NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. NATURE OF OPERATIONS

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and LLCs where the Company, as a partner or member, has undivided interests in the oil and gas properties. The consolidated financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

Unconsolidated Investments

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

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

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, shareholders’ equity, net income, comprehensive income or net cash provided by/used in operating, investing or financing activities.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. The operating results for the three months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full year. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves which are used in calculating the amortization of proved oil and gas property costs, the present value of future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates include the, impairment of unproved properties, fair values of derivative instruments, stock-based compensation, the collectability of outstanding

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

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

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-country basis. Internal costs directly associated with acquisition, exploration and development activities are capitalized and totaled $3.0 million and $1.2 million for the three months ended March 31, 2011 and 2010, respectively. Costs related to production, general corporate overhead or similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting oil and natural gas liquids to gas equivalents at the ratio of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter which is applied to capitalized oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average depreciation, depletion and amortization (“DD&A”) per Mcfe was $1.53 and $1.16 for the three months ended March 31, 2011 and 2010, respectively.

Costs not subject to amortization include unevaluated leasehold costs, seismic costs associated with specific unevaluated properties, related capitalized interest and the cost of exploratory wells in progress. Significant costs are assessed individually on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs are added to the oil and gas property costs subject to amortization. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved properties within the next two to five years. Insignificant costs are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease term of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs of $5.3 million and $4.5 million for the three months ended March 31, 2011 and 2010, respectively. Interest is capitalized on the average balance of unproved properties using a weighted-average interest rate based on outstanding borrowings.

Proceeds from the sale of oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company has not had any sales of oil and gas properties that significantly alter that relationship.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (1) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of properties not subject to amortization, and (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (2) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

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

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

Stock-Based Compensation

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

Stock Options and SARs. For stock options and Stock SARs that the Company expects to settle in common stock, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally three years). For Cash SARs and any Stock SARs that the Company expects to settle in cash, stock-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as other accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as other long-term liabilities. The Company recognizes stock-based compensation expense over the vesting period for stock options and SARs using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Stock options typically expire ten years after the date of grant. SARs typically expire seven years after the date of grant. The Company uses the Black-Scholes-Merton option pricing model to compute the fair value of stock options and SARs.

Restricted Stock Awards and Units . For restricted stock awards and units, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted stock awards and units is based on the average of the high and low price of the Company’s common stock on the grant date. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method.

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells after the reserves have been depleted. The asset retirement obligation is recognized when the well is drilled with an associated increase in oil and gas property costs. The asset retirement obligation is recorded at fair value and requires estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligation is discounted using a credit-adjusted risk-free interest rate which is accreted over time to its expected settlement value. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. On a quarterly basis, the Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

Cash and Cash Equivalents

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

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Revenue Recognition

Oil and gas sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company follows the sales method of accounting for oil and gas revenues whereby revenue is recognized for all oil and gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as an asset or liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production, and as of March 31, 2010 and December 31, 2010, the Company did not have any material production imbalances.

Deferred Financing Costs

Deferred financing costs include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of the debt instruments and costs associated with revolving credit facilities. The capitalized costs are amortized to interest expense using the effective interest method over the terms of the debt instruments or credit facilities.

Financial Instruments

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

Derivative Instruments

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

The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. See Note 8. Derivative Instruments for further discussion of the Company’s derivative instruments.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third parties in the oil and gas industry or drilling and completion advances to third-party operators for development costs of wells in progress. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners.

Derivative instruments subject the Company to a concentration of credit risk. See Note 8. Derivative Instruments for further discussion of concentration of credit risk related to the Company’s derivative instruments.

Accounts Receivable and Allowance for Doubtful Accounts

The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability on a quarterly basis and adjusts the allowance as necessary using the specific identification method. At March 31, 2011 and December 31, 2010, the Company’s allowance for doubtful accounts was $2.4 million and $2.5 million, respectively.

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

Income Taxes

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense.

Commitments and Contingencies

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

Foreign Currency

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

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Pinnacle Gas Resources, Inc.

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

4. INCOME TAXES

For the three months ended March 31, 2011 and 2010, all of the Company’s income before income taxes is derived from activities within the United States. The Company’s estimated annual effective income tax rate is used to allocate expected annual income tax expense to interim periods. The rate is the ratio of estimated annual income tax expense to estimated annual income before income taxes, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rate is applied to the year-to-date income before income taxes to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate, will impact future income tax expense. Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35% to income before income taxes as follows:

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

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

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At March 31, 2011, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

Senior Notes

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

Prior Senior Secured Revolving Credit Facility

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

Senior Secured Revolving Credit Facility

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

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

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The Company is subject to certain covenants under the terms of the Revolving Credit Facility which include, but are not limited to, the maintenance of the following financial covenants: (1) a ratio of Total Debt to EBITDA of not more than (a) 4.75 to 1.00 for fiscal quarters ending March 31, 2011 through December 31, 2011, (b) 4.25 to 1.00 for fiscal quarters ending March 31, 2012 through June 30, 2012 and (c) 4.00 to 1.00 for fiscal quarters ending September 30, 2012 and thereafter; (2) a current ratio of not less than 1.0 to 1.0; (3) a Senior Debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to Interest Expense ratio of not less than 2.50 to 1.00. At March 31, 2011, the ratio of Total Debt to EBITDA was 3.71 to 1.00, the current ratio was 2.06 to 1.0, the Senior Debt to EBITDA ratio was .98 to 1.00 and the EBITDA to Interest Expense ratio was 5.13 to 1.00. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the Revolving Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

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

The Revolving Credit Facility is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the Majority Lenders may accelerate amounts due under the Revolving Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).

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

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

UK Huntington Limited Recourse Credit Facility

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

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

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

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

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

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

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

6. COMMITMENTS AND CONTINGENCIES

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

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

7. SHAREHOLDERS’ EQUITY

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

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

8. DERIVATIVE INSTRUMENTS

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital expenditure program. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company’s current long-term strategy is to manage exposure for a substantial, but

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

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

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

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

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

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

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9. FAIR VALUE MEASUREMENTS

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

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

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

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

The fair values of derivative instruments are based on a third-party pricing model which utilizes inputs that include (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. The estimates of fair value are compared to the values provided by the counterparty for reasonableness. Derivative instruments are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. The fair values reported in the consolidated balance sheets are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The assets and liabilities for derivative instruments included in the tables above are presented on a gross basis. The assets and liabilities for derivative instruments included in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to master netting agreements. The fair values of the investment in Pinnacle are based on the closing price of Pinnacle’s common stock on December 31, 2010. The Company had no transfers in or out of Levels 1 or 2 for the three months ended March 31, 2011.

Fair Value of Other Financial Instruments

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

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Other Fair Value Measurements

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

10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information as of March 31, 2011 and December 31, 2010, and for the three months ended March 31, 2011 and March 31, 2010 on a parent company, combined guarantor subsidiaries, non-guarantor subsidiary, eliminating entries, and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiary guarantors operated as independent entities.

Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A.

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