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 September 30, 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 x NO ¨

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of October 31, 2011 was 39,411,094.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

INDEX


		PAGE
PART I. FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets As of September 30, 2011 (Unaudited) and December 31, 2010		2

	Consolidated Statements of Operations (Unaudited) For the three and nine months ended September 30, 2011 and 2010		3

	Consolidated Statements of Cash Flows (Unaudited) For the nine months ended September 30, 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		22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		33

Item 4.	Controls and Procedures		33

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		33

Item 1A.	Risk Factors		33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		36

Item 3.	Defaults Upon Senior Securities		36

Item 4.	(Removed and Reserved)		36

Item 5.	Other Information		36

Item 6.	Exhibits		36

SIGNATURES			37

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS


	September 30, 2011			December 31, 2010
	(Unaudited)
	(In thousands, except per share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,818		$	4,128
Accounts receivable, net
Oil and gas sales		18,497			16,027
Joint interest billing		23,788			14,309
Other		1,900			560
Advances to operators		164			487
Fair value of derivative instruments		29,095			17,698
Prepaids and other current assets		11,116			7,123

Total current assets		88,378			60,332

PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full cost method of accounting:
Proved oil and gas properties, net		682,736			626,665
Costs not subject to amortization		448,645			352,479
Other property and equipment, net		8,785			3,913

TOTAL PROPERTY AND EQUIPMENT, NET		1,140,166			983,057

DEFERRED FINANCING COSTS, NET		19,774			14,670
INVESTMENTS		2,523			3,392
FAIR VALUE OF DERIVATIVE INSTRUMENTS		10,467			7,257
DEFERRED INCOME TAXES		60,243			72,587
INVENTORY		—			1,646
OTHER ASSETS		1,758			1,193

TOTAL ASSETS	$	1,323,309		$	1,144,134


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	38,830		$	33,653
Revenue and royalties payable		39,488			23,864
Current state tax payable		748			4,052
Accrued drilling costs		53,678			26,884
Accrued interest		17,317			5,953
Other accrued liabilities		16,817			11,838
Advances for joint operations		6,784			3,407
Current maturities of long-term debt		—			160
Deferred income taxes		10,524			5,286
Other current liabilities		1,277			3,907

Total current liabilities		185,463			119,004

LONG-TERM DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT		623,893			558,094
ASSET RETIREMENT OBLIGATIONS		7,656			6,369
FAIR VALUE OF DERIVATIVE INSTRUMENTS		—			715
OTHER LIABILITIES		6,707			3,316
COMMITMENTS AND CONTINGENCIES		—			—
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value (90,000 shares authorized, 39,376 and 38,906 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively)		395			389
Additional paid-in capital		643,674			630,845
Accumulated deficit		(144,479	)		(174,598	)

Total shareholders’ equity		499,590			456,636

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,323,309		$	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 September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands, except per share amounts)
OIL AND GAS REVENUES	$	51,668		$	30,502		$	146,398		$	102,380
COSTS AND EXPENSES
Lease operating		7,292			7,118			21,385			18,361
Production tax		1,325			692			3,732			2,482
Ad valorem tax		1,026			749			2,698			2,421
Depreciation, depletion and amortization		20,325			10,094			57,596			31,014
Impairment of oil and gas properties		—			—			—			2,731
General and administrative (inclusive of stock-based compensation expense (benefit) of ($4,060) and $4,396 for the three months ended September 30, 2011 and 2010, respectively, and $6,595 and $9,716 for the nine months ended September 30, 2011 and 2010, respectively)		4,712			9,879			28,052			24,565
Accretion related to asset retirement obligations		71			56			215			160

TOTAL COSTS AND EXPENSES		34,751			28,588			113,678			81,734

OPERATING INCOME		16,917			1,914			32,720			20,646
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net		25,656			21,520			37,534			47,536
Loss on extinguishment of debt		—			—			(897	)		—
Interest expense		(13,386	)		(10,403	)		(38,001	)		(30,058	)
Capitalized interest		6,029			5,601			16,937			15,062
Other income (expense), net		17			6			78			(15	)

INCOME BEFORE INCOME TAXES		35,233			18,638			48,371			53,171
INCOME TAX EXPENSE		(13,590	)		(5,804	)		(18,252	)		(18,816	)


NET INCOME	$	21,643		$	12,834		$	30,119		$	34,355


OTHER COMPREHENSIVE INCOME, NET OF INCOME TAXES
Decrease in market value of investment in Pinnacle Gas Resources, Inc., net of income taxes		—			(16	)		—			(16	)

COMPREHENSIVE INCOME	$	21,643		$	12,818		$	30,119		$	34,339


NET INCOME PER COMMON SHARE
Basic	$	0.56		$	0.37		$	0.77		$	1.03

Diluted	$	0.55		$	0.37		$	0.76		$	1.02


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		38,914			34,730			38,927			33,301
Diluted		39,368			35,101			39,483			33,724

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30
	2011			2010
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	30,119		$	34,355
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation, depletion and amortization		57,596			31,014
Unrealized (gain) loss on derivative instruments		(13,998	)		(24,677	)
Impairment of oil and gas properties		—			2,731
Accretion related to asset retirement obligations		215			160
Loss on extinguishment of debt		897			—
Stock-based compensation		6,595			9,716
Allowance for (recoveries of) doubtful accounts		(58	)		368
Deferred income taxes		17,582			16,719
Amortization of debt discount and deferred financing costs, net of amounts capitalized		2,396			7,144
Other, net		7,019			1,789
Changes in operating assets and liabilities-
Accounts receivable		(13,228	)		(3,860	)
Accounts payable		28,359			1,322
Accrued liabilities		15,519			2,328
Other, net		(8,707	)		(270	)

Net cash provided by operating activities		130,306			78,839

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(373,789	)		(261,341	)
Increase in capital expenditure payables and accruals		16,216			17,404
Proceeds from sales of oil and gas properties, net		168,617			35,835
Advances to operators		323			477
Advances for joint operations		3,377			(395	)
Other, net		(496	)		(445	)

Net cash used in investing activities		(185,752	)		(208,465	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		501,164			245,600
Debt repayments		(437,660	)		(191,000	)
Proceeds from common stock offering, net of offering costs		—			73,814
Proceeds from stock options exercised		47			667
Payments of debt issuance costs		(8,415	)		(544	)

Net cash provided by financing activities		55,136			128,537

DECREASE IN CASH AND CASH EQUIVALENTS		(310	)		(1,089	)
CASH AND CASH EQUIVALENTS, beginning of period		4,128			3,837

CASH AND CASH EQUIVALENTS, end of period	$	3,818		$	2,748

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 United Kingdom. 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, the Utica Shale in Ohio, and the Huntington Field in the U.K. North Sea.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and 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 (“GAAP”). 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 all necessary adjustments, all of which were of a normal recurring nature and are in the opinion of management necessary for a fair presentation of the Company’s interim financial position, results of operations and cash flows. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. 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 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 average 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 creditworthiness 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.

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Cash and Cash Equivalents

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

Accounts Receivable and Allowance for Doubtful Accounts

The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability on a quarterly basis and adjusts the allowance as necessary using the specific identification method. At September 30, 2011 and December 31, 2010, the Company’s allowance for doubtful accounts was $2.3 million and $2.5 million, respectively.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third 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 9. Derivative Instruments for further discussion of concentration of credit risk related to the Company’s derivative instruments.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-country basis. Internal costs directly associated with acquisition, exploration and development activities are capitalized and totaled $2.0 million and $1.4 million for the three months ended September 30, 2011 and 2010, respectively, and $7.5 million and $4.2 million for the nine months ended September 30, 2011 and 2010, respectively. Costs related to production, general corporate overhead and similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting oil and natural gas liquids to gas equivalents at the ratio of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter then applying such amount to capitalized oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average depreciation, depletion and amortization (“DD&A”) per Mcfe on oil and gas properties was $1.81 and $1.18 for the three months ended September 30, 2011 and 2010, respectively, and $1.74 and $1.19 for the nine months ended September 30, 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 $6.0 million and $5.6 million for the three months ended September 30, 2011 and 2010, and $16.9 million and $15.1 million for the nine months ended September 30, 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 (i) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of properties

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not subject to amortization, and (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

The estimated future net revenues used in the ceiling test are calculated using average quoted market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices used in the ceiling test computation do not include the impact of derivative instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment.

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

Deferred Financing Costs

Deferred financing costs include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of debt 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.

Investments

Prior to the sale in January 2011 (see Note 3. Investments), the Company accounted for its investment in Pinnacle Gas Resources, Inc. (“Pinnacle”) as available-for-sale and adjusted the book value to fair value through other comprehensive income (loss), net of income taxes. This fair value was assessed quarterly for other than temporary impairment based on publicly available information. If the impairment was deemed other than temporary, it was recognized in earnings. Subsequent recoveries in fair value were reflected as increases to investments and other comprehensive income (loss), net of income taxes.

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

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 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 carrying amounts of long-term debt under the Prior Credit Facility, the Revolving Credit Facility and the Huntington Facility (each as defined in Note 6. Debt) approximate fair value as these borrowings bear interest at variable rates of interest. The carrying amounts of the Company’s 8.625% Senior Notes due 2018 (“Senior Notes”) and the Company’s 4.375% convertible senior notes due 2028 (“Convertible Senior Notes”) may not approximate fair value because the notes bear interest at fixed rates of interest. See Note 10. Fair Value Measurements.

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells after the reserves have been depleted. The asset retirement obligation is recognized 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.

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 the amount of such loss is reasonably estimable.

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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 September 30, 2011 and December 31, 2010, the Company did not have any material production imbalances.

Derivative Instruments

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

The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. See Note 9. Derivative Instruments for further discussion of the Company’s derivative instruments.

Stock-Based Compensation

The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock at the option of the Company (“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 expense (benefit) for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
	(In thousands)
Stock Options and SARs	$	(8,035	)	$	1,675	$	(1,121	)	$	2,196
Restricted Stock Awards and Units		3,777			2,721		10,227			7,520

		(4,258	)		4,396		9,106			9,716
Less: amounts capitalized		198			—		(2,511	)		—

Total Stock-Based Compensation Expense (Benefit)	$	(4,060	)	$	4,396	$	6,595		$	9,716

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 between four and seven years

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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 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.

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 (expense), net in the consolidated statements of operations.

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.

Net Income Per Common Share

Supplemental net income per common share information is provided below:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(In thousands, except
	per share amounts)
Net income	$	21,642	$	12,834	$	30,119	$	34,355


Weighted average common shares outstanding
Basic weighted average common shares outstanding		38,914		34,730		38,927		33,301
Restricted stock units, Stock SARs, stock options and warrants		454		371		556		423

Diluted weighted average common shares outstanding		39,368		35,101		39,483		33,724


Net income per common share
Basic	$	0.56	$	0.37	$	0.77	$	1.03
Diluted	$	0.55	$	0.37	$	0.76	$	1.02

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 10,507 and 67,562 shares related to restricted stock units, stock options and warrants from the calculation of dilutive shares for the three months ended September 30, 2011 and 2010, and 3,257 and 67,562 shares for the nine months ended September 30, 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 and nine months ended September 30, 2011 or 2010, because the conversion price was in excess of the market price of the common stock for those periods.

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3.	INVESTMENTS

Investments consisted of the following at September 30, 2011 and December 31, 2010:


	September 30, 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 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 received $0.9 million, or $0.34 per share, for its 2,555,825 shares of Pinnacle common stock during the second quarter of 2011.

4.	PROPERTY AND EQUIPMENT

At September 30, 2011 and December 31, 2010, property and equipment consisted of the following:


	September 30, 2011			December 31, 2010
	(In thousands)
Proved oil and gas properties	$	1,056,237		$	941,267
Costs not subject to amortization		448,645			352,479
Other property and equipment		10,224			7,314

Total property and equipment		1,515,106			1,301,060
Accumulated depreciation, depletion and amortization		(374,940	)		(318,003	)

Total property and equipment, net	$	1,140,166		$	983,057

Sale of Non-Core Area, Barnett Shale Properties

In May 2011, the Company sold a substantial portion of its non-core area Barnett Shale properties to KKR Natural Resources, a partnership formed between an affiliate of Kohlberg Kravis Roberts & Co. L.P. (KKR) and Premier Natural Resources. Net proceeds received from the sale were approximately $98 million, which represent an agreed upon purchase price of approximately $104 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received by the Company for sales of hydrocarbons from such properties between the effective date of January 1, 2011 and the closing date of May 17, 2011. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.

Marcellus Shale Joint Venture

On September 10, 2010, the Company completed the sale of 20% of its interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance Marcellus II, LLC (“Reliance”), a wholly-owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited for a combination of cash and a commitment to pay certain of our future development costs. Simultaneous with such transaction, our joint venture partner, ACP II Marcellus, LLC (“ACP II”), an affiliate of Avista Capital Holdings LP, entered into a purchase and sale agreement with Reliance under which it agreed to sell its entire interest in the same properties to Reliance. In June 2011, in accordance with the title and post-closing adjustment provisions of the purchase and sale agreements described above, the Company provided additional interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance in substitution of properties included in the sale that were affected by certain alleged title defects. In exchange for such substitute properties, the Company received $0.3 million in cash from Reliance relating to the sale of 20% of its interest. Additionally, during the second quarter of 2011 and third quarter 2010, the Company received cash distributions of $3.3 million and $20.8 million, respectively, on its B Unit investment in ACP II as a result of ACP II’s distribution to Avista of proceeds from its sale of oil and gas properties to an affiliate of Reliance. These distributions are recognized as reduction of proved oil and gas properties.

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Eagle Ford Joint Venture

On September 28, 2011, the Company completed the sale of 20% of its interests in oil and gas properties in parts of the Eagle Ford Shale to GAIL (INDIA) LIMITED (“GAIL”) effective September 1, 2011. Under the purchase and participation agreement for this transaction, the Company received $63.65 million in cash which was recognized as a reduction of proved oil and gas properties. As part of the consideration for the purchase, GAIL has committed to pay a “development carry” of 50% of certain of the Company’s future development costs up to approximately $31 million, as further described below. The Eagle Ford Shale assets to be conveyed to GAIL under the terms of the agreement include approximately 4,040 net acres located primarily in La Salle County, Texas and a 20% interest in eight completed horizontal wells. The amounts to be received by the Company are subject to adjustment, pending completion of land and title matters. The agreement also provides for an ongoing joint venture between the Company and GAIL with respect to the interests being purchased by GAIL. The development carry obligation extends until June 30, 2013 or until the earlier full utilization of the approximately $31 million development carry, subject to certain conditions and extensions. The Company will continue to operate the joint venture properties that it currently operates, and currently expects the approximately $31 million development carry to be exhausted in less than one year. The joint venture provides for an area of mutual interest including the purchased interests and specified areas adjacent to such interests. GAIL will have the right to purchase certain interests acquired by the Company in the area of mutual interest at a specified premium to the price paid by the Company.

5.	INCOME TAXES

For the three and nine months ended September 30, 2011 and 2010, all of the Company’s income before income taxes is derived primarily from activities within the United States and the United Kingdom. The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates is applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate, will impact future income tax expense. 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 September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
	(In thousands)
Income tax expense at the statutory rate	$	12,331	$	6,523		$	16,930		$	18,610
State income taxes, net of federal benefit		754		(701	)		2,456			647
Foreign income taxes		155		—			(19	)		—
Capital loss associated with investment in Pinnacle for which no income tax benefit was recognized in prior years		—		—			(1,135	)		—
Other, net		350		(18	)		20			(441	)

Income tax expense	$	13,590	$	5,804		$	18,252		$	18,816

As of September 30, 2011, the Company had income tax net operating loss (“NOL”) carryforwards of approximately $138.8 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 carry forward period. As such, the Company believes that it is more likely than not that its deferred tax assets will be fully realized.

At September 30, 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.

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DEBT

Debt consisted of the following at September 30, 2011 and December 31, 2010:


	September 30, 2011			December 31, 2010
	(In thousands)
Senior Notes	$	400,000		$	400,000
Unamortized discount for Senior Notes		(2,561	)		(2,751	)
Convertible Senior Notes		73,750			73,750
Unamortized discount for Convertible Senior Notes		(4,460	)		(6,405	)
Senior Secured Revolving Credit Facilities		154,000			93,500
Senior Secured Multicurrency Credit Facility		3,164			—
Other		—			160

		623,893			558,254
Less: Current maturities		—			(160	)

	$	623,893		$	558,094

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. 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 such senior credit agreement. As a result, the Company 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 (as defined in the senior credit agreement governing the Revolving Credit Facility) and (ii) $750 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of the Company’s U.S. assets and is guaranteed by certain of the Company’s subsidiaries. The initial Borrowing Base under the Revolving Credit Facility was $350 million and as of September 30, 2011, the borrowing base was $340 million. The next Borrowing Base redetermination is currently expected to occur in November 2011.

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).

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 (each as defined in the senior credit agreement governing the Revolving Credit Facility): (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 September 30, 2011, the ratio of Total Debt to EBITDA was 3.52 to 1.00, the current ratio was 1.52 to 1.00, the Senior Debt to EBITDA ratio was 0.88 to 1.00 and the EBITDA to Interest Expense ratio was 4.01 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. At September 30, 2011, the Company had $154.0 million of borrowings outstanding under the Revolving Credit Facility with a weighted average interest rate of 2.77%. At September 30, 2011, the Company also had $0.4 million in letters of credit

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outstanding which reduced the amounts available under the Revolving Credit Facility. Future availability under the $340 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, we and Carrizo UK Huntington Ltd. (“Carrizo UK”), as borrower, entered into a Senior Secured Multicurrency Credit Facility (the “Huntington Facility”). 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. 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. Based on the redetermination and recalculation, which occurred in the third quarter 2011, availability of the term loan facility and cost overrun facility is currently $55 million and $6.5 million, respectively.

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 project and 3.0% thereafter for the term loan facility and post-completion credit facility or (ii) 4.75% for the cost overrun facility.

At September 30, 2011, the Company had $3.2 million of borrowings outstanding under the Huntington Facility with a weighted average interest rate of 4.18% and no letters of credit had been issued.

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 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.	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. The Land Agreement expired pursuant to its terms on May 31, 2011. Under the Land Agreement, the Company was able to acquire up to $20 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from such third party. In consideration for the Company’s receipt of an option to purchase the leases acquired by the third party, each time the third party purchased a lease group under the Land Agreement the Company agreed to issue to the third party’s affiliate warrants to purchase a number of shares of the Company’s common stock with an exercise price of $22.09 and an expiration date of August 21, 2017. In addition, under certain circumstances where the Company reached 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 agreed to issue additional warrants. 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 18,608 shares of common stock during the first quarter of 2011. During July and October of 2011, the Company issued additional warrants to purchase 4,816 and 5,152 shares, respectively of the Company’s common stock to the third party’s affiliate for leases acquired prior to the expiration of the Land Agreement.

During the second and third quarter of 2011, the Company contributed $1.0 million and $1.1 million, respectively, in common stock of the Company to the University of Texas at Arlington (“UTA”) where we are producing natural gas from a number of wells in the Barnett Shale play.

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9.	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 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 or as required by the terms of our credit facilities.

The fair value of derivative instruments at September 30, 2011, and December 31, 2010 was a net asset of $39.6 million and $24.1 million, respectively. At September 30, 2011, approximately 51% of the fair value of the Company’s derivative instruments were with Credit Suisse, 35% were with BNP Paribas, 7% were with Shell Energy North America (US) LP, 5% were with Credit Agricole, and 2% 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 U.S. natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of September 30, 2011.


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2011		7,544,000	$	5.54	$	5.68
2012		18,943,000	$	5.50	$	5.61
2013		7,300,000	$	5.21	$	5.21

In connection with the natural gas 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 $4.82, the floor price becomes the market price plus the put spread of $1.23 on 3,031,000 of the 7,544,000 MMBtus and the remaining 4,513,000 MMBtus would have a floor price of $5.54.


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2011		3,031,000	$	4.82	$	1.23
2012		6,974,400	$	4.91	$	1.27

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The following sets forth a summary of the Company’s U.S. crude oil derivative positions at average NYMEX prices as of September 30, 2011.


Period	Volume (in Bbls)		Weighted Average Floor Price ($/Bbls)		Weighted Average Ceiling Price ($/Bbls)
2011		138,000	$	92.61	$	106.19
2012		549,000	$	80.00	$	100.18
2013		547,500	$	80.00	$	101.09

In addition to the table above, the Company sold call positions of 18,400 Bbls at a price per barrel of $95.00 for the remainder of 2011.

For the three and nine months ended September 30, 2011 and 2010, the Company recorded the following related to its oil and gas derivative instruments:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(In thousands)
Realized gain (loss), net	$	8,626	$	9,111	$	23,536	$	22,859
Unrealized gain (loss), net		17,030		12,409		13,998		24,677

Gain (loss) on derivative instruments, net	$	25,656	$	21,520	$	37,534	$	47,536

The Company deferred the payment of premiums associated with certain of its oil and gas derivative instruments totaling $2.2 million and $3.9 million at September 30, 2011 and December 31, 2010, respectively. We classified $1.3 million and $3.9 million as other current liabilities at September 30, 2011 and December 31, 2010, respectively, and $0.9 million as other non-current liabilities at September 30, 2011. There were no other non-current liabilities at December 31, 2010. These deferred premiums will be paid to the counterparty with each monthly settlement (October 2011 – March 2014) and recognized as a reduction of realized gain (loss) on derivative instruments, net.

10.

FAIR VALUE MEASUREMENTS

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

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

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

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

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2011 and December 31, 2010, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:


	September 30, 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		—		56,488			—		56,488			—		48,140			—		48,140
Liabilities:
Derivative instruments		—		(16,926	)		—		(16,926	)		—		(24,062	)		—		(24,062	)


Total	$	—	$	39,562		$	—	$	39,562		$	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 particular point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The assets and liabilities for derivative instruments included in the 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 value of the investment in Pinnacle was 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 nine months ended September 30, 2011 and 2010.

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 carrying amounts of long-term debt under the Prior Credit Facility, the Revolving Credit Facility and the Huntington Facility (each as defined in Note 6. Debt) approximate fair value as these borrowings bear interest at variable rates of interest. The fair values of the Convertible Senior Notes and Senior Notes at September 30, 2011, were estimated at approximately $72.6 million and $399.0 million, respectively, based on quoted market prices.

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, surface restoration and reserve lives.

11.

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On October 28, 2010, the Company and certain of its wholly owned subsidiaries (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 Senior Notes. 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. On August 5, 2011, two recently formed wholly owned subsidiaries of the Company, Carrizo (Eagle Ford) LLC and Carrizo (Niobrara) LLC, guaranteed the Senior Notes and the Convertible Senior Notes. These entities also guarantee borrowings under the Revolving Credit Facility.

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The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information as of September 30, 2011 and December 31, 2010, and for the three and nine months ended September 30, 2011 and 2010 on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries, 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


	September 30, 2011
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	1,221,545		$	56,195		$	2,117	$	(1,191,479	)	$	88,378
Property and equipment, net		102,293			973,052			54,846		9,975			1,140,166
Investments in subsidiaries		(116,360	)		—			—		116,360			—
Other assets		30,819			64,199			3,722		(3,975	)		94,765

Total assets	$	1,238,297		$	1,093,446		$	60,685	$	(1,069,119	)	$	1,323,309


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	113,622		$	1,209,061		$	5,823	$	(1,143,043	)	$	185,463
Long-term liabilities		632,271			1,048			6,124		(1,187	)		638,256
Shareholders’ equity		492,404			(116,663	)		48,738		75,111			499,590

Total liabilities and shareholders’ equity	$	1,238,297		$	1,093,446		$	60,685	$	(1,069,119	)	$	1,323,309


	December 31, 2010
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		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
Investments 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

-18-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS


	For the Three Months Ended September 30, 2011
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Oil and Gas revenues	$	7,607		$	44,061		$	—		$	—		$	51,668
Cost and expenses		14,160			23,685			24			(3,118	)		34,751

Operating income (loss)		(6,553	)		20,376			(24	)		3,118			16,917
Other income and (expense), net		22,966			(4,789	)		139			—			18,316

Income (loss) before income taxes		16,413			15,587			115			3,118			35,233
Income tax (expense) benefit		(5,863	)		(5,603	)		(957	)		(1,167	)		(13,590	)
Equity in income (loss) of subsidiaries		9,142			—			—			(9,142	)		—

Net income (loss)	$	19,692		$	9,984		$	(842	)	$	(7,191	)	$	21,643


	For the Three Months Ended September 30, 2010
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Oil and Gas revenues	$	6,353		$	24,149		$	—		$	—		$	30,502
Cost and expenses		15,936			13,222			—			(570	)		28,588

Operating income (loss)		(9,583	)		10,927			—			570			1,914
Other income and (expense), net		18,714			(1,990	)		—			—			16,724

Income before income taxes		9,131			8,937			—			570			18,638
Income tax (expense) benefit		(3,442	)		(2,158	)		—			(204	)		(5,804	)
Equity in income (loss) of subsidiaries		6,779			—			—			(6,779	)		—

Net income (loss)	$	12,468		$	6,779		$	—		$	(6,413	)	$	12,834

-19-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS


	For the Nine Months Ended September 30, 2011
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Oil and Gas revenues	$	25,771		$	120,627		$	—		$	—		$	146,398
Cost and expenses		52,129			67,332			167			(5,950	)		113,678

Operating income (loss)		(26,358	)		53,295			(167	)		5,950			32,720
Other income and (expense), net		34,063			(16,870	)		(1,542	)		—			15,651

Income (loss) before income taxes		7,705			36,425			(1,709	)		5,950			48,371
Income tax (expense) benefit		(2,804	)		(13,259	)		19			(2,208	)		(18,252	)
Equity in income (loss) of subsidiaries		21,476			—			—			(21,476	)		—

Net income (loss)	$	26,377		$	23,166		$	(1,690	)	$	(17,734	)	$	30,119


	For the Nine Months Ended September 30, 2010
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Oil and Gas revenues	$	25,952		$	76,428		$	—		$	—		$	102,380
Cost and expenses		47,113			37,560			—			(2,939	)		81,734

Operating income (loss)		(21,161	)		38,868			—			2,939			20,646
Other income and (expense), net		39,173			(6,648	)		—			—			32,525

Income (loss) before income taxes		18,012			32,220			—			2,939			53,171
Income tax (expense) benefit		(7,273	)		(10,494	)		—			(1,049	)		(18,816	)
Equity in income (loss) of subsidiaries		21,726			—			—			(21,726	)		—

Net income (loss)	$	32,465		$	21,726		$	—		$	(19,836	)	$	34,355

-20-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


	For the Nine Months Ended September 30, 2011
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities	$	59,668		$	71,777		$	(1,139	)	$	—		$	130,306
Net cash used in investing activities		(122,718	)		(214,217	)		(23,180	)		174,363			(185,752	)
Net cash provided by financing activities		53,143			151,646			24,710			(174,363	)		55,136

Net increase (decrease) in cash and cash equivalents		(9,907	)		9,206			391			—			(310	)
Cash and cash equivalents, beginning of period		1,418			2,710			—			—			4,128

Cash and cash equivalents, end of period	$	(8,489	)	$	11,916		$	391		$	—		$	3,818


	For the Nine Months Ended September 30, 2010
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities	$	25,039		$	53,800		$	—		$	—		$	78,839
Net cash used in investing activities		(150,894	)		(205,019	)		—			147,448			(208,465	)
Net cash provided by financing activities		128,537			147,448			—			(147,448	)		128,537

Net increase (decrease) in cash and cash equivalents		2,682			(3,771	)		—			—			(1,089	)
Cash and cash equivalents, beginning of period		1,337			2,500						—			3,837

Cash and cash equivalents, end of period	$	4,019		$	(1,271	)	$	—		$	—		$	2,748

-21-

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

The following is management’s discussion and analysis of the significant factors that affected the Company’s financial position and results of operations during the periods included in the accompanying unaudited consolidated financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, and the unaudited consolidated financial statements included in this quarterly report.

General Overview

Our third quarter 2011 included oil and gas revenues of $51.7 million and production of 11.3 Bcfe. The key drivers to our results for the three months ended September 30, 2011 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the three months ended September 30, 2011, we drilled (a) 11 gross wells (8.4 net) in the Eagle Ford Shale, (b) 7 gross wells (2.6 net) in the Marcellus Shale, (c) 10 gross wells (2.3 net) in the Barnett Shale, (d) 3 gross wells (2.3 net) in the Niobrara Formation, (e) 2 gross wells (0.3 net) in the U.K. North Sea, and (f) 2 gross (0.1 net) wells in the other project areas.

Production. Our third quarter 2011 production of 11.3 Bcfe, or 122.3 MMcfe/d, increased 31% from the third quarter 2010 production of 8.6 Bcfe, or 93.4 MMcfe/d. The increase from the third quarter of 2010 to the third 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 and the sale of substantially all of our non-core area Barnett Shale properties in May 2011.

Commodity prices. Our average natural gas price during the third quarter of 2011 was $3.06 per Mcf (excluding the impact of our derivative instruments), $0.19 per Mcf, or 6% lower than the price during the third quarter of 2010. Excluded from these prices are realized gain (loss) on derivative instruments, net of $7.6 million ($0.78 per Mcf) for the third quarter of 2011 and $9.0 million ($1.13 per Mcf) for the third quarter of 2010. Our average oil price during the third quarter of 2011 was $89.17 per barrel, $16.25 per barrel, or 22% higher than the price during the third quarter of 2010. Excluded from these prices is a realized gain (loss) on derivative instruments, net of $1.0 million ($4.55 per barrel) for the third quarter of 2011 and $0.1 million ($3.52 per barrel) for the third quarter of 2010.

Sale of Non-Core Area Barnett Shale Properties. In May 2011, we completed the sale of certain non-core area Barnett Shale properties. Net proceeds received from the sale were approximately $98 million, which represent an agreed upon purchase price of approximately $104 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received by us for sales of hydrocarbons from such properties between the effective date of January 1, 2011 and the closing date of May 17, 2011. The sale included approximately 13,000 leased acres, including 75 gross (58.5 net) wells that produced at an approximate gross rate of 15.7 MMcfe per day (8.3 MMcfe/d net). Estimated proved reserves associated with the divested properties amount to 122.4 Bcfe, 55% of which were proved undeveloped, as determined by our third party engineers at year-end 2010.

Eagle Ford Joint Venture. In September 2011, we entered into a joint venture with a wholly owned subsidiary of GAIL (INDIA) LIMITED (“GAIL”). Under the agreements governing the joint venture, we sold 20% of our interest in approximately 20,200 net mineral acres leased by us in the Eagle Ford Shale for total consideration of up to $95 million, comprised of $63.65 million in cash and the assumption of an additional $31 million of our future drilling and development costs incurred prior to June 30, 2013. The cash proceeds from the transaction were used to reduce the outstanding balance under the Revolving Credit Facility. The joint venture agreements contemplate certain purchase price adjustments, drilling carry extensions and conditions and an area of mutual interest agreement among the parties. The Eagle Ford Shale assets conveyed to GAIL under the terms of the agreement include approximately 4,040 net acres located primarily in La Salle County, Texas and a 20% interest in eight horizontal wells.

-22-

Utica Shale. In September 2011, we entered into a joint venture with an affiliate of Avista Capital Partners II, L.P. to acquire and develop acreage in the liquids rich region of the Utica Shale. The properties initially dedicated to the joint venture consist of approximately 15,000 net acres in eastern Ohio and northwestern Pennsylvania at an average cost of less than $1,500 per acre. Under the terms of the agreement, we will own an initial 10% interest in the joint venture properties with Avista owning the remaining 90%. Avista has the right to contribute aggregate funds of up to $130 million to the joint venture, with the ability to raise this amount by an incremental $70 million. We hold two purchase options to increase our participating interest to 50% in the properties initially dedicated to the joint venture and subsequently acquired by the joint venture over the next 12 and 18 months, respectively. Our purchase options may be exercised at specified increments above acreage cost and associated improvements at any time during the applicable option period. The exercise deadlines for both options are accelerated in connection with a sale by Avista of substantially all of its interests in the joint venture properties. In the event these purchase options are not exercised and we are not selling substantially all of our interest in the joint venture (except in connection with such a sale by Avista), we will be entitled to share in any cash distributions by Avista to its partners, provided specified return on investment thresholds on Avista’s investment are achieved, with the percentage of such cash distributions to us increasing if higher rates of return on investment thresholds are achieved. We will initially serve as operator of the joint venture properties and will provide certain management services to Avista related to the joint venture. Steven A. Webster, Chairman of Carrizo’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which entity has the ability to control Avista.

Outlook

Our outlook for the remainder of 2011 remains positive but challenging, primarily due to the low futures prices of natural gas that are offset by continued strength in oil prices. Commodity prices that permit us to drill, develop and produce at a profit are key to our future success. Following is a summary of activity by operating area:

Eagle Ford and Niobrara. Based upon the success of our drilling results in late 2010 and 2011, we continue to focus on developing our liquid rich resource plays in the Eagle Ford Shale and the Niobrara Formation and are reallocating capital from development of Barnett Shale gas to Eagle Ford and Niobrara oil. In the third quarter, we had ten wells producing in Eagle Ford Shale and seven wells producing in the Niobrara Formation. We currently have three rigs on our Eagle Ford properties. We continue to evaluate seismic data in the Niobrara Formation to enhance our drilling opportunities and currently have one rig drilling on our Niobrara properties.

Marcellus Shale. We currently have two drilling rigs and two spudder rigs drilling in the Marcellus, all of which we operate as part of our Reliance joint venture. Stimulation and completion of the back-log of drilled wells and first sales from Susquehanna County began in November. Production from this area commenced in the fourth quarter of 2011. We currently expect production to grow during 2012.

Barnett Shale. Due to low natural gas price outlook we currently plan no operated drilling activities in the Barnett Shale until the future natural gas price outlook improves. As of October 31, 2011, we have 8.1 previously drilled net wells left to complete which we expect to take place in the early part of 2012. We currently expect our production from the Barnett Shale to experience a decline in 2012 due to our shift of drilling to liquid rich plays and the Marcellus Shale.

U.K. North Sea. During the third quarter of 2011, we continued development of the Huntington Field. As a result of financial difficulties of a key supplier that has led to construction delays, we currently expect production from this field to begin in the third quarter of 2012.

Results of Operations

Three Months Ended September 30, 2011, Compared to the Three Months Ended September 30, 2010

Revenues from oil and gas production for the three months ended September 30, 2011 increased 69% to $51.7 million from $30.5 million for the same period in 2010 primarily due to increased production, particularly higher oil and condensate production in the Eagle Ford Shale, and higher oil prices. Production volumes for the three months ended September 30, 2011 and 2010 were 11.3 Bcfe and 8.6 Bcfe, respectively. The increase in production from the third quarter of 2010 to the third quarter of 2011 was primarily due to increased production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline and the sale of substantially all of our non-core area Barnett Shale properties in May 2011. Average natural gas prices, excluding the impact attributable to a $7.6 million and a $9.0 million realized gain on derivative instruments for the quarters ended September 30, 2011 and 2010, respectively, decreased 6% to $3.06 per Mcf in the third quarter of 2011 from $3.25 per Mcf in the same period in 2010. Average oil prices, excluding the impact attributable to a $1.0 million and a $0.1 million realized gain on derivative instruments for the quarters ended September 30, 2011 and 2010, respectively, increased 22% to $89.17 per barrel from $72.92 per barrel in the same period in 2010.

The following table summarizes production volumes, average sales prices (excluding the impact of derivative instruments) and oil and gas revenues for the three months ended September 30, 2011 and 2010:

-23-


	Three Months Ended September 30,				2011 Period Compared to 2010 Period
	2011		2010		Increase (Decrease)			% Increase (Decrease)
Production volumes
Oil and condensate (MBbls)		223		29		194			669	%
Natural gas and NGLs (MMcfe)		9,911		8,417		1,494			18	%
Average sales prices
Oil and condensate ($ per Bbl)	$	89.17	$	72.92	$	16.25			22	%
Natural gas ($ per Mcf)		3.06		3.25		(0.19	)		(6	)%
NGLs ($ per Mcfe)		9.51		5.74		3.77			66	%
Oil and gas revenues (In thousands of $)
Oil and condensate	$	19,924	$	2,096	$	17,828			851	%
Natural gas and NGLs		31,744		28,406		3,338			12	%

Total oil and gas revenues	$	51,668	$	30,502	$	21,166			69	%

Lease operating expenses (including transportation costs of $1.8 million) were $7.3 million (or $0.65 per Mcfe) for the three months ended September 30, 2011 as compared to lease operating expenses (including transportation costs of $1.3 million) of $7.1 million (or $0.83 per Mcfe) for the third quarter of 2010. Lease operating expenses increased due to increased production partially offset by a decrease in workover costs, as the prior year included the workover of a high volume gas well in the Gulf Coast area. We continue to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively lower salt water disposal costs in our core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, including the non-core area Barnett Shale properties sold in May 2011. This decrease in operating cost per Mcfe was partially offset by increased operating cost per Mcfe associated with oil production in the Eagle Ford and Niobrara operating areas.

Production taxes were $1.3 million (or 2.6% of revenues) for the three months ended September 30, 2011 as compared to $0.7 million (or 2.3% of revenues) for the three months ended September 30, 2010. The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 2.3% to 2.6% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.

Ad valorem taxes increased to $1.0 million (or $0.09 per Mcfe) for the three months ended September 30, 2011 from $0.7 million ($0.09 per Mcfe) for the same period in 2010. The increase in ad valorem taxes is due to new oil and gas wells drilled in 2010.

Depreciation, depletion and amortization (“DD&A”) expense for the three months ended September 30, 2011 increased to $20.3 million (or $1.81 per Mcfe) from $10.1 million (or $1.18 per Mcfe) for the same period in 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to increased production during the third quarter of 2011 as compared to the same period in 2010 and increased future development costs associated with crude oil and natural gas liquids reserves in the Eagle Ford that were added after the third quarter of 2010 and have a higher future development cost per equivalent unit than our proved gas reserves.

General and administrative expense decreased to $4.7 million for the three months ended September 30, 2011 from $9.9 million for the corresponding period in 2010. The decrease was primarily due to decreased stock-based compensation driven by the decrease in fair value of cash-settled stock appreciation rights due to the decrease in stock price during the third quarter of 2011, partially offset by increased compensation costs related to an increase in the number of employees, a contribution in common stock to the Child Development Center at the UTA and higher compensation expense related to a higher number of restricted stock awards granted to employees and executives.

The net gain on derivative instruments of $25.6 million in the third quarter of 2011 consisted of a $17.0 million unrealized gain on derivatives and an $8.6 million realized gain on derivatives. The net gain on derivative instruments of $21.5 million in the third quarter of 2010 was comprised of a $12.4 million unrealized gain on derivatives and a $9.1 million realized gain on derivatives.

Interest expense and capitalized interest for the three months ended September 30, 2011 were $13.4 million and $6.0 million, respectively, as compared to $10.4 million and $5.6 million, respectively, for the same period in 2010. The net increase was primarily due to interest on the $400 million aggregate principal amount of Senior Notes that were issued in the fourth quarter of 2010, partially offset by decreased interest and discount amortization attributable to the $300 million aggregate principal amount of the Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

-24-

The estimated annual effective income tax rates of September 30, 2011 and 2010 were 36.4% and 35.9%, respectively. The increase in the tax rate is due primarily to higher state income taxes associated with increased activity in Pennsylvania and Colorado. We expect substantially all of our income taxes to be deferred. The effective income tax rates for net income were 38.6% and 31.1% for the three months ended September 30, 2011 and 2010, respectively. The differences between these rates and our estimated annual effective income tax rates are due to true ups of prior estimates of state income taxes in both periods.

Nine Months Ended September 30, 2011, Compared to the Nine Months Ended September 30, 2010

Revenues from oil and gas production for the nine months ended September 30, 2011 increased 43% to $146.4 million from $102.4 million for the same period in 2010 primarily due to increased production, particularly higher oil and condensate production in the Eagle Ford Shale, and higher oil prices, partially offset by lower gas prices. Production volumes for the nine months ended September 30, 2011 and 2010 were 33.1 Bcfe and 26.2 Bcfe, respectively. The increase in production for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010 was primarily due to increased production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline and the sale of substantially all of our non-core area Barnett Shale properties in May 2011. Average natural gas prices, excluding the impact attributable to a $22.8 million realized gain on derivative instruments for the nine months ended September 30, 2011 and 2010, decreased to $3.12 per Mcf for the first nine months of 2011 from $3.57 per Mcf in the same period in 2010. Average oil prices, excluding the impact of a realized gain on derivative instruments of $0.7 million and $0.1 million for the nine months ended September 30, 2011 and 2010, respectively, increased 22% to $91.76 per barrel from $75.10 per barrel in the same period in 2010.

The following table summarizes production volumes, average sales prices (excluding the impact of derivative instruments) and oil and gas revenues for the nine months ended September 30, 2011 and 2010:


	Nine Months Ended September 30				2011 Period Compared to 2010 Period
	2011		2010		Increase (Decrease)			% Increase (Decrease)
Production volumes
Oil and condensate (MBbls)		515		105		410			390	%
Natural gas and NGLs (MMcfe)		30,026		25,524		4,502			18	%
Average sales prices
Oil and condensate ($ per Bbl)	$	91.76	$	75.10	$	16.66			24	%
Natural gas($ per Mcf)		3.12		3.57		(0.45	)		(15	)%
NGLs ($ per Mcfe)		8.18		6.40		1.78			28	%
Oil and gas revenues (In thousands of $)
Oil and condensate	$	47,284	$	7,854	$	39,430			502	%
Natural gas and NGLs		99,114		94,526		4,588			5	%

Total oil and gas revenues	$	146,398	$	102,380	$	44,018			43	%

Lease operating expenses (including transportation costs of $4.7 million) were $21.4 million (or $0.64 per Mcfe) for the nine months ended September 30, 2011 as compared to lease operating expenses (including transportation costs of $4.1 million) of $18.4 million (or $0.70 per Mcfe) for the nine months ended September 30, 2010. Lease operating expenses increased due to increased production. We continue to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively lower salt water disposal costs in our core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, including the non-core area Barnett Shale properties sold in May 2011. This decrease in operating cost per Mcfe was partially offset by increased operating cost per Mcfe associated with oil production in the Eagle Ford and Niobrara operating areas.

Production taxes increased to $3.7 million (or 2.6% of revenues) for the nine months ended September 30, 2011 from $2.5 million (or 2.4% of revenues) for the same period in 2010. The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 2.4% to 2.6% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.

Ad valorem taxes increased to $2.7 million ($0.08 per Mcfe) for the nine months ended September 30, 2011 from $2.4 million ($0.09 per Mcfe) for the same period in 2010. The increase in ad valorem taxes is due to new oil and gas wells drilled in 2010.

-25-

DD&A expense for the nine months ended September 30, 2011 increased to $57.6 million (or $1.74 per Mcfe) from $31.0 million (or $1.19 per Mcfe) for the same period in 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to increased production during the first nine months of 2011 as compared to the same period in 2010 and increased future development costs associated with crude oil and natural gas liquids reserves in the Eagle Ford that were added after the third quarter of 2010, and have a higher future development cost per equivalent unit than our proved gas reserves.

In June 2010, we concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts, resulting in a full-cost ceiling test impairment of $2.7 million for the nine months ended September 30, 2010 with respect to the U.K. cost center.

General and administrative expense increased to $28.1 million for the nine months ended September 30, 2011 from $24.6 million for the corresponding period in 2010. The increase was primarily due to (a) increased compensation costs related to an increase in the number of employees in 2011 as compared to 2010, (b) contributions in common stock to UTA, partially offset by (c) a decrease in stock-based compensation expense due to a decrease in the fair value of cash-settled stock appreciation rights due to a decrease in stock price in the third quarter of 2011 partially offset by increased number of restricted stock awards granted during the period.

The net gain on derivative instruments of $37.5 million in the first nine months of 2011 consisted of a $14.0 million unrealized gain on derivatives and a $23.5 million realized gain on derivatives. The net gain on derivative instruments of $47.5 million in the first nine months of 2010 was comprised of a $22.9 million realized gain on derivatives and a $24.6 million unrealized 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 nine months ended September 30, 2011 were $38.0 million and $16.9 million, respectively, as compared to $30.1 million and $15.1 million, respectively, for the same period in 2010. The net increase was primarily due to interest on the $400 million aggregate principal amount of Senior Notes that were issued in the fourth quarter of 2010, partially offset by decreased interest and discount amortization attributable to the $300 million aggregate principal amount of the Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

The estimated annual effective income tax rates as of September 30, 2011 and 2010 were 36.4% and 35.9%, respectively. The increase in the tax rate is due primarily to higher state income taxes associated with increased activity in Pennsylvania and Colorado. We expect substantially all of our income taxes to be deferred. The effective income tax rates for net income were 37.7% and 35.4% for the nine months ended September 30, 2011 and 2010, respectively. The differences between these rates and our estimated annual effective income tax rates are due to true ups of prior estimates of state income taxes in both periods.

Liquidity and Capital Resources

2011 Capital Expenditure Plan and Funding Strategy. Our revised 2011 capital expenditure plan is $470 million which includes $360 million for drilling (including $200 million for the Eagle Ford Shale, $80 million for the Barnett Shale, $40 million for the Niobrara Formation and, $30 million for the Marcellus Shale and $10 million for other areas-all net of carry), $90 million for leasehold and seismic costs and $20 million for the Huntington field development in the U.K. North Sea (net of the amounts to be funded by the Huntington Facility in excess of our initial equity contribution). 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.

Sources and Uses of Cash. 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. 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. For the nine months ended September 30, 2011, capital expenditures, net of proceeds from asset sales, exceeded our net cash provided by operations. During the nine months of 2011, we funded our capital expenditures with cash provided by operations, proceeds from the sale of assets, payments or carried interest relating to our joint ventures with Reliance and GAIL, and borrowings under our Prior Credit Facility, the Revolving Credit Facility and the Huntington Facility. Potential sources of future liquidity include the following:

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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.

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Borrowings under the Revolving Credit Facility and the Huntington Facility. At October 31, 2011, $195.0 million and $9.6 million of borrowings were outstanding under the Revolving Credit Facility and the Huntington Facility, respectively. At October 31, 2011, we also had $0.4 million in letters of credit outstanding under the Revolving Credit Facility, which reduce the amounts available under the Revolving Credit Facility. The amount we are able to borrow with respect to the Borrowing Base of the Revolving Credit Facility, which is currently $340 million, is subject to compliance with the financial covenants and other provisions of the credit agreement governing the Revolving Credit Facility.

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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.

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Asset sales. In the second quarter of 2011, we sold certain non-core area Barnett Shale properties. Net proceeds received from such sale were approximately $98 million, which represent an agreed upon purchase price of approximately $104 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received by us for sales of hydrocarbons from such properties between the effective date of January 1, 2011 and the closing date of May 17, 2011. In the third quarter of 2011, we completed the sale of 20% of our interests in oil and gas properties in parts of the Eagle Ford Shale to GAIL effective September 1, 2011. Net proceeds received from the sale to Gail were approximately $63.65 million in cash. As part of the consideration for the purchase, GAIL has committed to pay a “development carry” of 50% of certain of our future development costs up to approximately $31 million. We used the net proceeds from these sales to repay borrowings under our Revolving Credit Facility and then used the resulting additional capacity under our Revolving Credit Facility to fund, in part, our 2011 capital expenditure plan, and for general corporate purposes. 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.

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

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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.

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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 Reliance in the Marcellus Shale, with GAIL in the Eagle Ford Shale, with Avista in the Utica Shale, and with Sumitomo in the Barnett Shale.

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Joint ventures with third parties to acquire and develop acreage, such as our Utica Shale joint venture with Avista in which we have the option to purchase a greater participating interest or to share in distributions based on our initial investment once specified return on investment thresholds have been achieved.

Overview of Cash Flow Activities. Net cash provided by operating activities was $130.3 million and $78.8 million for the nine months ended September 30, 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 increased oil prices, partially offset by lower gas prices in the first nine months of 2011 as compared to the same period in 2010.

Net cash used in investing activities was $185.8 million and $208.5 million for the nine months ended September 30, 2011 and 2010, respectively, and decreased primarily due to higher proceeds from the sales of oil and gas properties, partially offset by increased capital expenditures during 2011.

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Net cash provided by financing activities for the nine months ended September 30, 2011 and 2010 was $55.1 million and $128.5 million, respectively. The decrease related primarily to the absence of common stock offerings during the first nine months of 2011 as compared to the first nine months of 2010.

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 October 31, 2011, we had hedged approximately 5,002,000 MMBtu (82,000 MMBtu per day for the remainder of 2011) of our 2011 natural gas production at a weighted average floor or swap price of $5.54 per MMBtu relative to Waha and Houston Ship Channel prices. As of October 31, 2011, we had borrowings outstanding of $195 million under our Revolving Credit Facility with a borrowing base of $340 million. At October 31, 2011, we also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the Revolving Credit Facility. Additionally, as noted under “Sources and Uses of Cash” above, the amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement governing the Revolving Credit Facility. The borrowing base 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 revised 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 September 30, 2011, we entered into a long-term office lease agreement that requires payments of $0 for the remainder of 2011, $0 for 2012, $1.1 million for 2013, $1.4 million for 2014, $1.4 million for 2015 and $8.9 million for 2016 and beyond.

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 our U.S. assets and is guaranteed by certain of our U.S. subsidiaries. The initial Borrowing Base under the Revolving Credit Facility was $350 million and as of September 30, 2011 the borrowing base was $340 million. The next Borrowing Base redetermination is currently expected to occur in November 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 (each as defined in the credit agreement governing the Revolving Credit Facility): (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 September 30, 2011, the ratio of Total Debt to EBITDA was 3.52 to 1.00, the current ratio was 1.52 to 1.0, the Senior Debt to EBITDA ratio was 0.88 to 1.00 and the EBITDA to Interest Expense ratio was 4.01 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.

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

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, 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 September 30, 2011, we had $154 million of borrowings outstanding under the Revolving Credit Facility with a weighted average interest rate of 2.77%. At September 30, 2011, we also had $0.4 million in letters of credit outstanding which reduced the amounts available under the Revolving Credit Facility. Future availability under the $340 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, 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 us. 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. Based on the redetermination and recalculation which occurred in the third quarter 2011, availability of the term loan facility and cost overrun facility is currently $55 million and $6.5 million, respectively.

Initial borrowings under the term loan facility and cost overrun facility were conditioned on, among other things, our having made and spent an approximately $22 million equity contribution to Carrizo UK, which was completed in February 2011. During the third quarter of 2011, we fully utilized the initial equity contribution and borrowed $3.2 million under the facility. Capital expenditures related to the Huntington Field development project totaled approximately $8.1 million in September 2011 and we expect these and future capital expenditures related to the Huntington Field development to be funded by the Huntington Facility. As of October 31, 2011 $9.6 million was outstanding under the Huntington Facility and no letters of credit had been issued.

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.

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.

The Huntington Facility requires Carrizo UK to enter into certain hedging arrangements in order 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

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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 us or our 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.

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 September 30, 2011 by approximately $187 million and was based on crude oil and condensate prices of $90.49 per barrel, natural gas liquids prices of $45.46 per barrel and natural gas prices of $3.34 per Mcf (or a volume weighted average price of $4.85 per Mcfe), representing the unweighted average market prices on the first calendar day of each month during the 12-month period ended September 30, 2011. A ten percent increase in the unweighted average market prices for the 12-month period ended September 30, 2011 would have increased the cost center ceiling by approximately $109 million to $296 million and a ten percent decrease in the unweighted average market prices would have decreased the ceiling test cushion by approximately $162 million to $25 million. This sensitivity analysis is as of September 30, 2011 and, accordingly, does not consider drilling results, production and prices subsequent to September 30, 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 for up to 36 months or as required by terms of the Revolving Credit Facility. 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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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 U.S. natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of September 30, 2011.


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2011		7,544,000	$	5.54	$	5.68
2012		18,943,000	$	5.50	$	5.61
2013		7,300,000	$	5.21	$	5.21

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 $4.82, the floor price becomes the market price plus the put spread of $1.23 on 3,031,000 of the 7,544,000 MMBtus and the remaining 4,513,000 MMBtus would have a floor price of $5.54.


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2011		3,031,000	$	4.82		$	1.23
2012		6,974,400	$	4.91		$	1.27

The following sets forth a summary of our U.S. crude oil derivative positions at average NYMEX prices as of September 30, 2011.


Period	Volume (in Bbls)		Weighted Average Floor Price ($/Bbls)		Weighted Average Ceiling Price ($/Bbls)
2011		138,000	$	92.61	$	106.19
2012		549,000	$	80.00	$	100.18
2013		547,500	$	80.00	$	101.09

In addition to the table above, the Company sold call positions of 18,400 Bbls at a price per barrel of $95.00 for the remainder of 2011.

For the three and nine months ended September 30, 2011 and 2010, we recorded the following related to our derivative instruments:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2011		2010		2011		2010
	(In thousands)
Realized gain (loss), net	$	8,626	$	9,111	$	23,536	$	22,859
Unrealized gain (loss), net		17,030		12,409		13,998		24,677

Gain (loss) on derivative instruments, net	$	25,656	$	21,520	$	37,534	$	47,536

We deferred the payment of premiums associated with certain of our oil and gas derivative instruments totaling $2.2 million and $3.9 million at September 30, 2011 and December 31, 2010, respectively. We classified $1.3 million and $3.9 million as other current liabilities at September 30, 2011 and December 31, 2010, respectively, and $0.9 million other non-current liabilities at September 30, 2011. There were no other non-current liabilities at December 31, 2010. These deferred premiums will be paid to the counterparty with

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each monthly settlement (October 2011 – March 2014) and recognized as a reduction of realized gain (loss) on derivative instruments, net.

Forward Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, including our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, timing and amounts of production, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), capital expenditure plans, planned evaluation of prospects, probability of prospects having oil and gas, expected production or reserves, pipeline connections, increases in reserves, acreage, working capital requirements, commodity price risk management activities and the impact on our average realized prices, the availability of expected sources of liquidity to implement the Company’s business strategies, accessibility of borrowings under our credit facilities, future exploration activity, drilling, completion and fracturing of wells, land acquisitions, production rates, forecasted production, growth in production, development of new drilling programs, participation of our industry partners, exploration and development expenditures, the impact of our business strategies, the benefits, results, effects, availability of and results of new and existing joint ventures and sales transactions, 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, and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information, property acquisition risks, availability of equipment, actions by our midstream and other industry partners, weather, availability of financing, actions by lenders, our ability to obtain permits and licenses, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability of and completion of land acquisitions, completion and connection of wells, and other factors detailed in the “Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 and in our other filings with the SEC, including this quarterly report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the 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 September 30, 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.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended September 30, 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

Other than the risk factors set forth below, there were no material changes to the factors discussed in Part I. Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 and Part II. Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011. 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 are subject to various environmental risks and governmental regulations, including those relating to benzene emissions and hydraulic fracturing, and future regulations may be more stringent.

Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, plug and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. In addition, we may incur costs arising out of property damage, including environmental damage caused by previous owners or operators of property we purchase or lease or relating to third party sites, or injuries to employees and other persons. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, financial position and results of operations.

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Moreover, changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and negatively impact our production and operations. For example, the Texas Commission on Environmental Quality (TCEQ) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett Shale production area. The final rule, which becomes effective in April 2011, establishes new emissions standards for a broad array of equipment at our drillsites, including engines. Additionally, the Environmental Protection Agency (EPA) is currently evaluating, pursuant to a court-mandated settlement, measures to strengthen and to expand certain regulations under the Clean Air Act, including the New Source Performance Standards (NSPS), maximum achievable control technology standards (MACT) and residual risk standards, affecting a wide array of air emission sources in the oil and gas industry. If these or other initiatives result in an increase in regulation, it could increase our costs or reduce our production, which could have a material adverse effect on our results of operations and cash flows.

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Barnett Shale, the Marcellus Shale, the Eagle Ford Shale and the Niobrara Formation. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. The U.S. Congress is currently considering legislation to subject hydraulic fracturing operations to federal regulation and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. The EPA has recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the federal Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing, delaying the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Additionally, the EPA has commenced a comprehensive research study to investigate the potential adverse environmental impacts of hydraulic fracturing, including on water quality and public health. The initial EPA study results are expected to be available in late 2012. In addition, committees of the U.S. House of Representatives and Senate continue to hold hearings to investigate issues related to hydraulic fracturing. The Department of Energy, at the direction of the President, is also studying hydraulic fracturing in order to provide recommendations and identify best practices and other steps to enhance companies’ safety and environmental performance of hydraulic fracturing. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there have been a variety of regulatory initiatives at both the federal and state levels to restrict oil and gas drilling operations in certain locations.

At the state level, the New York legislature has approved a temporary moratorium on drilling involving hydraulic fracturing, and the New York State Department of Environmental Conservation has ceased issuing exploration and production drilling permits, pending completion of an environmental impact statement regarding hydraulic fracturing. Pennsylvania has adopted a variety of regulations since 2010 limiting how and where hydraulic fracturing can be performed in the state, including the adoption of upgraded well construction and casing standards, upgraded cement standards and new recordkeeping requirements. Some municipalities in the state have adopted or are considering adopting bans on drilling, including [areas in which we operate], and the Governor of Pennsylvania has instituted a moratorium on leasing state forest land for gas drilling. Further, in July 2011, the Pennsylvania Governor’s Marcellus Shale Advisory Commission released its report setting forth 96 recommendations on a variety of issues related to natural gas development in Pennsylvania. These recommendations are related to infrastructure; public health, safety, and environmental protection; local impact and emergency response; and economic and workforce development. The Commission made the most recommendations in the area of public health, safety and environmental protection, including doubling penalties authorized for violations of the Oil and Gas Act; increasing bonding requirements; authorizing a state agency to suspend, revoke, or deny permits on a quicker timeframe for violations or failure to correct violations; expanding a well operator’s presumed liability for impaired water quality; amending well stimulation and completion reporting requirements to require disclosure of hazardous chemicals used in fracturing; and other issues related to fracturing operations. Some or all of these recommendations have been incorporated into proposed legislation, will likely be acted upon and may result in the adoption of new laws and regulations governing shale gas development in the Marcellus Shale in Pennsylvania that could result in substantial changes in the way natural gas activities are conducted in the area.

At the international level, the U.K. and EU Parliaments have each discussed implementing a drilling moratorium in the U.K. North Sea. We use hydraulic fracturing extensively and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states of New York and Pennsylvania, could reduce the

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volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

President Obama’s 2012 Fiscal Year Budget proposals, and certain legislation introduced in the United States Congress, if enacted into law, would make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial position and results of operations.

Enactment of proposed severance taxes and impact fees on natural gas wells could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

Legislation has been proposed in the Pennsylvania House of Representatives for the adoption of a severance tax on the production of natural gas in Pennsylvania. Recently, Legislation that is supported by the Governor was proposed for the adoption of an impact fee on all natural gas wells drilled in the state. The proposed impact fee would initially be $40,000 and would decline annually to $10,000 in years four through ten of the life of the well, although other proposals have been made, including a proposal for an impact fee that would fluctuate based on natural gas prices and production levels. The specific characteristics, including the scope and magnitude, of the severance taxes or impact fees have not been determined. A substantial portion of our Marcellus Shale acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts severance taxes or impact fees, they could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

We have no experience drilling wells in the Utica Shale and less information regarding reserves and decline rates in this shale formation than in other areas of our operations.

We have no exploration experience and no development experience in the Utica Shale. We have not participated in the drilling of any wells in this 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 Utica Shale than we have in other areas in which we operate.

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

Issuance of Warrants to Purchase Common Stock under the Land Agreement. On November 24, 2009, the Company entered into a Land Agreement, as amended (the “Land Agreement”), with an unrelated third party and its affiliate. Pursuant to the Land Agreement, and in consideration of the Company’s receipt of an option to purchase certain leases acquired by the third party, the Company issued warrants to purchase 4,816 and 5,152 shares of the Company’s common stock on July 1, 2011 and October 1, 2011, respectively, to such third party with an exercise price of $22.09 and an expiration date of August 21, 2017. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis. The warrants were issued pursuant to an exemption from registration under §4(2) of the Securities Act of 1933, as amended.

See Note 8. Shareholders’ Equity for further discussion of the Land Agreement.

Issuance of Common Stock to the University of Texas at Arlington. On August 29, 2011, the Company issued 38,122 shares of the Company’s common stock to the University of Texas at Arlington at par value ($0.01 per share), for proceeds of $381. This issuance was related to our third quarter 2011 pledge of $1.1 million to the University of Texas at Arlington. The shares were issued pursuant to an exemption from registration under §4(2) of the Securities Act of 1933, as amended.

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

*31.1	–	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2	–	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1	–	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2	–	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101	–	Interactive Data Files

*	Filed herewith.

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SIGNATURES

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


	Carrizo Oil & Gas, Inc.
	(Registrant)

Date: November 8, 2011	By:	/s/ Paul F. Boling
	Vice President, Chief Financial Officer and Secretary
	(Principal Financial Officer)

Date: November 8, 2011	By:	/s/ David L. Pitts
	Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

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