Edgar Filing: CARRIZO OIL & GAS INC

form10q_033110.htm

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, 2010

[ ] 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		(IRS Employer Identification No.)
	incorporation or organization)

1000 Louisiana Street, Suite 1500, Houston, TX	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):

Large accelerated filer [] Accelerated filer [X]

Non-accelerated filer [ ] Smaller reporting company [ ]

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES [ ] NO [X]

The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of April 30, 2010 was 34,611,408.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

INDEX

PART I. FINANCIAL INFORMATION			PAGE

	Item 1.	Consolidated Balance Sheets
		As of March 31, 2010 (Unaudited) and December 31, 2009	2

		Consolidated Statements of Operations (Unaudited)
		For the three months ended March 31, 2010 and 2009	3

		Consolidated Statements of Cash Flows (Unaudited)
		For the three months ended March 31, 2010 and 2009	4

		Notes to Consolidated Financial Statements (Unaudited)	5

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	16

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24

	Item 4.	Controls and Procedures	25


PART II. OTHER INFORMATION

	Items 1-6.		26

SIGNATURES			27

Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
ASSETS	2010			2009
	(Unaudited)
	(In thousands, except per share amount)
CURRENT ASSETS:
Cash and cash equivalents	$	2,367		$	3,837
Accounts receivable, net
Oil and gas sales		13,027			13,202
Joint interest billing		8,300			4,901
Related party		2,926			445
Other		2,968			2,793
Advances to operators		398			540
Fair value of derivative financial instruments		25,259			8,404
Other current assets		2,528			1,278
Total current assets		57,773			35,400

PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full-cost method of accounting:
Proved oil and gas properties, net		418,427			399,182
Costs not subject to amortization		360,787			330,607
Other property and equipment, net		4,159			3,911
TOTAL PROPERTY AND EQUIPMENT, NET		783,373			733,700
DEFERRED FINANCING COSTS, NET		8,953			9,738
INVESTMENTS		3,341			3,358
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		6,652			6,477
DEFERRED INCOME TAX		62,831			70,217
INVENTORY		3,292			3,292
OTHER ASSETS		1,006			925
TOTAL ASSETS	$	927,221		$	863,107

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Accounts payable, trade	$	18,301		$	19,907
Revenue and royalties payable		28,755			27,390
Accrued drilling costs		14,169			17,251
Accrued interest		6,098			1,922
Other accrued liabilities		7,796			11,120
Advances for joint operations		2,952			1,739
Current maturities of long-term debt		308			148
Deferred income tax		6,761			1,474
Other current liabilities		3,587			1,777
Total current liabilities		88,727			82,728

LONG-TERM DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT		559,741			520,188
ASSET RETIREMENT OBLIGATION		4,382			5,410
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		195			2,818
OTHER LIABILITIES		4,494			4,354

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY:
Common stock, par value $0.01 (90,000 shares authorized; 31,348 and
31,0000 issued and outstanding at March 31, 2010 and
December 31, 2009, respectively)		313			311
Additional paid-in capital		434,107			431,757
Accumulated deficit		(164,812	)		(184,548	)
Accumulated other comprehensive income, net of taxes		74			89
Total shareholders' equity		269,682			247,609
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	927,221		$	863,107

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

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Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended
	March 31,
	2010			2009
	(In thousands except
	per share amounts)
REVENUES:
Oil and gas revenues	$	38,956		$	30,734
Other revenues		468			469

TOTAL REVENUES		39,424			31,203

COSTS AND EXPENSES:
Lease operating		3,751			5,183
Production tax		905			(1,322	)
Ad valorem tax		1,204			897
Transportation, gathering and processing		1,333			3,279
Gas purchases		461			550
Depreciation, depletion and amortization		9,841			15,276
Impairment of oil and gas properties		-			216,391
General and administrative (inclusive of stock-based compensation expense
of $2,164 and $3,426 for the three months ended March 31, 2010
and 2009, respectively)		6,936			7,900
Accretion expense related to asset retirement obligation		51			71

TOTAL COSTS AND EXPENSES		24,482			248,225

OPERATING INCOME (LOSS)		14,942			(217,022	)

OTHER INCOME AND EXPENSES:
Gain on derivatives, net		22,802			30,090
Interest expense		(9,810	)		(9,060	)
Capitalized interest		4,469			4,951
Impairment of investment in Pinnacle Gas Resources, Inc.		-			(2,091	)
Other income, net		30			51

INCOME (LOSS) BEFORE INCOME TAXES		32,433			(193,081	)
INCOME TAX (EXPENSE) BENEFIT		(12,697	)		67,536

NET INCOME (LOSS)	$	19,736		$	(125,545	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES:
Decrease in market value of investment in Pinnacle Gas Resources, Inc.		(15	)		(60	)
Reclassification of cumulative decrease in market value of investment in Pinnacle
Gas Resources, Inc., net of tax		-			1,359

COMPREHENSIVE INCOME (LOSS)	$	19,721		$	(124,246	)

BASIC INCOME (LOSS) PER COMMON SHARE	$	0.64		$	(4.07	)

DILUTED INCOME (LOSS) PER COMMON SHARE	$	0.63		$	(4.07	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		31,071			30,883
DILUTED		31,515			30,883

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

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Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three
	Months Ended
	March 31,
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	19,736		$	(125,545	)
Adjustment to reconcile net income (loss) to net cash provided by operating activities-
Depreciation, depletion and amortization		9,841			15,276
Impairment of oil and gas properties		-			216,391
Unrealized gain on derivative financial instruments		(17,627	)		(11,280	)
Accretion of discount on asset retirement obligation		51			71
Stock-based compensation		2,164			3,426
Allowance for doutbful accounts		123			222
Deferred income taxes		12,682			(67,601	)
Amortization of equity premium associated with Convertible Senior Notes		1,695			1,361
Impairment of investment in Pinnacle Gas Resources, Inc.		-			2,091
Other		674			1,260
Changes in operating assets and liabilities -
Accounts receivable		(3,072	)		(524	)
Other assets		(339	)		(245	)
Accounts payable		(326	)		2,388
Accrued liabilities		1,361			4,443
Net cash provided by operating activities		26,963			41,734

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(60,994	)		(52,869	)
Change in drilling cost accrual		(3,458	)		(14,024	)
Proceeds from the sale of oil and gas properties		592			6
Advances to operators		142			(508	)
Advances for joint operations		(1,716	)		3,600
Other		(156	)		(57	)
Net cash used in investing activities		(65,590	)		(63,852	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		52,600			24,000
Debt repayments		(16,000	)		(3,929	)
Proceeds from stock options exercised		557			-
Payments of financing costs and other		-			(26	)
Net cash provided by financing activities		37,157			20,045

DECREASE IN CASH AND CASH EQUIVALENTS		(1,470	)		(2,073	)

CASH AND CASH EQUIVALENTS, beginning of period		3,837			5,184

CASH AND CASH EQUIVALENTS, end of period	$	2,367		$	3,111

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

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Index

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Carrizo Oil & Gas, Inc., a Texas corporation (“Carrizo” or the “Company”) is an independent energy company engaged in the exploration, development and production of oil and gas, primarily in the Barnett Shale area in North Texas, the Marcellus Shale area in Appalachia, the Eagle Ford Shale in South Texas, the Niobrara formation in Colorado and in other proved onshore trends along the Texas and Louisiana Gulf Coast regions. The Company’s other interests include properties in the U.K. North Sea.

Principles of Consolidation

The consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances. The 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 (“SEC”). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Unconsolidated Investments

The Company accounts for its investment in Pinnacle Gas Resources, Inc. as available-for-sale and adjusts the book value to fair market value through other comprehensive income (loss), net of 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 will be recognized in earnings. Subsequent recoveries in fair value are reflected as increases to investments and other comprehensive income (loss), net of 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 year presentation. These reclassifications had no effect on total assets, total liabilities, shareholders’ equity or net income (loss).

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 consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of unproved properties, future taxable income and related income tax assets/liabilities, the collectability of outstanding accounts receivable, fair values of derivatives, stock-based compensation expense, contingencies and the results of current and future litigation. Oil and natural gas reserve estimates which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

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Index

The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of oil and gas, the credit worthiness of counterparties, interest rates, the market value of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income. Future changes in these assumptions may affect these significant estimates materially in the near term. The Company has evaluated subsequent events for recording and disclosures, including assumptions used in its estimates.

Oil and Gas Properties

Investments in oil and gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company proportionally consolidates its interests in unincorporated joint ventures and oil and gas properties. The Company capitalized employee-related costs for employees working directly on acquisition, exploration and development activities of $1.2 million and $1.5 million for the three months ended March 31, 2010 and 2009, respectively. Maintenance and repairs are expensed as incurred.

Depreciation, depletion and amortization (“DD&A”) of proved oil and gas properties is based on the unit-of-production method using estimates of proved reserve quantities. The depletable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for the quarters ended March 31, 2010 and 2009 was $1.16, and $1.83, respectively. Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved oil and gas reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of the oil and gas properties (excluding unproved properties, capitalized interest and exploratory wells in progress) and estimated future development costs less salvage value to calculate the depletion expense.

Costs not subject to amortization include costs of unproved properties (which consists of unevaluated leaseholds and seismic costs associated with specific unevaluated properties), capitalized interest and exploratory wells in progress. These costs are evaluated periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties have been impaired, the amount of such impairment is determined and added to the proved oil and gas property costs subject to DD&A. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production, production response to secondary activities and available funds for exploration and development. The Company expects it will complete its evaluation of the properties representing the majority of its unproved property costs within the next two to five years. The Company capitalized interest costs associated with its unproved properties of $4.5 million and $5.0 million for the three months ended March 31, 2010 and 2009, respectively.

Dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to a “ceiling-test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. If net capitalized costs exceed this limit, the excess is charged to earnings. For the first quarter of 2009, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by SEC guidelines in effect at the time, to measure the full cost ceiling test impairment. Using prices as of May 6, 2009, the Company incurred an impairment charge of $216.4 million ($140.7 million net of tax). Had the Company used prices in effect as of March 31, 2009, an impairment charge of $323.2 million ($210.1 million net of tax) would have been recorded for the first quarter of 2009. The option to use a pricing date subsequent to the balance sheet is no longer available to the Company due to the adoption of the new oil and gas reporting requirements effective December 31, 2009. Prices used in the ceiling test computation do not include the impact of hedges as the Company’s derivative instruments are treated as non-designated derivatives.

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

Stock-Based Compensation

The Company grants stock options, including stock appreciation rights (“SARs”) that settle in the Company’s common stock, and restricted stock to directors, employees and independent contractors.

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Index

For stock options, including SARs that settle in common stock, compensation expense is based on the grant-date fair value of the option and recognized in equity at the grant date and expensed over the vesting period. Stock options typically expire ten years after the date of grant. SARs expire seven years after the date of grant. SARs that settle in cash are valued at each reporting period date and an expense and liability are recognized over the vesting period.

For restricted stock, the Company measures deferred compensation based on the average of the high and low price of the Company’s stock on the grant date. The deferred compensation is amortized to stock-based compensation expense ratably over the vesting period of the restricted shares (generally one to three years), using the straight-line method, except for awards with performance conditions, in which case we use the graded vesting method. Restricted stock issued to independent contractors that vest over time as services are provided is adjusted to fair value at each reporting period with the change in fair value being recorded to expense over the requisite service period.

The Company recognized the following stock-based compensation expense for the periods indicated, which are reflected as general and administrative expense in the accompanying statements of operations:

	For the Three Months
	Ended March 31,
	2010		2009
	(In millions)
Stock Option and SARs	$	0.4	$	-
Restricted Stock		1.8		3.4

Total Stock-Based Compensation	$	2.2	$	3.4

Derivative Instruments

The Company uses derivatives, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage price risk underlying its oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its derivative instruments as a cash flow hedge, such derivative instruments provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, we recognize all unrealized and realized gains and losses related to these contracts currently in earnings and are classified as gain(loss) on derivatives, net in our consolidated statements of operations.

The Company’s Board of Directors sets all risk management policies and reviews volume limitations, 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 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. The Board of Directors also reviews the status and results of derivative activities at least quarterly. See Note 8, “Derivative Financial Instruments” for further discussion of the Company’s derivative activities.

Accounts Receivable and Allowance for Doubtful Accounts

At March 31, 2010 and December 31, 2009, the Company had related party receivables of $2.9 million and $0.4 million, respectively, with ACP II Marcellus, LLC, a private equity fund, related to the Company’s operations in the Marcellus Shale.

The Company establishes provisions for losses on accounts receivable when it determines that it will not collect all or a part of the outstanding balance. The Company reviews collectability quarterly and adjusts the allowance as necessary using the specific identification method. At March 31, 2010 and December 31, 2009, the Company’s allowance for doubtful accounts was $2.2 million and $2.0 million, respectively.

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Index

Earnings Per Share

Supplemental earnings per share information is provided below:

	For the Three Months
	Ended March 31,
	2010		2009
	(In thousands, except
	per share amounts)
Net income (loss)	$	19,736	$	(125,545	)

Average common shares outstanding
Weighted average common shares outstanding		31,071		30,883
Restricted stock and stock options		444		-
Diluted weighted average common shares outstanding		31,515		30,883

Net income (loss) per common share
Basic	$	0.64	$	(4.07	)
Diluted	$	0.63	$	(4.07	)

Basic earnings per common share is based on the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential common shares outstanding during the periods. The Company excluded 39,121 shares related to restricted stock and stock options from the calculation of dilutive shares for the three months ended March 31, 2010 because the grant prices were greater than the average market price of the common shares for the first quarter of 2010 and would be antidilutive to the computation. The Company did not include 685,854 of stock options in the calculation of dilutive shares for the three months ended March 31, 2009 due to the net loss reported in the period. Shares of common stock subject to issuance pursuant to the conversion features of the 4.375% convertible senior notes due 2028 (the “Convertible Senior Notes”) did not have an effect on the calculation of dilutive shares for the three months ended March 31, 2010 and 2009.

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 future taxable income based upon the Company’s estimated 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.

Recently Adopted Accounting Pronouncements

A standard to improve disclosures about fair value measurements was issued by the Financial Accounting Standards Board (the “FASB”) in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuance and settlements for the rollforward of Level 3 activity and (4) the transfers in and out of Levels 1 and 2. The Company adopted the new disclosures in the first quarter of 2010.

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Index

2.	INVESTMENTS

Investments consisted of the following at March 31, 2010 and December 31, 2009:

	March 31,		December 31,
	2010		2009
	(In thousands)
Pinnacle Gas Resources, Inc.	$	818	$	835
Oxane Materials, Inc.		2,523		2,523

	$	3,341	$	3,358

Pinnacle Gas Resources, Inc.

In 2003, the Company and its wholly-owned subsidiary CCBM, Inc. contributed their interests in certain natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”).

At March 31, 2009, the market value of the Company’s investment in Pinnacle had consistently remained below its original book basis since October 2008. The Company determined that the impairment was other than temporary and, accordingly, recorded an impairment expense of $2.1 million at March 31, 2009. At March 31, 2010, the Company reported the fair value of the stock at $0.8 million (based on the closing price of Pinnacle’s common stock on March 31, 2010).

On February 23, 2010, Pinnacle entered into an Agreement and Plan of Merger (the “Merger Agreement”) with affiliates of Scotia Waterous (USA), Inc. At the closing of the transactions contemplated by the Merger Agreement, Pinnacle is expected to be owned by an investor group led by Scotia Waterous (USA), Inc., which includes DLJ Merchant Banking Partners III, L.P. and affiliated investment funds and certain members of Pinnacle’s management team.

Subject to the terms and conditions of the Merger Agreement, at the effective time and as a result of the Merger, each outstanding share of Pinnacle common stock, (other than dissenting shares and those owned by the buyers and affiliates) will be converted into the right to receive a cash amount of $0.34 per share. As of March 31, 2010, the Company owned 2,555,825 shares of Pinnacle common stock.

Oxane Materials, Inc.

In May 2008, the Company entered into a strategic alliance agreement with Oxane Materials, Inc. (“Oxane”) in connection with the development of a proppant product to be used in the Company’s exploration and production program. The Company contributed approximately $2.0 million to Oxane in exchange for warrants to purchase Oxane common stock and for certain exclusive use and preferential purchase rights with respect to the proppant. The Company simultaneously invested an additional $500,000 in a convertible promissory note from Oxane. The convertible promissory note accrued interest at a rate of 6% per annum. During the fourth quarter of 2008, the Company converted the promissory note into 630,371 shares of Oxane preferred stock.

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3.	PROPERTY AND EQUIPMENT, NET

At March 31, 2010 and 2009, property and equipment, net consisted of the following:

	March 31,			December 31,
	2010			2009
	(In thousands)
Proved oil and gas properties	$	696,743		$	667,907
Costs not subject to amortization:
Unevaluated leaseholds and seismic costs		271,477			258,300
Capitalized interest		37,455			34,563
Exploratory wells in progress		51,855			37,744
Land, building and other equipment		6,902			6,475
Total property and equipment		1,064,432			1,004,989

Accumulated depreciation, depletion and amortization		(281,059	)		(271,289	)
Property and equipment, net	$	783,373		$	733,700

4.	INCOME TAXES

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35% to pretax income (loss) as follows:

	For the
	Three Months Ended
	March 31,
	2010		2009
Provision (benefit) at the statutory rate	$	11,352	$	(67,578	)
State and local income taxes, net of federal benefit		1,334		66
Other		11		(24	)
Total income tax expense (benefit)	$	12,697	$	(67,536	)

At March 31, 2010, the Company had a net deferred tax asset of $56.1 million. The Company has determined it is more likely than not that its deferred tax assets are fully realizable based on projections of future taxable income which included estimated production of proved reserves at estimated future pricing. No valuation allowance for the net asset is currently needed.

The Company classifies interest and penalties associated with income taxes as interest expense. At March 31, 2010, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

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5.	LONG-TERM DEBT

Long-term debt consisted of the following at March 31, 2010 and December 31, 2009:

	March 31,			December 31,
	2010			2009
	(In thousands)
Convertible Senior Notes	$	373,750		$	373,750
Unamortized discount for Convertible Senior Notes		(42,008	)		(45,122	)
Senior Secured Revolving Credit Facility		228,000			191,400
Other		307			308
		560,049			520,336
Less: Current maturities		(307	)		(148	)

	$	559,742		$	520,188

Convertible Senior Notes

In May 2008, the Company issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (the “Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year. The notes will be convertible, using a net share settlement process, into a combination of cash and Carrizo common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of the Company’s conversion obligation in excess of such principal amount.

The notes are convertible into the Company’s common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate).

Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of the Company’s common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of the Company’s common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028.

The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Senior Credit Facility (defined below), the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.

The Convertible Senior Notes are unsecured obligations of the Company and rank equal to all future senior unsecured debt but rank second in priority to the Senior Credit Facility.

In accordance with the accounting guidelines for convertible debt, the Company valued the Convertible Senior Notes at May 21, 2008, as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium. The resulting debt discount is being amortized to interest expense through June 1, 2013, the first date on which the holders may require the Company to repurchase the Convertible Senior Notes, which will result in an effective interest rate of approximately 8% for the Convertible Senior

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Notes. Amortization of the debt discount amounted to $3.1 million and $12.1 million for the three months ended March 31, 2010 and for the year ended December 31, 2009, respectively.

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility (the “Senior Credit Facility”) with Wells Fargo Bank, N.A., administrative agent. The Senior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base and, as of $375.0 million (as of May 5, 2010). It is secured by substantially all of the Company’s proved oil and gas assets and is currently guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus), LLC; Carrizo Marcellus Holdings, Inc.; Hondo Pipeline Inc.; Bandelier Pipeline Holding, LLC and Mescalero Pipeline, LLC.

The Senior Credit Facility matures on October 29, 2012, and is subject to semi-annual borrowing base redetermination dates on March 31 and September 30.

In April 2009, the Company amended the Senior Credit Facility to, among other things, (1) adjust the maximum ratio of total net debt to Consolidated EBITDAX; (2) modify the calculation of total net debt for purposes of determining the ratio of total net debt to Consolidated EBITDAX to exclude the following amounts, which represent a portion of the Convertible Senior Notes deemed to be an equity component under the accounting guidelines related to convertible debt that may be settled in cash (including partial cash settlement) upon conversion: $51.3 million during 2009, $38.9 million during 2010, $26.0 million during 2011 and $12.7 million during 2012 until the maturity date; (3) add a new senior leverage ratio; (4) modify the interest rate margins applicable to Eurodollar loans; (5) modify the interest rate margins applicable to base rate loans; and (6) establish new procedures governing the modification of swap agreements.

In May 2009, the Company amended the Senior Credit Facility to, among other things, (1) provide that the aggregate notional volume of oil and gas subject to swap agreements may not exceed 80% of “forecasted production from proved producing reserves,” (as that term is defined in the Senior Credit Facility), for any month, (2) remove a provision that limited the maximum duration of swap agreements permitted under the Senior Credit Facility to five years, and (3) provide that the aggregate notional amount under interest rate swap agreements may not exceed the amount of borrowings then outstanding under the Senior Credit Facility.

If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, the Company has the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.

The annual interest rate on each base rate borrowing is (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 1.00% and 2.00% (depending on the then-current level of borrowing base usage), but such interest rate can never be lower than the adjusted Daily LIBO rate on such day plus a margin between 2.25% to 3.25% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted daily LIBO rate plus a margin between 2.25% to 3.25% (depending on the then-current level of borrowing base usage). At March 31, 2010, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.1%.

The Company is subject to certain covenants under the amended terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.00 to 1.00 (as defined in the Senior Credit Facility); and (2) a maximum total net debt to Consolidated EBITDAX (as defined in the Senior Credit Facility) of (a) 4.75 to 1.00 for each quarter ending on or after December 31, 2009 and on or before September 30, 2010, (b) 4.25 to 1.00 for the quarter ending December 31, 2010, and (c) 4.00 to 1.00 for each quarter ending on or after March 31, 2011; and (3) a maximum ratio of senior debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDAX of 2.25 to 1.00.

The Senior Credit Facility also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.

The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.

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At March 31, 2010, the Company had $228.0 million of borrowings outstanding under the Senior Credit Facility, and the amount available for borrowings was $122.0 million which can be used to fund working capital and the Company’s capital expenditure plan to the extent such amounts exceed the cash flow from operations subject to the terms and covenants of the Senior Credit Facility.

6.	ASSET RETIREMENT OBLIGATION

The following table is a reconciliation of the asset retirement obligation:

	For the Three			For the
	Months Ended			Year Ended
	March 31,			December 31,
	2010			2009
	(In thousands)
Asset retirement obligation at beginning of period	$	5,410		$	6,503
Liabilities incurred		51			444
Liabilities settled		-			(36	)
Accretion expense		51			308
Revisions of previous estimates		(1,130	)		(1,809	)
Asset retirement obligation at end of period	$	4,382		$	5,410

The revisions of previous estimates relate primarily to increases in the estimated life of wells in the Barnett Shale and the reduction of estimated obligations in the North Sea.

7.	COMMITMENTS AND CONTINGENCIES

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a 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 natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

8.	DERIVATIVE FINANCIAL INSTRUMENTS

The Company typically uses fixed-rate swaps, costless collars, puts, calls and basis differential swaps to manage price risk associated with a portion of anticipated future oil and gas production. While the use of derivative financial instruments limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, 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 enters into the majority of its derivative transactions with three counterparties and netting agreements are in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price and credit risk. The Company has additional price risk since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the financial instruments.

The following table sets forth a summary of our natural gas derivative volumes and average Houston Ship Channel and Waha prices as of March 31, 2010.

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		Volume		Average		Average
Period	Contracts	(in MMbtu)		Floor Price		Ceiling Price
2010	Swaps		6,893,000	$	5.74	$	5.74
2010	Collars		8,776,000		5.71		6.72
2010	Long Puts		3,210,000		5.17
			18,879,000

2011	Swaps		5,016,000		5.74		5.74
2011	Collars		6,749,000		6.73		8.59
2011	Long Puts		5,475,000		5.08
			17,240,000

2012	Swaps		1,559,000		6.55		6.55
2012	Collars		6,404,000		6.48		8.30
2012	Long Puts		-
			7,963,000

In addition to the hedged volumes above, Carrizo owns protective put spreads with a weighted average spread of $1.54 on 10,061,000 MMbtu for 2010, $1.27 on 14,049,000 MMbtu for 2011, and $1.42 on 6,404,000 for 2012.

For the three months ended March 31, 2010 and 2009, the Company recorded the following related to its derivatives:

	For the Three Months
	Ended March 31,
	2010		2009
	(In millions)
Realized gain on oil and gas derivatives	$	5.0	$	18.8
Unrealized gain on oil and gas derivatives		17.8		11.3
Gain on derivatives, net	$	22.8	$	30.1

The Company purchased certain hedge positions and deferred the payment of the premium of $6.8 million and $4.8 million at March 31, 2010 and December 31, 2009, respectively. The Company classified $3.6 million and $1.8 million as other current liabilities at March 31, 2010 and December 31, 2009, respectively, and $3.2 million and $3.0 million as other non-current liabilities at March 31, 2010 and December 31, 2009, respectively.

At March 31, 2010, approximately 47% of the Company’s open natural gas hedged volumes were with Credit Suisse, 40% were with Shell Energy North America (US) LP, and the remaining 13% were with Credit Agricole.

The fair value of the outstanding derivatives at March 31, 2010 and December 31, 2009 was a net asset of $31.7 million and $12.1 million, respectively.

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.

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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.

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

	March 31, 2010								December 31, 2009
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in thousands)
Assets:
Investment in Pinnacle
Gas Resources, Inc.	$	818	$	-	$	-	$	818	$	835	$	-	$	-	$	818
Oil and gas derivatives		-		63,639		-		63,639		-		48,192		-		48,192
Liabilities:
Oil and gas derivatives		-		31,923		-		31,923		-		36,129		-		36,129

Total	$	818	$	31,716	$	-	$	32,534	$	835	$	12,063	$	-	$	12,898

The derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our consolidated balance sheet.

Oil and gas derivatives are valued by using valuation models that are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. We had no transfers in or out of Levels 1 or 2 for the three months ended March 31, 2010.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and bank borrowings, including borrowings under the Senior Credit Facility. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank and vendor borrowings approximate the carrying amounts as of March 31, 2010 and December 31, 2009, and were determined based upon interest rates currently available to the Company for borrowings with similar terms. The fair value of the Convertible Senior Notes at March 31, 2010 was estimated at approximately $330.3 million based on a quote provided by an investment bank.

10.	SUBSEQUENT EVENTS

In April 2010, the Company sold 3.22 million shares of its common stock in an underwritten public offering at a price of $23.00 per share. The Company received proceeds of approximately $74.1 million, and used the funds to repay borrowings under its revolving credit facility.

Effective May 5, 2010, the Company amended the Senior Credit Facility to increase the borrowing base to $375 million from $350 million, representing an increase of $25 million. As of April 30, 2010, the outstanding balance under the Senior Credit Facility was approximately $163 million (or 43% of a $375 million borrowing base) representing available liquidity of $212 million.

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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 certain significant factors that have affected certain aspects of the Company’s financial position and results of operations during the periods included in the accompanying unaudited 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 financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 and the unaudited financial statements included in this quarterly report.

General Overview

Our first quarter 2010 included oil and gas revenues of $39.0 million and production of 8.3 Bcfe. The key drivers to our results for the three months ended March 31, 2010 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the three months ended March 31, 2010, we drilled (1) 21 gross wells (11.6 net wells) in the Barnett Shale area with an apparent success rate of 100%, (2) two gross (0.5 net) wells in the Gulf Coast and (3) one gross (0.5 net) well in the Marcellus Shale. At March 31, 2010 we had an inventory of 50 gross wells (33.1 net) in the Barnett Shale that have been drilled and are waiting on hydraulic fracturing, completion or pipeline connection.

Production. Our first quarter 2010 production of 8.3 Bcfe, or 91.9 MMcfe/d was relatively flat compared to first quarter 2009 production of 8.3 Bcfe, or 91.8 MMcfe/d. The first quarter 2010 production decreased 5% from the fourth quarter 2009 production of 8.7 Bcfe, or 94.4 MMcfe/d in the previously disclosed joint venture with Sumitomo, primarily as a result of normal production declines and the sale of a portion of our working interest in certain Barnett Shale wells during the fourth quarter of 2009.

Commodity prices. Our average natural gas price during the first quarter of 2010 was $4.49 per Mcf (excluding the impact of our hedges), $0.86 per Mcf, or 24%, higher than the price in the first quarter of 2009 and $1.01 per Mcf, or 29%, higher than the price in the fourth quarter of 2009.

Financial flexibility. In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price of $23.00 per share. We used the net proceeds of approximately $74.1 million to repay borrowings under our revolving credit facility. We expect to fund, in part, our recently expanded capital expenditure plan for 2010 with the available capacity under the revolver. On May 5, 2010, the borrowing base of our Senior Credit Facility increased from $350 million to $375 million, representing a $25 million increase.

Recent Developments

New Growth Strategy and Increased Capital Expenditure Plan

On April 8, 2010, we announced an additional growth strategy in crude oil and liquids-rich plays. We are attempting to increase significantly the level of our crude oil and liquids production and reserves by as early as the first quarter of 2011. As part of this effort, we have completed the acquisition of acreage and are pursuing additional land acquisitions in an unconventional play that is rich in condensate and natural gas liquids located in the Eagle Ford shale formation (the “Eagle Ford Shale”), principally in LaSalle County, Texas. We are also pursuing land acquisitions in an unconventional oil play located in the Niobrara formation in the Denver-Julesberg basin (the “Niobrara”) in Weld County, Colorado.

Upon completion of our public equity offering described above, our Board of Directors increased our 2010 capital expenditure plan from $170 million to $225 million. The increase in our capital expenditure plan is expected to be allocated as follows:

·	$30 million for acreage acquisitions, which includes approximately 9,000 acres already acquired, acquisition of additional acreage and for drilling two horizontal wells in the Eagle Ford Shale this year; and

·	$25 million for acreage acquisitions, which includes a recently completed 45,800 net acre acquisition, the acquisition of additional acreage, and drilling two to three horizontal wells in the Niobrara this year.

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Eagle Ford Leasing Update. During the first quarter of 2010, we commenced leasing in the condensate and liquids-rich portions of the Eagle Ford Shale. As of April 30, 2010, we have closed on approximately 9,000 net acres, and we have targeted to acquire at least an additional 5,100 acres in the play. We currently intend to commence drilling two horizontal wells on this acreage in mid-2010.

Niobrara Acquisition. We have acquired approximately 45,800 net leasehold acres held by the seller in an unconventional oil play located in the Weld County, Colorado portion of the Niobrara. We currently anticipate that our first Niobrara well could spud in the third quarter of 2010. We have acquired a 100% working interest in all leases subject to the transaction. The seller has retained the option to participate for up to a fully participating non-carried 12.5% working interest, on a well by well basis, in all drilling operations in the area of mutual interest established in connection with this transaction. Our revised capital expenditure plan includes the drilling of two to three horizontal wells in the Niobrara during 2010 and the acquisition of additional acreage as well. We are currently negotiating to acquire at least an additional 11,000 acres in this new core area.

Outlook

Our outlook for 2010 is challenging, primarily as a result of the decline in gas prices that began in mid 2008, but our outlook for the long-term future remains positive. 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 have a positive impact on our results in 2010:

As described above, we plan to increase the level of our crude oil and liquids production and reserves in our portfolio of drilling areas by as early as the first quarter of 2011. Since the beginning of the year, we acquired acreage positions and plan to drill in the Eagle Ford Shale, principally in LaSalle County, Texas and in the Niobrara formation in the Denver-Julesburg basin in Weld County, Colorado.

We plan to continue the exploration and development activities in the Marcellus Shale in the Northeastern United States, primarily through joint ventures with ACP II Marcellus, LLC and with other industry partners. Among other activities, we currently plan to drill one gross (0.5 net) vertical wells and fracture stimulate four gross (2.0 net) previously drilled vertical wells in the West Virginia portion of the Marcellus Shale to test the prospectivity of that area. In the later part of 2009, we started drilling two wells in Pennsylvania and plan to drill a third well pending further seismic data interpretation.

In connection with our recent equity offering and our new strategy to enter into crude oil and liquids-rich plays, we have increased our 2010 capital expenditure plan from $170 million to $225 million, which currently includes $147 million for drilling, $76 million for land and seismic acquisitions and $2 million for the pre-development work of our Huntington Field in the North Sea.

·	We expect to continue to hedge production to limit our exposure to reductions in natural gas prices. At March 31, 2010, we had hedged approximately 44,082,000 MMBtus of natural gas production through 2012.

Results of Operations

Three Months Ended March 31, 2010,

Compared to the Three Months Ended March 31, 2009

Revenues from oil and gas production for the three months ended March 31, 2010 increased 27% to $39.0 million from $30.7 million for the same period in 2009 due to increased oil and gas prices. Production volumes for natural gas for the three months ended March 31, 2010 was 8.0 Bcf in 2010 and 2009. Average natural gas prices, excluding the impact attributable to a $5.0 million and a $16.0 million cash-settled gain for the quarters ended March 31, 2010 and 2009, respectively, increased to $4.49 per Mcf in the first quarter of 2010 from $3.63 per Mcf in the same period in 2009. Average oil prices, excluding the impact of our settled derivative gain of $2.8 million for the quarter ended March 31, 2009, increased 93% to $76.13 per barrel from $39.38 per barrel in the same period in 2009.

The following table summarizes production volumes, average sales prices (excluding the impact of derivatives) and oil and gas revenues for the three months ended March 31, 2010 and 2009:

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	For the				2010 Period
	Months Ended				Compared to 2009 Period
	March 31,				Increase			% Increase
	2010		2009		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		38		44		(6	)		(14	)%
Natural gas (MMcf)		8,040		7,994		46			1	%
Average sales prices
Oil and condensate (per Bbl)	$	76.13	$	39.38	$	36.75			93	%
Natural gas (per Mcf)		4.49		3.63		0.86			24	%
Operating revenues (In thousands)
Oil and condensate	$	2,874	$	1,734	$	1,140			66	%
Natural gas		36,082		29,000		7,082			24	%

Total oil and gas revenues	$	38,956	$	30,734	$	8,222			27	%

Lease operating expenses for the three months ended March 31, 2010 decreased 28% to $3.8 million from $5.2 million for the same period in 2009, primarily as a result of a general decline in oilfield services and lower workover expenses in the first quarter of 2010.

Production taxes increased from a credit of $(1.3) million in the first quarter of 2009 to $0.9 million for the same period in 2010 as a result of a tax credit received in 2009.

Ad valorem taxes increased 34% to $1.2 million for the three months ended March 31, 2010 from $0.9 million for the same period in 2010 as a result of new wells drilled in 2009.

Transportation, gathering and processing costs decreased 59% to $1.3 million for the first quarter of 2010 primarily as a result of a change in pricing and transportation contractual arrangements effective July 1, 2009.

Depreciation, depletion and amortization (DD&A) expense for the three months ended March 31, 2010 decreased 36% to $9.8 million ($1.19 per Mcfe) from $15.3 million ($1.85 per Mcfe) for the same period in 2009. This decrease in DD&A was primarily due to a lower depletion rate resulting from impairment charges that reduced the depletable full-cost pool in the first and fourth quarters of 2009 and due to lower overall finding costs of new reserves added primarily in the fourth quarter of 2009.

Due to low oil and gas prices during 2009, indicated by average posted prices of $3.17 per Mcf for natural gas and $51.76 per Bbl for oil on May 6, 2009, the discounted present value (discounted at ten percent) of future net cash flows from our proved oil and gas reserves fell below our net book basis in the proved oil and gas properties. This resulted in a non-cash, ceiling test write-down at March 31, 2009 of $216.4 million ($140.7 million after tax). There was no such write-down at March 31, 2010.

General and administrative expense decreased to $6.9 million for the three months ended March 31, 2010 from $7.9 million for the corresponding period in 2009. The decrease was due primarily to lower non-cash, stock-based compensation of $1.2 million including additional compensation awards issued in the first quarter of 2009 related to payment of 2008 discretionary bonuses to non-executive employees in Company stock.

The net gain on derivatives of $22.8 million in the first quarter of 2010 was comprised of a $17.8 million of unrealized mark-to-market gain on natural gas derivatives and a $5.0 million of realized gain on settled natural gas derivatives. The net gain on derivatives of $30.1 million in the first quarter of 2009 was comprised of a $11.3 million net unrealized mark-to-market gain on derivatives and a $18.8 million realized gain on settled derivatives.

Interest expense and capitalized interest for the three months ended March 31, 2010 were $9.8 million and $4.5 million, respectively, as compared to $9.1 million and $5.0 million, respectively for the same period in 2009. The increase was primarily due to higher debt levels under the Senior Credit Facility and lower levels of capitalized interest.

Our overall tax effective rate was 39.2% for the first quarter of 2010 and 35.0% for the first quarter of 2009. The increase in the effective tax rate was due to higher state income taxes during 2010.

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Liquidity and Capital Resources

2010 Capital Budget and Funding Strategy. In connection with our recent equity offering and our new strategy to enter into crude oil and liquids-rich plays, we have increased our 2010 capital expenditure plan from $170 million to $225 million which currently includes $147 million for drilling, $76 million for land and seismic acquisitions and $2 million for the development of the North Sea. If our development plan for the Huntington Field is approved by our joint venture during 2010, we may be required to invest up to an additional $20.0 million in facilities and drilling to develop this field in 2010. We currently intend to project finance all or a portion of the additional Huntington field development costs. We intend to finance our 2010 capital and exploration budget primarily from cash flows from operations, the possible selective sale or monetization of non-core assets and available borrowings under the Senior Credit Facility. We may be required to reduce or defer part of our 2010 capital expenditures program if we are unable to obtain sufficient financing from these sources or if natural gas prices decline.

Sources and Uses of Cash. During the three months ended March 31, 2010, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations. During 2010, we have funded our capital expenditures with cash generated from operations and net additional borrowings under the Senior Credit Facility, including borrowing capacity made available by the paydown of the facility, with proceeds of our common stock offering. 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 oil and gas field services. We hedge a portion of our production to reduce the downside risk of declining oil and gas prices.

Borrowings under the Senior Credit Facility. On May 5, 2010, we amended our Senior Credit Facility to increase the borrowing base to $375 million from $350 million, representing an increase of $25 million. As of April 30, 2010, the outstanding balance under the Senior Credit Facility was approximately $163 million (or 43% of a $375 million borrowing base) representing available liquidity of $212 million.

Asset sales. In order to fund our capital and exploration budget, we may consider the sale of certain properties or assets that are not part of our core business, or are no longer deemed essential to our future growth, if we are able to sell such assets on terms that are acceptable to us. We may consider the sale of additional non-core assets including the possible sale of our interest in the Huntington Field located in the North Sea, provided that we can obtain terms that are acceptable to us.

·	Debt and equity offerings. In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price of $23.00 per share. We used the net proceeds of approximately $74.1 million to repay borrowings under our revolving credit facility.

·	Project financing in certain limited circumstances, particularly to fund all or a portion of our future development costs for the Huntington Field in the U.K. North Sea.

·	Lease option agreements and land banking arrangements, such as those we have entered into in the past regarding the Marcellus Shale, the Barnett Shale and other plays.

·	Joint ventures through which parties fund a portion of our land acquisition exploration activities to earn an interest in our exploration acreage, such as our joint venture 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 pipelines and compressors, which are not part of our core oil and gas exploration and production business.

In 2010 we currently plan to drill 57 gross (38.1 net) wells in the Barnett Shale area, 11 gross (3.8 net) wells in the Marcellus shale area, two gross (2.0 net) wells in the Eagle Ford Shale, three gross (3.0 net) wells in the Niobrara formation and three gross (1.5 net) wells in our other areas. The actual number of wells drilled and capital expended depends on our available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. Capital expenditures do not include operating costs such as the steam costs that will be required for the multi-year development of our Camp Hill project. In addition to our capital expenditure program, we have contractual obligations as discussed below.

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Overview of Cash Flow Activities. Cash flows provided by operating activities were $27.0 million and $41.7 million for the three months ended March 31, 2010 and 2009, respectively. The decrease was primarily due to a higher amount of cash settled hedges on our natural gas production in 2009 as compared to 2010.

Cash flows used in investing activities were $65.6 million and $63.9 million for the three months ended March 31, 2010 and 2009, respectively, and increased slightly primarily to increased oil and gas property expenditures during 2010 as compared to 2009.

Net cash provided by financing activities for the three months ended March 31, 2010 and 2009 was $37.2 million and $20.0 million, respectively. The increase related primarily to net borrowings under the Senior Credit Facility.

Liquidity/Cash Flow Outlook.

We currently believe that cash generated from our April 2010 equity offering and from operations, supplemented by borrowings under the Senior Credit Facility, will be sufficient to fund our immediate needs. Cash generated from operations is primarily driven by production and commodity prices. While we have steadily increased production over the last few years, natural gas prices declined significantly since the third quarter of 2008. In an effort to mitigate declining prices, we hedge a portion of our production and, as of March 31, 2010, we had hedged approximately 18,879,000 MMBtu (68.7 MMcf per day for the year, or 72% of our estimated production from April through December 2010) of our 2010 natural gas production at a weighted average floor or swap price of $5.63 per MMBtu relative to WAHA and Houston Ship Channel prices. On May 5, 2010, we amended the Senior Credit Facility to increase the borrowing base to $375 million from $350 million, representing an increase of $25 million. As of April 30, 2010, the outstanding balance under our credit facility was approximately $163 million (or 43% of a $375 million borrowing base) representing available liquidity of $212 million, subject to the terms of the covenants of the Senior Credit Facility.

If cash from operations, funds available under the Senior Credit Facility and the other sources of cash described under “Sources and Uses of Cash” are insufficient to fund our 2010 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 2010 oil and gas exploration and development program, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties.

Contractual Obligations

During the first quarter of 2010, we entered into long-term transportation in the Marcellus Shale play that requires minimum volume commitments valued at $0.9 million for 2010, $1.5 million for 2011, $2.9 million for 2012, $5.9 million for 2013 and $11.7 million thereafter.

Financing Arrangements

In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price of $23.00 per share. We used the net proceeds of approximately $74.1 million to repay borrowings under our revolving credit facility. We expect to fund in part, our recently expanded capital expenditure plan for 2010 with the available capacity under the revolver.

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 the third quarter of 2008 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.

Recently Adopted Accounting Pronouncements

A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuance and settlements for the rollforward of Level 3 activity and (4) the transfers in and out of Levels 1 and 2. We adopted the new disclosures in the first quarter of 2010.

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Critical Accounting Policies

The preparation of financial statements in accordance with 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 the 2009 Form 10-K. 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 contingencies.

The full Cost Ceiling test cushion at March 31, 2010 was $91.7 million and was based upon average realized oil, natural gas liquids and natural gas prices of $64.51 per Bbl, $26.66 per Bbl and $3.69 per Mcf, respectively, or a volume weighted average price of $24.11 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. In connection with our March 31, 2010 Full Cost Ceiling test computation, a price sensitivity study also indicated that a ten percent increase in the commodity prices used in the ceiling test at March 31, 2010 would have increased the Full Cost Ceiling test cushion by approximately $104.4 million and a ten percent decrease in such commodity prices would have resulted in a $13.3 million ceiling test impairment. The aforementioned price sensitivity is as of March 31, 2010 and, accordingly, does not include any potential changes in reserve values due to subsequent performance or events, such as commodity prices, reserve revisions and drilling results.

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 under the full cost method of accounting rules. See “—Critical Accounting Policies—Oil and Natural Gas Properties,” in our 2009 Form 10-K.

To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including fixed rate swaps, costless collars, puts, calls and basis differential swaps, in order to establish some price floor protection.

The following table includes oil and gas positions settled during the three month periods ended March 31, 2010 and 2009, and the unrealized gain/(loss) associated with the outstanding oil and natural gas derivatives at March 31, 2010 and 2009.

	For the
	Three Months Ended
	March 31,
	2010		2009
Oil positions settled (Bbls)		-		18,200
Natural gas positions settled (MMBtus)		6,210,000		4,280,000

Realized gain ($ millions)	$	5.0	$	18.8
Unrealized gain ($ millions)		17.8		11.3

Gain on derivatives, net	$	22.8	$	30.1

The following table sets forth our natural gas derivative volumes and average Houston Ship Channel and Waha prices as of March 31, 2010.

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		Volume		Average		Average
Period	Contracts	(in MMbtu)		Floor Price		Ceiling Price
2010	Swaps		6,893,000	$	5.74	$	5.74
2010	Collars		8,776,000		5.71		6.72
2010	Long Puts		3,210,000		5.17
			18,879,000

2011	Swaps		5,016,000		5.74		5.74
2011	Collars		6,749,000		6.73		8.59
2011	Long Puts		5,475,000		5.08
			17,240,000

2012	Swaps		1,559,000		6.55		6.55
2012	Collars		6,404,000		6.48		8.30
2012	Long Puts		-
			7,963,000

As of March 31, 2010, approximately 47% of our open natural gas hedged volumes were with Credit Suisse, 40% were with Shell Energy North America (U.S.), L.P. and the remaining 13% were with Credit Agricole.

While the use of derivative financial instruments limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil and gas. We enter into the majority of our derivative transactions with three counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed to price risk. We have additional price risk because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the financial instruments. Moreover, our derivative arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time.

Our natural gas derivative transactions are generally settled based upon the average of the reported settlement prices on the HSC or WAHA indices for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reported settlement prices on the West Texas Intermediate index for each trading day of a particular calendar month.

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 natural gas and oil exploration, acquisition of 3-D seismic data (including number, timing and size of projects), spending plans, capital expenditure plans, planned evaluation of prospects, probability of prospects having oil and gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement the Company’s business strategies, accessibility of borrowings under our credit facility, future exploration activity, production rates, 2010 project financing, growth in production, development of new drilling programs, participation of our industry partners, funding for our Marcellus Shale operations, hedging of production, exploration and development expenditures, Camp Hill reserves development and production, borrowing base redeterminations under the Senior Credit Facility, 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,”

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“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 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 new SEC rules regarding oil and gas reserves, activities and approvals of our partners and parties with whom we have alliances, technological changes, significant capital requirements, borrowing base determinations and availability under the Senior Credit Facility, evaluations of the Company by potential lenders under the Senior Credit Facility, the potential impact of government regulations, including proposed legislation and regulations related to hydraulic fracturing, air emissions and climate change, and adverse regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, actions by lenders, ability to obtain permits, the results of audits and assessments, and other factors detailed in the “Risk Factors” and other sections of our Annual Report on Form 10-K for the year ended December 31, 2009 and in this and 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.

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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 year ended December 31, 2009. There have been no material changes to the disclosure regarding our exposure to certain market risks made in our Annual Report on Form 10-K for the year ended December 31, 2009. For additional information regarding our long-term debt, see Note 5 of the Notes to Consolidated Financial Statements (Unaudited) in Item 1 of Part I of this Quarterly Report on Form 10-Q.

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ITEM 4. - CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of March 31, 2010 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended March 31, 2010 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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

In addition to the risk factors set forth below and the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

We may not complete additional acquisitions in the Niobrara or Eagle Ford Shale plays.

It is possible that we will not complete acquisitions of additional acreage in the Eagle Ford Shale or the Niobrara plays. If we do not complete additional Niobrara or Eagle Ford acquisitions, we will not have the opportunity to develop the related assets and to attempt to realize the benefits we believe such acquisitions will afford us. If we are unable to complete additional Niobrara or Eagle Ford Shale acquisitions, this may detract from our efforts to realize our new growth strategy in crude oil and liquids-rich plays. Additionally, we may be unable to find or consummate other opportunities in these areas or in other areas with similar exposure to oil, condensate and natural gas liquids on similar terms or at all.

We have no experience drilling wells in the Niobrara and the Eagle Ford Shale and less information regarding reserves and decline rates in these shale formations than in other areas of our operations.

We have no exploration experience and no development experience in the Niobrara and the Eagle Ford Shale. We have not participated in the drilling of any wells in these areas. Other operators in these areas have significantly more experience in the drilling of wells, including the drilling of horizontal wells. As a result, we have less information with respect to the ultimate recoverable reserves, the production decline rate and other matters relating to the exploration, drilling and development of the Niobrara and the Eagle Ford Shale than we have in other areas in which we operate.

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

None.

Item 3. - Defaults Upon Senior Securities

None.

Item 5. - Other Information

None.

Item 6. - Exhibits

Exhibits required by Item 601 of Regulation S-K are as follows:

Exhibit Number		Description
10.40	—	Twelfth Amendment to Credit Agreement dated as of May 5, 2010, among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank.
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.

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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 7, 2010	By: /s/Paul F. Boling
	Chief Financial Officer
	(Principal Financial Officer)



Date: May 7, 2010	By: /s/David L. Pitts
	Chief Accounting Officer
	(Principal Accounting Officer)

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