth a summary of the Company’s natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of March 31, 2011.


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2011		19,255,000	$	5.65	$	5.83
2012		11,623,000	$	5.90	$	6.33
2013		3,650,000	$	5.00	$	5.00

In connection with the derivative instruments above, the Company has entered into protective put spreads. When the market price declines below the short put price as reflected below, the Company will effectively receive the market price plus a put spread. For example, for the remainder of 2011, if market prices fall below the short put price of $4.55, the floor price becomes the market price plus the put spread of $1.35 on 11,494,000 of the 19,255,000 MMBtus and the remaining 7,761,000 MMBtus have a floor price of $5.65.


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2011		11,494,000	$	4.55	$	1.35
2012		6,404,000	$	5.17	$	1.09

For the three months ended March 31, 2011 and 2010, the Company recorded the following related to its derivative instruments:


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Realized gain	$	10,007		$	4,955
Unrealized gain (loss)		(10,194	)		17,847

Gain (loss) on derivative instruments, net	$	(187	)	$	22,802

The Company deferred the payment of premiums associated with certain of its oil and gas derivative instruments totaling $4.2 million and $3.9 million at March 31, 2011 and December 31, 2010, respectively. The Company classified $3.0 million and $3.9 million as other current liabilities at March 31, 2011 and December 31, 2010, respectively, and $1.2 million as other non-current liabilities at March 31, 2011. These deferred premiums will be paid to the counterparty with each monthly settlement (April 2011 – March 2014) and recognized as a reduction of realized gain on derivative instruments.

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9. FAIR VALUE MEASUREMENTS

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:


	March 31, 2011										December 31, 2010
	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
	(in thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.	$	—	$	—		$	—	$	—		$	869	$	—		$	—	$	869
Derivative instruments		—		36,839			—		36,839			—		48,140			—		48,140
Liabilities:
Derivative instruments		—		(21,911	)		—		(21,911	)		—		(24,062	)		—		(24,062	)


Total	$	—	$	14,928		$	—	$	14,928		$	869	$	24,078		$	—	$	24,947

The fair values of derivative instruments are based on a third-party pricing model which utilizes inputs that include (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 compared to the values provided by the counterparty for reasonableness. Derivative instruments are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. The fair values reported in the consolidated balance sheets are as of a 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 tables above are presented on a gross basis. 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 fair values of the investment in Pinnacle are based on the closing price of Pinnacle’s common stock on December 31, 2010. The Company had no transfers in or out of Levels 1 or 2 for the three months ended March 31, 2011.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the borrowings under the Revolving Credit Facility as of March 31, 2011 and the Prior Credit Facility as of December 31, 2010, approximate the carrying amounts and were based upon interest rates currently available to the Company for borrowings with similar terms. The fair values of the Convertible Senior Notes and Senior Notes at March 31, 2011, were estimated at approximately $73.3 million and $424.0 million based on quoted market prices.

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Other Fair Value Measurements

The initial measurement of asset retirement obligations at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, the costs of surface restoration and reserve lives.

10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On October 28, 2010, the Company and certain of its wholly owned subsidiaries Bandelier Pipeline Holding, LLC, Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding Inc., CCBM, Inc., Chama Pipeline Holding LLC, CLLR, Inc, Hondo Pipeline, Inc. and Mescalero Pipeline, LLC (collectively, the “Subsidiary Guarantors”) entered into a purchase agreement pursuant to which the Company agreed to sell $400 million aggregate principal amount of the Company’s 8.625% Senior Notes due 2018. Certain, but not all, of the Company’s wholly owned subsidiaries have issued full, unconditional and joint and several guarantees of the Senior Notes and may guarantee future issuances of debt securities.

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 March 31, 2011 and December 31, 2010, and for the three months ended March 31, 2011 and March 31, 2010 on a parent company, combined guarantor subsidiaries, non-guarantor subsidiary, eliminating entries, 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 the subsidiary guarantors 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


	March 31, 2011
	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,128,414		$	33,060		$	15,606		$	(1,097,946	)	$	79,134
Property and equipment, net		168,247			864,258			34,576			5,322			1,072,403
Investment in subsidiaries		(132,207	)		—			—			132,207			—
Other assets		30,315			72,994			—			(3,187	)		100,122

Total assets	$	1,194,769		$	970,312		$	50,182		$	(963,604	)	$	1,251,659


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	90,061		$	1,101,409		$	52,929		$	(1,097,946	)	$	146,453
Long-term liabilities		649,338			1,111			(2,748	)		(2,130	)		645,571
Shareholders’ equity		455,370			(132,208	)		1			136,472			459,635

Total liabilities and shareholders’ equity	$	1,194,769		$	970,312		$	50,182		$	(963,604	)	$	1,251,659


	December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,029,000		$	22,733		$	—		$	(991,401	)	$	60,332
Property and equipment, net		194,243			784,790			—			4,024			983,057
Investment in subsidiaries		(139,829	)		—			—			139,829			—
Other assets		99,876			78,288			—			(77,419	)		100,745

Total assets	$	1,183,290		$	885,811		$	—		$	(924,967	)	$	1,144,134


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	85,783		$	1,024,622		$	—		$	(991,401	)	$	119,004
Long-term liabilities		644,315			1,018			—			(76,839	)		568,494
Shareholders’ equity		453,192			(139,829	)		—			143,273			456,636

Total liabilities and shareholders’ equity	$	1,183,290		$	885,811		$	—		$	(924,967	)	$	1,144,134

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS


	For the Three Months Ended March 31, 2011
	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues	$	8,775		$	35,283		$	—	$	—		$	44,058
Cost and expenses		16,181			19,410			—		(1,298	)		34,293

Operating income (loss)		(7,406	)		15,873			—		1,298			9,765
Other expenses		(4,144	)		(3,826	)		—		—			(7,970	)


Income (loss) before income taxes		(11,550	)		12,047			—		1,298			1,795
Income tax (expense) benefit		3,843			(4,426	)		—		(477	)		(1,060	)

Equity in income of subsidiaries		7,621			—			—		(7,621	)		—

Net income	$	(86	)	$	7,621		$	—	$	(6,800	)	$	735


	For the Three Months Ended March 31, 2010
	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues	$	11,228		$	27,728		$	—	$	—		$	38,956
Cost and expenses		13,790			11,520			—		(1,296	)		24,014

Operating income (loss)		(2,562	)		16,208			—		1,296			14,942
Other income and (expenses)		19,906			(2,415	)		—		—			17,491

Income before income taxes		17,344			13,793			—		1,296			32,433
Income tax expense		(6,528	)		(5,707	)		—		(462	)		(12,697	)
Equity in income of subsidiaries		8,086			—			—		(8,086	)		—

Net income	$	18,902		$	8,086		$	—	$	(7,252	)	$	19,736

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


	For the Three Months Ended March 31, 2011
	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities	$	28,724		$	23,553		$	—		$	—		$	52,277
Net cash used in investing activities		(90,639	)		(77,001	)		(34,575	)		103,273			(98,942	)
Net cash provided by financing activities		64,493			53,092			50,181			(103,273	)		64,493

Net increase (decrease) in cash and cash equivalents		2,578			(356	)		15,606			—			17,828

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

Cash and cash equivalents, end of period	$	3,996		$	2,354		$	15,606		$	—		$	21,956


	For the Three Months Ended March 31, 2010
	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities	$	8,537		$	18,426		$	—		$	—		$	26,963
Net cash used in investing activities		(44,673	)		(63,096	)		—			42,179			(65,590	)
Net cash provided by financing activities		37,157			42,179			—			(42,179	)		37,157

Net increase (decrease) in cash and cash equivalents		1,021			(2,491	)		—			—			(1,470	)

Cash and cash equivalents, beginning of period		1,337			2,500									3,837

Cash and cash equivalents, end of period	$	2,358		$	9		$	—		$	—		$	2,367

11. SUBSEQUENT EVENTS

On April 27, 2011, the Company announced that it had entered into a definitive agreement to sell a substantial portion of its non-core Barnett Shale properties for approximately $104 million, subject to purchase price adjustments. This sale is expected to close in mid-May 2011 and is subject to customary closing conditions. The Company intends to use the net proceeds from this sale to repay borrowings outstanding under the Revolving Credit Facility. As a consequence of the sale, the Borrowing Base availability under the Revolving Credit Facility will be reduced from $350 million to $300 million.

On May 4, 2011, the Company, two of its subsidiaries, which currently hold no assets, CCBM, Inc. and Chama Pipeline Holding LLC, and Wells Fargo Bank, National Association, as Trustee, entered into the Sixth Supplemental Indenture and Seventh Supplemental Indenture to release CCBM, Inc. and Chama Pipeline Holding LLC as Subsidiary Guarantors of the Company’s 8.625% Senior Notes due 2018 and the Company’s 4.375% Convertible Senior Notes due 2028, respectively. These entities are currently being dissolved.

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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 fiscal year ended December 31, 2010, and the unaudited consolidated financial statements included in this quarterly report.

General Overview

Our first quarter 2011 included oil and gas revenues of $44.1 million and production of 10.7 Bcfe. The key drivers to our results for the three months ended March 31, 2011 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the three months ended March 31, 2011, we drilled (a) 18 gross wells (8.3 net) in the Barnett Shale area with a success rate of 100%, (b) 7 gross (1.2 net) wells in the Marcellus Shale area, one gross (0.5 net) of which was unsuccessful, and (c) 4 gross (0.1 net) wells in the Fayetteville Shale area.

Production. Our first quarter 2011 production of 10.7 Bcfe, or 118.8 MMcfe/d, increased 29% from the first quarter 2010 production of 8.3 Bcfe, or 91.9 MMcfe/d, and remained unchanged from fourth quarter 2010 production of 10.7 Bcfe. The increase from the first quarter of 2010 to the first quarter of 2011 was primarily a result of production from new wells in the Barnett Shale, Eagle Ford Shale and the Niobrara Formation, partially offset by normal production decline in the Barnett Shale. The flat production from the fourth quarter of 2010 to the first quarter of 2011 was due primarily to the increased production from new wells in the Eagle Ford Shale and the Niobrara offset by curtailment of our production as a result of inclement weather and normal production decline in the Barnett Shale.

Commodity prices. Our average natural gas price during the first quarter of 2011 was $3.26 per Mcf (excluding the impact of our derivative instruments), $1.23 per Mcf, or 27 % lower than the price during the first quarter of 2010 and $0.35 per Mcf, or 12% higher than the price during the fourth quarter of 2010. Excluded from these prices are realized gains on derivative instruments of $9.9 million ($4.26 per Mcf) for the first quarter of 2011, $10.3 million ($3.91 per Mcf) for the fourth quarter of 2010 and $5.0 million ($5.10 per Mcf) for the first quarter of 2010. Our average oil price during the first quarter of 2011 was $88.65 per barrel, $12.52 per barrel, or 16% higher than the price during the first quarter of 2010 and $4.84 per barrel, or 6% higher than the price during the fourth quarter of 2010. Realized gains attributable to oil were not significant.

Financial flexibility. In April 2011 we entered into an agreement to sell a substantial portion of our non-core Barnett Shale properties for approximately $104 million, subject to purchase price adjustments. This sale is expected to close in mid-May and is subject to customary closing conditions. The sale includes approximately 13,000 leased acres, including 75 gross (58.5 net) wells currently producing at an approximate gross rate of 15.7 MMcfe per day (8.3 MMcfed net). Estimated proved reserves associated with the divested properties amount to 122.4 Bcfe, 55% of which are proved undeveloped, as determined by our third party engineers at year-end 2010. As a consequence of the sale, the Borrowing Base availability under the Revolving Credit Facility will be reduced from $350 million to $300 million. We intend to use the net proceeds from this sale to repay borrowings under our Revolving Credit Facility. Also contributing to our financial flexibility was our entrance into two new credit facilities in the first quarter of 2011.

•

New Senior Secured Revolving Credit Facility. On January 27, 2011, we entered into the Revolving Credit Facility. The Revolving Credit Facility provides for a borrowing capacity up to the lesser of the Borrowing Base and $750 million and matures on January 27, 2016.

•

UK Huntington Limited Recourse Credit Facility. On January 28, 2011, we and Carrizo UK, as borrower, entered into the Huntington Facility. The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea.

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Outlook

Our outlook for 2011 remains positive, but challenging, primarily due to the low futures prices of natural gas. Production growth and commodity prices that permit us to drill, develop and produce at a profit are key to our future success, and we believe the following measures will continue to have a positive impact on our results in 2011:

Eagle Ford and Niobrara. Based upon the success of our drilling results in late 2010 and early 2011, we continue to focus on developing our liquid rich resource plays in the Eagle Ford Shale and the Niobrara Formation. In March 2011, we resumed developing the Eagle Ford Shale by relocating a rig from the Barnett Shale to the Eagle Ford Shale, entered into a three year contract for a second rig to begin work in the second quarter of 2011 and contracted for the delivery of a third drilling rig in the fourth quarter of this year. We continue to obtain and evaluate seismic data in the Niobrara Formation to enhance our drilling opportunities and we recently entered into an 18 month drilling contract that is expected to commence drilling in the Niobrara Formation during the third quarter of 2011. This is in addition to the Niobrara rig we currently have under contract for the drilling of five wells with an option for an additional two wells.

Marcellus Shale. We currently have four rigs under contract in the Marcellus Shale, two of which we operate as part of our Reliance joint venture.

Results of Operations

Three Months Ended March 31, 2011, Compared to the Three Months Ended March 31, 2010

Revenues from oil and gas production for the three months ended March 31, 2011 increased 13% to $44.1 million from $39.0 million for the same period in 2010 primarily due to increased production and higher oil prices. Production volumes were 10.7 Bcfe and 8.3 Bcfe for the three months ended March 31, 2011 and 2010, respectively. The increase in production was primarily attributable to production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline in the Barnett Shale. Average natural gas prices, excluding the impact attributable to a $9.9 million and a $5.0 million realized gain on derivative instruments for the quarters ended March 31, 2011 and 2010, respectively, decreased 27% to $3.26 per Mcf in the first quarter of 2011 from $4.49 per Mcf in the same period in 2010. Average oil prices, excluding the impact attributable to a $0.1 million realized gain on derivative instruments for the quarter ended March 31, 2011, increased 16% to $88.65 per barrel from $76.13 per barrel in the same period in 2010.

The following summarizes production volumes, average sales prices (excluding the impact of gains and losses on derivative instruments) and oil and gas revenues for the three months ended March 31, 2011 and 2010:


	Three Months Ended March 31,				2011 Period Compared to 2010 Period
	2011		2010		Increase (Decrease)			% Increase (Decrease)
Production volumes
Oil and condensate (MBbls)		133		38		95			250	%
Natural gas and NGLs (MMcf)		9,891		8,040		1,851			23	%
Average sales prices
Oil and condensate (per Bbl)	$	88.65	$	76.13	$	12.52			16	%
Natural gas and NGLs (per Mcf)		3.26		4.49		(1.23	)		(27	)%
Oil and gas revenues (In thousands)
Oil and condensate	$	11,830	$	2,874	$	8,956			312	%
Natural gas and NGLs		32,228		36,082		(3,854	)		(11	)%


Total oil and gas revenues	$	44,058	$	38,956	$	5,102			13	%

Lease operating expenses were $6.7 million (or $0.62 per Mcfe) during the three months ended March 31, 2011 as compared to $5.1 million (or $0.61 per Mcfe) for the first quarter of 2010. Increased operating expenses were due to increased production primarily attributable to new wells in the Barnett Shale, Eagle Ford Shale and the Niobrara Formation.

Production taxes remained unchanged at $0.9 million for the three months ended March 31, 2011 and 2010 as the impact of increased production was largely offset by lower gas prices and a severance tax refund attributable to prior periods during the three months ended March 31, 2011.

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Ad valorem taxes decreased 43% to $0.7 million for the three months ended March 31, 2011 from $1.2 million for the same period in 2010. During the first quarter of 2011, we determined that the actual ad valorem taxes for 2010 were lower than amounts estimated in prior year.

DD&A expense for the three months ended March 31, 2011 increased to $16.7 million ($1.56 per Mcfe) from $9.8 million ($1.19 per Mcfe) for the same period in 2010. This increase in DD&A was primarily due to increased production and increased future development costs attributable to crude oil and natural gas liquids reserves added during the fourth quarter of 2010, which have a higher future development cost per equivalent unit than the Company’s existing proved gas reserves.

General and administrative expense increased to $9.2 million for the three months ended March 31, 2011 from $6.9 million for the corresponding period in 2010. The increase was primarily due to (a) increased stock-based compensation largely attributable to stock appreciation rights that increased in fair value during the first quarter of 2011, and (b) increased compensation costs largely due to an increase in the number of employees in the first quarter of 2011.

The net loss on derivative instruments of $0.2 million in the first quarter of 2011 consisted of a $10.2 million unrealized loss on derivatives and a $10.0 million realized gain on derivatives. The net gain on derivative instruments of $22.8 million in the first quarter of 2010 was comprised of a $17.8 million unrealized gain on derivatives and a $5.0 million realized gain on derivatives.

In January 2011, in connection with our entrance into a new senior secured revolving credit facility, we terminated our prior credit facility. As a result, we recognized a non-cash, pre-tax loss on extinguishment of debt of $0.9 million representing the deferred financing costs attributable to the commitments of two banks in the prior credit facility who are not participating in the new credit facility.

Interest expense and capitalized interest for the three months ended March 31, 2011 were $12.2 million and $5.3 million, respectively, as compared to $9.8 million and $4.5 million, respectively, for the same period in 2010. The net increase was primarily due to interest on the $400 million aggregate principal amount of 8.625% Senior Notes which were issued in the fourth quarter of 2010 and higher amortization of deferred financing costs, partially offset by decreased interest and discount amortization attributable to the $300 million aggregate principal amount of the 4.375% Convertible Senior Notes repurchased in the tender offer during the fourth quarter of 2010 and higher capitalized interest due to higher levels of unproved properties and a higher weighted average interest rate in 2011.

Our effective income tax rate was 59.0% for the first quarter of 2011 and 39.2% for the first quarter of 2010. Our estimated annual effective income tax rate for 2011 is approximately 37%, substantially all of which we expect to be deferred. The effective income tax rate for the first quarter of 2011 was higher than 37% primarily due to providing for changes in the current year estimated and prior year actual effective state income tax rate. This increase was partially offset by the income tax benefit of a capital loss associated with our investment in Pinnacle Gas Resources, Inc. which was sold in the first quarter of 2011 for which no income tax benefit was recognized in prior years. We expect to realize the benefit of this capital loss by offsetting it against the capital gain we expect to result from the sale of our non-core Barnett Shale properties in the second quarter of 2011.

Liquidity and Capital Resources

2011 Capital Expenditure Plan and Funding Strategy. For 2011, our Board has established a capital expenditure of $340 million which includes approximately $253 million for drilling (including $129 million in the Eagle Ford Shale, $75 million for the Barnett Shale, $25 million for the Niobrara and $21 million in the Marcellus Shale), $34 million for leasehold and seismic costs and $53 million for the Huntington field development in the U.K. North Sea of which $31 million will be funded by our Huntington Facility – described below with the remaining $22 million funded by the equity investment we made in our U.K. North Sea subsidiary during the first quarter of 2011. We intend to finance the remainder of our 2011 capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors.

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Sources and Uses of Cash. For the three months ended March 31, 2011, capital expenditures, net of proceeds from asset sales, exceeded our net cash provided by operations. During the first quarter of 2011, we funded our capital expenditures with cash provided by operations, payments or carried interest from our joint ventures with Reliance and Avista, and borrowings under our Prior Credit Facility, the Revolving Credit Facility, and the Huntington Facility. Potential sources of future liquidity include the following:

•

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

•

Borrowings under the Revolving Credit Facility. In January 2011, we closed a new $750 million Revolving Credit Facility with a borrowing base of $350 million at March 31, 2011. This facility matures in January 2016 and expanded our ability to enter into project financing arrangements such as our Huntington Facility. At April 29, 2011, $175.0 million of borrowings were outstanding under the Revolving Credit Facility. The Revolving Credit Facility provides that the Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, beginning May 1, 2011. The next borrowing base redetermination is currently expected to occur on or before June 1, 2011 following the sale of certain non-core Barnett Shale properties. At April 29, 2011, we also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the Revolving Credit Facility. 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.

•

Borrowings under project financing arrangements in certain limited circumstances. As described above, we plan to fund a substantial portion of our costs relating to the Huntington Field from our recently established Huntington Facility.

•

Asset sales. In April 2011, we entered into a definitive agreement to sell substantially all of our non-core Barnett Shale properties for approximately $104 million. We intend to use the net proceeds from this sale to repay borrowings under our Revolving Credit Facility and then use the resulting additional capacity under our Revolving Credit Facility to fund, in part, our 2011 capital expenditure plan, and for general corporate purposes. As a consequence of the sale, the Borrowing Base availability under the Revolving Credit Facility will be reduced from $350 million to $300 million. In order to further fund our capital expenditure plan, we may consider additional sales of certain properties or assets, including our interest in the Huntington field development project in the U.K. North Sea, that are not part of our core business, or are no longer deemed essential to our future growth, and provided that we are able to sell such assets on terms that are acceptable to us.

•

Securities offerings. As situations or conditions arise, we may need 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.

•

Lease option agreements and land banking arrangements, such as those we have entered into in the Marcellus Shale, the Barnett Shale and other plays. Please read “Lease Option Arrangements” from our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

•

Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage and/or purchase a portion of interests, such as our joint ventures with Avista and Reliance in the Marcellus Shale play and our joint venture with Sumitomo in the Barnett Shale.

•

We may consider sale/leaseback transactions of certain capital assets, such as our remaining pipelines and compressors, which are not part of our core oil and gas exploration and production business.

Our primary use of cash is capital expenditures related to our drilling and development programs and, to a lesser extent, our lease and seismic data acquisition programs. Our 2011 capital expenditure plan has been established at $340 million and includes approximately $253 million for drilling, $34 million for leasehold and seismic costs and $53 million for the Huntington field development in the U.K. North Sea of which $31 million will be funded by our Huntington Facility with the remaining $22 million funded by the equity investment we made in our U.K. North Sea subsidiary during the first quarter of 2011. The actual amount of investment could vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors.

Overview of Cash Flow Activities. Net cash provided by operating activities were $52.3 million and $27.0 million for the three months ended March 31, 2011 and 2010, respectively. The increase was primarily due to increased production, particularly higher crude oil and condensate production in the Eagle Ford Shale, and higher realized hedge gains, partially offset by lower gas prices in the first three months of 2011 as compared to the same period in 2010.

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Net cash used in investing activities were $98.9 million and $65.6 million for the three months ended March 31, 2011 and 2010, respectively, and increased primarily due to increased capital expenditures during 2011.

Net cash provided by financing activities for the three months ended March 31, 2011 and 2010 was $64.5 million and $37.2 million, respectively. The increase related primarily to increased borrowings under the Revolving Credit Facility during 2011.

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, the sale of non-core assets and borrowings under the Revolving Credit Facility and the Huntington Facility, will be sufficient to fund our immediate cash flow requirements. Cash provided by operating activities is primarily driven by production and commodity prices. While we have steadily increased production over the last few years, spot and futures prices of natural gas continue to remain depressed. 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 program, we hedge a portion of our production and, as of April 29, 2011, we had hedged approximately 17,305,000 MMBtu (71,000 MMBtu per day for the remainder of 2011) of our 2011 natural gas production at a weighted average floor or swap price of $5.64 per MMBtu relative to WAHA and Houston Ship Channel prices. As of April 29, 2011, we have borrowed $175.0 million under our Revolving Credit Facility with a borrowing base of $350 million, which will be reduced to $300 million as a result of the sale of certain non-core Barnett Shale properties which we expect to close in mid-May 2011. At April 29, 2011, we also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the 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 Revolving Credit Facility provides that the Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, 2011. The next borrowing base redetermination is currently expected to occur on or before June 1, 2011 following the sale of certain non-core Barnett Shale properties. The borrowing base is affected by our banks assumptions with respect to future oil and gas prices. Our borrowing base may decrease if our banks reduce their expectations with respect to future oil and gas prices from those assumptions used to determine our existing borrowing base.

If cash provided by operating activities, funds available under the Revolving Credit Facility and the Huntington Facility and the other sources of cash described under “Sources and Uses of Cash” are insufficient to fund our 2011 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives to fund it. 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 our planned 2011 capital expenditure plan, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties.

Contractual Obligations

During the three months ended March 31, 2011, we entered into and extended long-term drilling contracts that require payments of $25.8 million for the remainder of 2011, $20.0 million for 2012, $9.6 million for 2013 and $3.7 million for 2014.

Financing Arrangements

Senior Secured Revolving Credit Facility

On January 27, 2011, we entered into the Revolving Credit Facility which provides for a borrowing capacity up to the lesser of (i) the Borrowing Base and (ii) $750 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of the Company’s assets and is guaranteed by certain of the Company’s subsidiaries. The initial Borrowing Base under the Revolving Credit Facility is $350 million. The Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, beginning May 1, 2011.

We are subject to certain covenants under the terms of the Revolving Credit Facility 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 (a) 4.75 to 1.00 for fiscal quarters ending March 31, 2011 through December 31, 2011, (b) 4.25 to 1.00 for fiscal quarters ending March 31, 2012 through June 30, 2012 and (c) 4.00 to 1.00 for fiscal quarters ending September 30, 2012 and thereafter; (2) a current ratio of not less than 1.0 to

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1.0; (3) a Senior Debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to Interest Expense ratio of not less than 2.50 to 1.00. At March 31, 2011, the ratio of Total Debt to EBITDA was 3.71 to 1.00, the current ratio was 2.06 to 1.0, the Senior Debt to EBITDA ratio was .98 to 1.00 and the EBITDA to Interest Expense ratio was 5.13 to 1.00. 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.

On January 27, 2011, we borrowed $112 million under the Revolving Credit Facility, which was used to repay in full indebtedness outstanding under the Prior Credit Facility, to pay transaction costs associated with the entrance into the Revolving Credit Facility and for other general corporate purposes.

At March 31, 2011, we had $166 million of borrowings outstanding under the Revolving Credit Facility with a weighted average interest rate of 2.7%. At March 31, 2011, we also had $0.3 million in letters of credit outstanding which reduced the amounts available under the Revolving Credit Facility. Future availability under the $350 million borrowing base is subject to the terms and covenants of the Revolving Credit Facility. The Revolving Credit Facility is used to fund ongoing working capital needs and the remainder of our capital expenditure plan only to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

UK Huntington Limited Recourse Credit Facility

On January 28, 2011, the Company and Carrizo UK, as borrower, entered into the Huntington Facility. The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea. The Huntington Facility provides for a multicurrency credit facility consisting of (1) a $55 million term loan facility to be used to fund Carrizo UK’s share of project development costs, (2) a $6.5 million contingent cost overrun term loan facility and (3) a $22.5 million post-completion credit facility providing for loans and letters of credit to be used to fund certain abandonment and decommissioning costs following project completion.

Availability under each of the term loan facility and the cost overrun facility is subject to borrowing bases that are generally based on consolidated cash flow and debt service projections for Carrizo UK attributable to certain proved reserves in the Huntington Field project. The availability under the term loan facility and the cost overrun facility will be redetermined by the lenders at least semi-annually on each April 1 and October 1 in connection with the updating and recalculation of revenue and cash flow projections with respect to the Huntington Field project, except that the first such redetermination and recalculation took place on May 1, 2011 which confirmed the existing ultimate availability discussed above.

Borrowings under the term loan and cost overrun facilities are available until the earlier of December 31, 2012 or the achievement of certain project development milestones. The term loan and cost overrun facilities mature on December 31, 2014, subject to acceleration in the event that future projection estimates of remaining reserves in the project area have declined to less than 25% of the level initially projected by Carrizo UK and the lenders. Letters of credit under the post-completion revolving credit facility mature on December 31, 2016. Amounts outstanding under the term loan or cost overrun facility must currently be repaid according to the following schedule: (i) 45% will be due on December 31, 2012, (ii) 20% will be due on June 30, 2013, (iii) 20% will be due on December 31, 2013, (iv) 10% will be due on June 30, 2014 and (iv) the remaining 5% will be due on the final maturity date of December 31, 2014.

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The Huntington Facility is subject to customary events of default. If an event of default occurs and is continuing, the Majority Lenders may accelerate amounts due under the Huntington Facility.

As of March 31, 2011, no amounts were outstanding under the Huntington Facility and no letters of credit had been issued.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and gas prices. The significant decline in gas prices since mid-2008 and the continued depressed price of gas has resulted in a significant decline in revenue per unit of production. Although operating costs have also declined, the rate of decline in gas prices has been substantially greater. Historically, inflation has had a minimal effect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money supply in recent months, inflation could become a significant issue in the future.

Critical Accounting Policies

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. These policies and estimates are described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010. 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 cost center ceiling exceeded our net capitalized costs for the U.S. cost center at March 31, 2011 by approximately $133.5 million and was based on crude oil and condensate prices of $76.18 per barrel, natural gas liquids prices of $37.02 per barrel and natural gas prices of $3.20 per Mcf (or a volume weighted average price of $4.25 per Mcfe), representing the unweighted average market prices on the first calendar day of each month during the 12-month period ended March 31, 2011. A ten percent increase in the unweighted average market prices for the 12-month period ended March 31, 2011 would have increased the cost center ceiling by approximately $124.5 million and a ten percent decrease in the unweighted average market prices would have resulted in a ceiling test impairment of approximately $35.1 million. This sensitivity analysis is as of March 31, 2011 and, accordingly, does not consider drilling results, production and prices subsequent to March 31, 2011 that may require revisions to our proved reserve estimates.

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, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and gas.

We review the carrying value of our oil and natural gas properties quarterly using the full cost method of accounting rules. See “Summary of Critical Accounting Policies—Oil and Natural Gas Properties,” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

We rely on 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 program. 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 36 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations for the period in which the changes occur.

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The fair value of derivative instruments at March 31, 2011, and December 31, 2010 was a net asset of $14.9 million and $24.1 million, respectively. At March 31, 2011, approximately 67% of the fair value of our derivative instruments were with Credit Suisse, 16% were with Shell Energy North America (US) LP, 10% were with BNP Paribas, 6% were with Credit Agricole, and the remaining 1% were with Societe Generale and master netting agreements are in place with these counterparties. Because the counterparties are either investment grade financial institutions or an investment grade international oil and gas company, 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, BNP Paribas, Credit Agricole, and Societe Generale are lenders in our Revolving Credit Facility, and BNP Paribas and Societe Generale are lenders in our Huntington 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 the Revolving Credit Facility or the Huntington Facility.

The following sets forth a summary of the Company’s natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of March 31, 2011.


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2011		19,255,000	$	5.65	$	5.83
2012		11,623,000	$	5.90	$	6.33
2013		3,650,000	$	5.00	$	5.00

In connection with the derivative instruments above, we have entered into protective put spreads. When the market price declines below the short put price as reflected below, we will effectively receive the market price plus a put spread. For example, for the remainder of 2011, if market prices fall below the short put price of $4.55, the floor price becomes the market price plus the put spread of $1.35 on 11,494,000 of the 19,255,000 MMBtus and the remaining 7,761,000 MMBtus have a floor price of $5.65.


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2011		11,494,000	$	4.55	$	1.35
2012		6,404,000	$	5.17	$	1.09

For the three months ended March 31, 2011 and 2010, we recorded the following related to its derivative instruments:


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Realized gain	$	10,007		$	4,955
Unrealized gain (loss)		(10,194	)		17,847

Gain (loss) on derivative instruments, net	$	(187	)	$	22,802

We deferred the payment of premiums associated with certain of our oil and gas derivative instruments totaling $4.2 million and $3.9 million at March 31, 2011 and December 31, 2010, respectively. We classified $3.0 million and $3.9 million as other current liabilities at March 31, 2011 and December 31, 2010, respectively, and $1.2 million as other non-current liabilities at March 31, 2011. These deferred premiums will be paid to the counterparty with each monthly settlement (April 2011 – March 2014) and recognized as a reduction of realized gain on derivative instruments.

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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, 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, funding for our Marcellus Shale operations, exploration and development expenditures, the impact of our business strategies, the benefits, results, effects, closing and timing of our new and existing joint ventures and sales transactions, 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, activities 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, 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, 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, purchase price adjustments, completion and connection of Barnett wells, and other factors detailed in the “Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 and in our other filings with the SEC. 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 “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A. of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010. 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 fiscal year ended December 31, 2010.

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 March 31, 2011 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.

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Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended March 31, 2011 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

Item 1A. Risk Factors.

There were no material changes to the risk factors previously disclosed in Part 1, Item 1A. “Risk Factors” of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

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

Under the Land Agreement, the Company issued warrants to purchase 57,461 shares of common stock in 2010, warrants to purchase 8,297 and 10,311 shares of common stock on February 1, 2011 and March 4, 2011, respectively.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. (Removed and Reserved).

Item 5. Other Information.

None.

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

	*4.1	—	Sixth Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc. the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee

	*4.2	—	Seventh Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc. the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee

	*4.3	—	Form of Warrant to be issued pursuant to Land Agreement dated November 24, 2009.

	†10.1	—	Credit Agreement dated as of January 27, 2011 among Carrizo Oil & Gas, Inc., as Borrower, BNP Paribas, as Administrative Agent, Credit Agricole Corporate and Investment Bank and Royal Bank of

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		Canada, as Co-Syndication Agents, Capital One, N.A. and Compass Bank, as Co-Documentation Agents, BNP Paribas Securities Corp. as Sole Lead Arranger and Sole Bookrunner, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 2, 2011).

†10.2	—	Senior Secured Multicurrency Credit Facility Agreement dated as of January 28, 2011 among Carrizo UK Huntington Ltd., as Borrower, Carrizo Oil & Gas, Inc., as Parent, and BNP Paribas and Societe Generale as Lead Arrangers, Bookrunners and Original Lenders (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 2, 2011).

*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.

*	Filed herewith.

†	Incorporated by reference as indicated.

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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: May 10, 2011	By:	/s/ Paul F. Boling
		Vice President, Chief Financial Officer and Secretary
		(Principal Financial Officer)

Date: May 10, 2011	By:	/s/ David L. Pitts
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)

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