NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Operations

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 crude oil, NGLs, and gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

Consolidated Financial Statements

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, 2017 (“ 2017 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes in the 2017 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.

2. Summary of Significant Accounting Policies

Revenue Recognition

Impact of ASC 606 Adoption . Effective January 1, 2018, the Company adopted ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASC 606”) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information for the three months ended March 31, 207 has not been recast and continues to be reported under the accounting standards in effect for that period. Additionally, adoption of ASC 606 did not impact net income attributable to common shareholders and the Company does not expect that it will do so in future periods.

The table below summarizes the impact of adoption for the three months ended March 31, 2018:

Changes to crude oil, NGL, and natural gas revenues and lease operating expense are due to the conclusion that the Company controls the product throughout processing before transferring to the customer for certain natural gas processing arrangements. Therefore, any transportation, gathering, and processing fees incurred prior to transfer of control are included in lease operating expense.

The Company’s revenues are comprised solely of revenues from customers and include the sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on our single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of March 31, 2018 and December 31, 2017, receivables from contracts with customers were $66.3 million and $85.6 million , respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of income.

Crude oil sales. Crude oil production is primarily sold at the wellhead at an agreed upon index price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the wellhead, net of transportation costs incurred by the purchaser.

Natural gas and NGL sales. Natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. The Company evaluates whether it is the principal or agent in the transaction and has concluded it is the principal and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented in “Lease operating expense” in the consolidated statements of income as the Company maintains control throughout processing.

Transaction Price Allocated to Remaining Performance Obligations . The Company applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Recently Adopted Accounting Pronouncements

Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or divestitures) of assets or businesses. Effective January 1, 2018, the Company adopted ASU 2017-01 using the prospective method and will apply the clarified definition of a business to future acquisition and divestitures.

Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. Effective January 1, 2018, the Company adopted ASU 2016-15 using the retrospective approach as prescribed by ASU 2016-15. There were no changes to the statement of cash flows as a result of adoption.

Recently Issued Accounting Pronouncements

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach.

The Company is in the process of reviewing and determining the contracts to which ASU 2016-02 applies with the assistance of a third party consultant. These include contracts such as non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements, and contracts for the use of vehicles and well equipment. The Company continues to review current accounting policies, controls, processes, and disclosures that will change as a result of adopting the new standard. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) increases in depreciation, depletion and amortization and interest expense, (iii) decreases in lease operating and

general and administrative expense and (iv) additional disclosures. The Company plans to adopt the guidance on the effective date of January 1, 2019.

Net Income Attributable to Common Shareholders Per Common Share

Supplemental net income attributable to common shareholders per common share information is provided below:

The table below presents the weighted average dilutive and anti-dilutive securities outstanding for the periods presented which consisted of unvested restricted stock awards and units, unvested performance shares and exercisable common stock warrants:

3. Acquisitions and Divestitures of Oil and Gas Properties

Acquisitions

ExL Acquisition. On August 10, 2017, the Company closed on the acquisition of oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) for aggregate net proceeds of $679.8 million (the “ExL Acquisition”). The Company also agreed to pay an additional $50.0 million per year if crude oil prices exceed specific thresholds for each of the years of 2018 through 2021 with a cap of $125.0 million as described in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Company’s 2017 Annual Report (the “Contingent ExL Consideration”). The Company determined that the Contingent ExL Consideration is an embedded derivative and has reflected the liability at fair value in both current and non-current “Derivative liabilities” in the consolidated balance sheets. The total fair value of the Contingent ExL Consideration as of March 31, 2018 and December 31, 2017 was $91.5 million and $85.6 million , respectively. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details. The contingent consideration, if paid, will be recognized as a reduction of the fair value liability in the consolidated balance sheets.

The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information as disclosed in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Company’s 2017 Annual Report.

Included in the consolidated statements of income for the three months ended March 31, 2018 are total revenues of $43.5 million and net income attributable to common shareholders of $34.8 million from the ExL Acquisition.

Divestitures

Niobrara. On January 19, 2018, the Company closed on its sale of substantially all of its assets in the Niobrara Formation for estimated aggregate net proceeds of $132.3 million , subject to post-closing adjustments. The estimated aggregate net proceeds were recognized as a reduction of proved oil and gas properties.

The Company could also receive contingent consideration of $5.0 million per year if crude oil prices exceed specific thresholds for each of the years of 2018 through 2020 as described in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Company’s 2017 Annual Report (the “Contingent Niobrara Consideration”). The Company determined that the Contingent

Niobrara Consideration is an embedded derivative and has reflected the asset at fair value in current and non-current “Other assets” in the consolidated balance sheets. The total fair value of the Contingent Niobrara Consideration as of March 31, 2018 and January 19, 2018 was $8.3 million and $7.9 million , respectively. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

Eagle Ford. On January 31, 2018, the Company closed on its sale of a portion of its assets in the Eagle Ford Shale to EP Energy E&P Company, L.P. for estimated aggregate net proceeds of $247.1 million , subject to post-closing adjustments. The estimated aggregate net proceeds were recognized as a reduction of proved oil and gas properties.

Utica. On November 15, 2017, the Company closed on its sale of substantially all of its assets in the Utica Shale for aggregate net proceeds of $63.1 million .

The Company could also receive contingent consideration of $5.0 million per year if crude oil prices exceed specific thresholds for each of the years of 2018 through 2020 as described in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Company’s 2017 Annual Report (the “Contingent Utica Consideration”). The Company determined that the Contingent Utica Consideration is an embedded derivative and has reflected the asset at fair value in current and non-current “Other assets” in the consolidated balance sheets. The total fair value of the Contingent Utica Consideration as of March 31, 2018 and December 31, 2017 was $9.0 million and $8.0 million , respectively. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

Marcellus. On November 21, 2017, the Company closed on its sale of substantially all of its assets in the Marcellus Shale for aggregate net proceeds of $73.9 million .

The Company could also receive contingent consideration of $3.0 million per year if natural gas prices exceed specific thresholds for each of the years of 2018 through 2020 with a cap of $7.5 million as described in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Company’s 2017 Annual Report (the “Contingent Marcellus Consideration”). The Company determined that the Contingent Marcellus Consideration is an embedded derivative and has reflected the asset at fair value in current and non-current “Other assets” in the consolidated balance sheets. The total fair value of the Contingent Marcellus Consideration as of March 31, 2018 and December 31, 2017 was $1.7 million and $2.2 million , respectively. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

4. Property and Equipment, Net

As of March 31, 2018 and December 31, 2017 , total property and equipment, net consisted of the following:

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $13.73 and $12.69 for the three months ended March 31, 2018 and 2017 .

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $6.6 million and $5.4 million for the three months ended March 31, 2018 and 2017 , 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 $10.4 million and $3.8 million for the three months ended March 31, 2018 and 2017 .

5. Income Taxes

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 differs from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of 21% and 35% for the three months ended March 31, 2018 and 2017, respectively, to income before income taxes as follows:

Significant changes in the Company’s operations, including the ExL Acquisition in the Delaware Basin in the third quarter of 2017 and divestitures of substantially all of the Company’s assets in the Utica and Marcellus Shales in the fourth quarter of 2017 and in the Niobrara Formation in the first quarter of 2018, resulted in changes to the Company’s state apportionment for estimated state deferred tax liabilities. As a result of these changes, as well as current period activity, the Company recorded state current and deferred income tax expense of $0.3 million primarily associated with the future Texas deferred tax liabilities.

Tax Cuts and Jobs Act

On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 which allowed the Company to provide a provisional estimate of the impacts of the Act in its earnings for the year ended December 31, 2017 and also provided a one-year measurement period in which the Company would record additional impacts from the enactment of the Act as they are identified. As of March 31, 2018 , the Company had not made any changes to the provisional estimates in its Consolidated Financial Statements included in the 2017 Annual Report. While the Company has made a reasonable estimate of the effects on its existing deferred tax balances, it has not completed its accounting for the tax effects of the enactment of the Act and continues to analyze the effects of the Act in its consolidated financial statements and operations.

Deferred Tax Assets Valuation Allowance

Deferred tax assets are recorded for net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

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, 2018 , driven primarily by the impairments of proved oil and gas properties recognized beginning

in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the third quarter of 2015, and continuing through the first quarter of 2018, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, at the end of each quarter, including March 31, 2018 , the Company determined a valuation allowance was required.

For the three months ended March 31, 2018 , the Company reduced the valuation allowance by $8.4 million due to a partial release as a result of current period activity. After the impact of the partial release, the valuation allowance as of March 31, 2018 was $324.6 million . For the three months ended March 31, 2017 , as a result of adopting Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“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 . This increase in the valuation allowance was more than offset by a partial release of $17.4 million as a result of activity during the first quarter of 2017.

6. Long-Term Debt

Long-term debt consisted of the following as of March 31, 2018 and December 31, 2017 :

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of March 31, 2018 , had a borrowing base of $830.0 million , with an elected commitment amount of $800.0 million , and $421.7 million of borrowings outstanding at a weighted average interest rate of 4.24% . As of March 31, 2018 , the Company had no letters of credit outstanding. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes due 2020 (the “ 7.50% Senior Notes”) have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are 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.

On January 31, 2018, as a result of the divestiture in the Eagle Ford Shale discussed above, the Company’s borrowing base under the senior secured revolving credit facility was reduced from $900.0 million to $830.0 million , however, the elected commitment amount remained unchanged at $800.0 million . See “Note 14. Subsequent Events” for details of the twelfth amendment that was entered into in May 2018.

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 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 income.

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA for the fiscal quarter ended March 31, 2018 is calculated based on an annualized average of the last three fiscal quarters, and EBITDA for fiscal quarters ending thereafter will be calculated based on the last four fiscal quarters, in each case after giving pro forma effect to EBITDA for material acquisitions and divestitures of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of March 31, 2018 , the ratio of Total Debt to EBITDA was 2.60 to 1.00 and the Current Ratio was 1.52 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings.

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 and divestitures of oil and gas properties, mergers, 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).

Redemptions of 7.50% Senior Notes

On January 19, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on February 18, 2018, $100.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On February 20, 2018, the Company paid an aggregate redemption price of $105.1 million , which included a redemption premium of $1.9 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $100.0 million of the 7.50% Senior Notes, the Company recorded a loss on extinguishment of debt of $2.7 million , which includes the redemption premium paid to redeem the notes and non-cash charges of $0.8 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes.

On January 31, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on March 2, 2018, $220.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On March 2, 2018, the Company paid an aggregate redemption price of $231.8 million , which includes a redemption premium of $4.1 million as well as accrued and unpaid interest of $7.7 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $220.0 million of the 7.50% Senior Notes, the Company recorded a loss on extinguishment of debt of $6.0 million , which includes the redemption premium paid to redeem the notes and non-cash charges of $1.9 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes.

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

The results of operations and financial position 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. Preferred Stock and Warrants

On August 10, 2017, the Company closed on the issuance and sale in a private placement of (i) $250.0 million initial liquidation preference ( 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 (the “Warrants”), for a cash purchase price equal to $970.00 per share of Preferred Stock, to certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”). The Company used the net proceeds of approximately $236.4 million , net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes.

The Preferred Stock has a liquidation preference of $1,000.00 per share and bears an annual cumulative dividend rate of 8.875% , payable on March 15, June 15, September 15 and December 15 of any given year. The Company may elect to pay all or a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending:

If the Company fails to satisfy the Preferred Stock dividend on the applicable dividend payment date, then the unpaid dividend will be added to the liquidation preference until paid.

The Preferred Stock outstanding is not mandatorily redeemable, but can be redeemed at the Company’s option and, in certain circumstances, at the option of the holders of the Preferred Stock. On or prior to August 10, 2018, the Company had the right to redeem up to 50,000 shares of Preferred Stock, in cash, at $1,000.00 per share, plus accrued and unpaid dividends in an amount not to exceed the sum of the cash proceeds of divestitures of oil and gas properties and related assets, the sale or issuance of the Company’s common stock and the sale of any of the Company’s wholly owned subsidiaries. On January 19, 2018, the Company provided a notice to be delivered to the holders of its Preferred Stock under which it called for redemption of 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, on January 24, 2018. The Company paid $50.5 million on January 24, 2018 upon redemption, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends, with a portion of the proceeds from the divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details.

As a result of the redemption, the Company recorded a loss on redemption of preferred stock of $7.1 million , which is presented with the Preferred Stock dividends and accretion in the consolidated statements of income. This loss was calculated as the difference between the consideration transferred to the holders of the Preferred Stock, excluding accrued and unpaid dividends, of $50.0 million and 20% of the carrying value of the Preferred Stock on the date of redemption plus any direct costs incurred as a result of the redemption.

In addition, at any time on or prior to August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at a redemption premium of 104.4375% , plus accrued and unpaid dividends and the present value on the redemption date of all quarterly dividends that would be payable from the redemption date through August 10, 2020. After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends.

The holders of the Preferred Stock have the option to cause the Company to redeem the Preferred Stock under the following conditions:

For the first two conditions described above, the Company has the option to settle any such redemption in cash or shares of its common stock and the holders of the Preferred Stock may elect to revoke or reduce the redemption if the Company elects to settle in shares of common stock.

The Preferred Stock are non-voting shares except as required by the Company’s articles of incorporation or bylaws. However, so long as the GSO Funds beneficially own more than 50% of the Preferred Stock, the consent of the holders of the Preferred Stock will be required prior to issuing stock senior to or on parity with the Preferred Stock, incurring indebtedness subject to a leverage ratio, agreeing to certain restrictions on dividends on, or redemption of, the Preferred Stock and declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year subject to a leverage ratio. Additionally, if the Company does not redeem the Preferred Stock before August 10, 2024, in connection with a change of control or failure to pay a quarterly dividend within three months of the applicable payment date, the holders of the Preferred Stock are entitled to additional rights including:

The Preferred Stock is presented as temporary equity and is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The Company reassesses the presentation of the Preferred Stock in its consolidated balance sheets on a quarterly basis.

The table below summarizes Preferred Stock activity for the three months ended March 31, 2018 :

Preferred Stock Dividends and Accretion

For the three months ended March 31, 2018 , the Company declared and paid $4.9 million of dividends in cash. On January 24, 2018, the Company paid $0.5 million of dividends to the holders of record of the Preferred Stock which was redeemed, as described above. Additionally, the Company paid $4.4 million of dividends to the holders of record on March 15, 2018.

For the three months ended March 31, 2018 , the Company recorded accretion of the Preferred Stock of $0.8 million , which is presented with the dividends in the consolidated statements of income.

9. Shareholders’ Equity and Stock-Based Compensation

Stock-Based Compensation

As of March 31, 2018 , there were 318,109 common shares remaining available for grant under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”). Each restricted stock award, restricted stock unit, or performance share granted under the 2017 Incentive Plan counts as 1.35 shares while a stock option or stock-settled stock appreciation right granted under the 2017 Incentive Plan counts as 1.00 share against the number of common shares available for grant under the 2017 Incentive Plan.

Restricted Stock Awards and Units. Restricted stock awards can be granted to employees and independent contractors and restricted stock units can be granted to employees, independent contractors, and non-employee directors. As of March 31, 2018 , unrecognized compensation costs related to unvested restricted stock awards and units was $35.0 million and will be recognized over a weighted average period of 2.4 years.

The table below summarizes restricted stock award and unit activity for the three months ended March 31, 2018 :

During the first quarter of 2018, the Company granted 1,343,412 restricted stock units to employees and independent contractors with a grant date fair value of $19.7 million as part of its annual grant of long-term equity incentive awards. These restricted stock units will vest ratably over a three -year period.

Stock Appreciation Rights (“SARs”). SARs can be granted to employees and independent contractors under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”) and employees, independent contractors, and non-employee directors under the 2017 Incentive Plan. SARs granted under the Cash SAR Plan may only be settled in cash, while SARs granted under the 2017 Incentive Plan can be settled in shares of common stock or cash, at the option of the Company. Outstanding SARs that have been granted under the 2017 Incentive Plan have been deemed to be settled in cash, therefore, all outstanding SARs will be settled in cash. The grant date fair value of SARs is calculated using the Black-Scholes-Merton option pricing model. The liability for SARs as of March 31, 2018 was $2.9 million , of which $0.1 million was classified as “Other current liabilities,” with the remaining $2.8 million classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2017 , the liability for SARs was $4.4 million , all of which was classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $5.8 million as of March 31, 2018 , and will be recognized over a weighted average period of 2.8 years.

The table below summarizes the activity for SARs for the three months ended March 31, 2018 :

During the first quarter of 2018, the Company granted 616,686 SARs under the 2017 Incentive Plan with a grant date fair value of $4.9 million to certain employees and independent contractors as part of its annual grant of long-term equity incentive awards. These SARs will vest ratably over a three -year period and expire approximately seven years from the grant date.

The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the three months ended March 31, 2018 :

Performance Shares. The Company can grant performance shares to employees, independent contractors, and non-employee directors, where each performance share represents the right to receive one share of common stock. The number of performance shares that will vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three -year performance period, the last day of which is also the vesting date. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of March 31, 2018 , unrecognized compensation costs related to unvested performance shares was $3.3 million and will be recognized over a weighted average period of 2.4 years.

The table below summarizes performance share activity for the three months ended March 31, 2018 :

During the first quarter of 2018, the Company granted 93,771 target performance shares to certain employees and independent contractors with a grant date fair value of $1.8 million as part of its annual grant of long-term equity incentive awards. Also during the first quarter of 2018, the Company issued 49,458 shares of common stock for 56,517 target performance shares that vested during the first quarter of 2018 with a multiplier of 88% based on the Company’s final TSR ranking during the performance period.

The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the three months ended March 31, 2018 :

Stock-Based Compensation Expense, Net. Stock-based compensation expense associated with restricted stock awards and units, SARs and performance shares is reflected as “General and administrative expense, net” in the consolidated statements of income.

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, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure 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, basis swaps, three-way collars and purchased and sold call options, which are described below.

Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes.

Basis Swaps: The Company receives a variable NYMEX settlement price, plus or minus a fixed differential price, and pays a variable published index price to the counterparties over specified periods for contracted volumes.

Three-Way Collars: A three-way collar is a combination of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the market price is between the fixed floor price and the fixed sub-floor price or is above the fixed ceiling price, the Company receives the fixed floor price or pays the market price, respectively. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. The Company has incurred premiums on certain of these contracts in order to obtain a higher floor price and/or ceiling price.

Sold Call Options : These contracts give the counterparties the right, but not the obligation, to buy contracted volumes from the Company over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the counterparties to pay premiums to the Company that represent the fair value of the call option as of the date of purchase.

Purchased Call Options : These contracts give the Company the right, but not the obligation, to buy contracted volumes from the counterparties over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the counterparties pay the Company the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the Company to pay premiums to the counterparties that represent the fair value of the call option as of the date of purchase.

All of the Company’s purchased call options were executed contemporaneously with sales of call options to increase the fixed price on a portion of the existing sold call options and therefore are presented on a net basis in the “Net Sold Call Options” table below.

Premiums : In order to increase the fixed price on a portion of the Company’s existing sold call options, as mentioned above, the Company incurred premiums on its purchased call options. Additionally, the Company has incurred premiums on certain of its three-way collars in order to obtain a higher floor price and/or ceiling price. The payment of premiums associated with the Company’s purchased call options and certain of the three-way collars are deferred until the applicable contracts settle on a monthly basis. When the Company has entered into three-way collars which span multiple years, the Company has elected to defer payment of certain of the premiums until the final year’s contracts settle on a monthly basis.

The following table sets forth a summary of the Company’s outstanding crude oil derivative positions at weighted average contract prices as of March 31, 2018 :