Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of oil, NGLs, and gas primarily from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Niobrara Formation in Colorado, the Utica Shale in Ohio, and the Marcellus Shale in Pennsylvania.

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”) and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. These financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”). Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

The Company has provided a discussion of significant accounting policies, estimates, and judgments in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its 2016 Annual Report. There have been no changes to the Company’s significant accounting policies since December 31, 2016, other than the adoption of Accounting Standards Update No. 2016-09recently adopted accounting pronouncement described further below.

Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero. As a result of adoption, on a prospective basis as prescribed by ASU 2016-09, all windfall tax benefits and tax shortfalls will be recorded as income tax expense or benefit in the consolidated statements of operations. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, this portion of ASU 2016-09 will have no significant effect on the Company’s consolidated balance sheets or consolidated statements of operations. In addition, windfall tax benefits are now required to be presented in cash flows from operating activities in the consolidated statements of cash flows as compared to cash flows from financing activities, which the Company has elected to adopt prospectively. There are no periods presented that would require reclassification of cash flows had the Company elected to adopt this guidance retrospectively. Further, the Company has elected to account for forfeitures as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.

after December 15, 2017,

The Company is in the process ofcurrently assessing the impact of ASU 2014-09 with the assistance2016-02 which includes an analysis of an outside consultant. The assessment consists of analyzing the Company’s existing contracts, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements and current accounting policies and practicesdisclosures that will change as a result of adopting ASU 2016-02. Appropriate systems, controls, and processes to identify potential differences that would result from applyingsupport the requirements of ASU 2014-09. Once the assessment is complete, the Company will implement appropriate changes to its business processes, systems or controls to support recognition and disclosure pursuant to ASU 2014-09.requirements of the new standard are also being evaluated. Based on assessments performed to date,upon its initial assessment, the Company currently does not expectexpects the impactadoption of adopting ASU 2014-09 to have a material effect on the timing or method of revenue recognition as the performance obligations are not materially changed under ASU 2014-09.2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018, however, the Company continues to review the impact of ASU 2014-09 on its consolidated financial statements and related disclosures.2019.

Supplemental net income (loss) per common share information is provided below:

The table below presents the dilutive and anti-dilutive weighted average common shares outstanding for the three and six months ended March 31,June 30, 2017 and 2016:

On December 14, 2016, the Company completed its initial closing of the acquisition of oil and gas properties in the Eagle Ford Shale from Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation (the “Sanchez Acquisition”). The Sanchez Acquisitiontransaction had an effective date of June 1, 2016 and was accounted for under the acquisition method of accounting whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then available information.

At the time of the initial close, an adjustment to the purchase price of $16.8 million was made for leases that were not conveyed to the Company. On January 9, 2017 and April 13, 2017, the Company paid $7.0 million of the $16.8and $9.8 million, respectively, for certain of thethese outstanding leases which werewhen conveyed to the Company. See the updated purchase price allocation presented below.

The purchase price allocation for the Sanchez Acquisition is preliminary and subject to change based on closings subsequent to March 31, 2017, related to the remaining leases that were not conveyed to the Company at the initial closing on December 14, 2016 or the subsequent closing on January 9, 2017 and final updates tosettlement of purchase price adjustments primarily relaterelated to net cash flows from the acquired wells from the effective date to the closing date. The Company currently expects to finalize its allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date during the fourth quarter of 2017. The following presents the purchase price and the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. The Company currently expects these amounts will be finalized during the fourth quarter of 2017.

On April 13,June 28, 2017, the finalCompany entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) for a purchase price of $648.0 million, subject to customary purchase price adjustments (the “ExL Acquisition”). The transaction has an effective date of May 1, 2017 and is expected to close on August 10, 2017. On June 28, 2017, the Company paid $75.0 million to the seller as a deposit, which was funded with borrowings under the Company’s

The Company has also agreed to pay an additional $50.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00 for any the years of 2018, 2019, 2020 and 2021, with such payments due on January 29, 2019, January 28, 2020, January 28, 2021 and January 28, 2022, respectively. This payment of $9.8 million was made(the “Contingent ExL Payment”) will be zero for the leases thatrespective year if such EIA WTI average price of a barrel of oil is $50.00 or below for any of such years, and the Contingent ExL Payment is capped at and will not exceed $125.0 million.

The Company intends to fund the remaining purchase price due at closing with the net proceeds from the pending issuance and sale of Preferred Stock and warrants described below, the net proceeds from the common stock offering completed on July 3, 2017, which, pending the closing of the ExL Acquisition, were not conveyedused to temporarily repay a portion of the borrowings outstanding under the revolving credit facility and the net proceeds from the senior notes offering completed on July 14, 2017, which, pending the closing of the ExL Acquisition, a portion was used to temporarily repay borrowings outstanding under the revolving credit facility and for general corporate purposes with the remainder temporarily invested in cash equivalents. See “Note 13. Subsequent Events” for details regarding the common stock and senior notes offerings completed in July 2017. Upon closing the ExL Acquisition, the Company will become the operator of the ExL Properties with an approximate 70% average working interest.

On June 28, 2017, the Company entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”) to issue and sell in a private placement (i) 250,000 shares of 8.875% redeemable preferred stock, par value $0.01 per share (the “Preferred Stock”) and (ii) warrants for 2,750,000 shares of the Company’s common stock, with a term of ten years and an exercise price of $16.08 per share, exercisable only on a net share settlement basis, for a cash purchase price equal to $970.00 per share of Preferred Stock purchased. The Company paid the GSO Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement. The closing of the private placement is expected to occur on August 10, 2017 contemporaneously with the closing of the ExL Acquisition and is subject to certain closing conditions, including the closing of the ExL Acquisition. The Company expects to receive net proceeds of approximately $236.2 million, net of commitment fees and offering costs, from the issuance and sale of the Preferred Stock and warrants. The Company will use the net proceeds to fund a portion of the purchase price of the ExL Acquisition. The Company also agreed to enter into a registration rights agreement with the GSO Funds at the initial closing orof the subsequent closing on January 9, 2017. This amount has not been reflected inprivate placement, pursuant to which the preliminary purchase price allocation presented above.Company will agree to provide certain registration and other rights for the benefit of the GSO Funds.

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $12.69$12.43 and $15.22$13.41 for the three months ended March 31,June 30, 2017 and 2016, respectively, and $12.55 and $14.32 for the six months ended June 30, 2017 and 2016, respectively.

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $5.4$1.9 million and $4.4$1.4 million for the three months ended March 31,June 30, 2017 and 2016, respectively, and $7.3 million and $5.8 million for the six months ended June 30, 2017 and 2016, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling $3.8$4.0 million and $5.6$4.9 million for the three months ended March 31,June 30, 2017 and 2016, respectively, and $7.8 million and $10.5 million for the six months ended June 30, 2017 and 2016, respectively.

During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million. The proceeds from this sale were recognized as a reduction of proved oil and gas properties.

At the end of each quarter, the net book value of oil and gas properties, less 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 unproved properties not being amortized, 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. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current period (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense or benefit to interim periods. The rates are the ratio of estimated annual income tax expense or benefit to estimated annual income or loss 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 discrete item occurs. The estimated annual effective income tax rates are applied to the year-to-date income or loss before income taxes by taxing jurisdiction to determine the income tax expense or benefit allocated to the interim period. The Company updates its estimated annual effective income tax rates on a quarterly basis considering the geographic mix of income or loss attributable to the tax jurisdictions in which the Company operates.

The Company’s income tax (expense) benefit differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) before income taxes as follows:

Deferred tax assets are recorded for net operating losses and temporary differences between the book and tax basis of assets and

A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at March 31,June 30, 2017, driven primarily by the impairments of proved oil and gas properties recognized beginning

As a result of adopting ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017.

For the three and six months

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of March 31,June 30, 2017, had a borrowing base of $600.0$900.0 million, of which $800.0 million has been committed by lenders, with $123.0$282.3 million of borrowings outstanding at a weighted average interest rate of 2.95%3.44%. As of March 31,June 30, 2017, the Company also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. As of March 31, 2017, theThe credit agreement governing the revolving credit facility providedprovides for interest-only payments until July 2, 2018,May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time), when the credit agreement was scheduled to maturematures and any outstanding borrowings would becomeare due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at

least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination.

Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as of March 31, 2017, as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations.

The credit agreement 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 credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

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 materially adverse effect on the financial position or results of operations of the Company.

AsAt the Company’s annual meeting of March 31,shareholders on May 16, 2017, there were 26,275 common shares remaining available for grant undershareholders approved the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Incentive“Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding

As of June 30, 2017, there were 1,811,671 common shares remaining available for grant under the 2017 Incentive Plan. The issuance of a restricted stock award, restricted stock unit, or performance share counts as 1.35 shares while the issuance of a stock option or stock-settled stock appreciation right counts as 1.00 share against the number of common shares available for grant under the 2017 Incentive Plan. As of June 30, 2017, the Company does not have any outstanding stock options and all outstanding stock appreciation rights will be settled solely in cash.

Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance shares is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties.

The table below summarizes restricted stock award and unit activity for the first quarter ofsix months ended June 30, 2017:

The table below summarizes the activity for SARs for the first quarter ofsix months ended June 30, 2017:

The Company recognized the following stock-based compensation expense, net for the periods indicated:

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, three-way collars and purchased and sold call options, which are described below.

All of the Company’s purchased call options were executed contemporaneously with sales of call options to increase the fixed price of existing sold call options and therefore are presented on a net basis in the summary of open crude oil derivative positions below.

The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of March 31,June 30, 2017:

The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of March 31,June 30, 2017:

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty,counterparty. Deferred premiums are netted with the fair value derivative asset and liability positions, which positions are all offset to a single fair value asset or liability, at the end of each reporting period, including the deferred premiums associated with its hedge positions.period. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premiums, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.

Counterparties to the Company’s derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds our unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral.

Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties or its counterparty’s parent company.

All derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. The deferred premium obligations are recorded in the period in which they are incurred and are netted with the derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, as well as deferred premium obligations, recorded in the Company’s consolidated balance sheets as of March 31,June 30, 2017 and December 31, 2016 are summarized below:

The Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of derivative instruments are recognized as (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the changes occur. All deferred premium obligations are recognized in (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the premium obligations are incurred. Cash flows are impacted to the extent that settlements under these contracts, including any deferred premiums, result in payments or receipts from the counterparty during the period and are presented as cash received (paid) for derivative settlements, net in the Company's consolidated statements of cash flows.

The effect of derivative instruments and deferred premiums on the Company’s consolidated statements of operations for the three and six months ended March 31,June 30, 2017 and 2016 by commodity is summarized below:

The cash flow impactseffect of the Company’s derivative instruments are presented as separate line items within the net cash provided by operating activities inand deferred premiums on the Company’s consolidated statements of cash flows.flows for the three and six months ended June 30, 2017 and 2016 are summarized below: