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 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.

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, 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.

2. Summary of Significant Accounting Policies

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. 2016-09 described further below.

Recently Adopted Accounting Pronouncement

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption.

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.

Recently Issued Accounting Pronouncements

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. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017,

with early adoption permitted, provided that it is adopted in its entirety in the same period. Currently, the Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows.

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. 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. Although the Company is in the process of evaluating ASU 2016-02 and the impact the adoption of the new standard will have on its consolidated financial statements and related disclosures, it is currently anticipated to result in an increase in the assets and liabilities recorded on its consolidated balance sheets. The Company will evaluate its existing contracts including, but not limited to, drilling rig contracts and gathering, processing, and transportation contracts to determine if they qualify for lease accounting under ASU 2016-02.

In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, timing, amount and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted for interim and annual periods beginning after December 31, 2016. Companies are permitted to adopt ASU 2014-09 through the use of either the full retrospective approach, meaning the standard is applied to all of the periods presented, or a modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.

The Company is in the process of assessing the impact of ASU 2014-09 with the assistance of an outside consultant. The assessment consists of analyzing the Company’s existing contracts and current accounting policies and practices to identify potential differences that would result from applying 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. Based on assessments performed to date, the Company currently does not expect the impact 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. 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.

Net Income (Loss) Per Common Share

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 months ended March 31, 2017 and 2016 :

3. Acquisition

Sanchez Acquisition

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 Acquisition 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, the Company paid $7.0 million of the $16.8 million for certain of the outstanding leases which were 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 to purchase price adjustments primarily relate to net cash flows from the acquired wells from the effective date to the closing date. 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, 2017, the final payment of $9.8 million was made for the leases that were not conveyed to the Company at the initial closing or the subsequent closing on January 9, 2017. This amount has not been reflected in the preliminary purchase price allocation presented above.

4. Property and Equipment, Net

As of March 31, 2017 and December 31, 2016 , total property and equipment, net consisted of the following:

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $12.69 and $15.22 for the three months ended March 31, 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 million and $4.4 million for the three months ended March 31, 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 million and $5.6 million for the three months ended March 31, 2017 and 2016 , respectively.

Divestiture

During the first quarter of 2017, the Company sold a small 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.

Impairment 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 did not recognize an impairment of proved oil and gas properties for the three months ended March 31, 2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil from December 31, 2015 to March 31, 2016, the Company recognized an impairment of proved oil and gas properties for the three months ended March 31, 2016 . Details of the 12-Month Average Realized Price of crude oil for the three months ended March 31, 2017 and 2016 and the impairment of proved oil and gas properties for the three months ended March 31, 2016 are summarized in the table below: 

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) 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 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, 2017 , 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 2017, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including March 31, 2017 , were reduced to zero . 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 months

ended March 31, 2017, as a result of current quarter activity and the recognition of tax shortfalls from stock-based compensation expense that are now recognized in income tax expense due to the adoption of ASU 2016-09, a partial release of $17.4 million from the valuation allowance was needed to bring the net deferred tax assets to zero. After the impact of the adoption of ASU 2016-09 and the current quarter activity, the valuation allowance as of March 31, 2017 was $562.7 million .

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.

6. Long-Term Debt

Long-term debt consisted of the following as of March 31, 2017 and December 31, 2016 :

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of March 31, 2017 , had a borrowing base of $600.0 million , with $123.0 million of borrowings outstanding at a weighted average interest rate of 2.95% . As of March 31, 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, the credit agreement governing the revolving credit facility provided for interest-only payments until July 2, 2018, when the credit agreement was scheduled to mature and any outstanding borrowings would become 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.

As of March 31, 2017, the Company was 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 Secured Debt to EBITDA of not more than 2.00 to 1.00, (2) a Current Ratio of not less than 1.00 to 1.00, and (3) a ratio of EBITDA to Interest Expense of not less than 2.50 to 1.00. As defined in the credit agreement, EBITDA includes the last four quarters after giving pro forma effect to EBITDA for material acquisitions and dispositions of oil and gas properties, Interest Expense is comprised of the aggregate interest expense paid in cash for the last four quarters, and the Current Ratio includes an add back of the unused portion of lender commitments. As of March 31, 2017 , the ratio of Total Secured Debt to EBITDA was 0.30 to 1.00, the Current Ratio was 2.56 to 1.00 and the ratio of EBITDA to Interest Expense was 4.53 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 dispositions 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, 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).

On May 4, 2017, the Company entered into a ninth amendment to its credit agreement governing the revolving credit facility. See “Note 13. Subsequent Events” for further details.

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. Shareholders’ Equity and Stock-Based Compensation Plans

As of March 31, 2017 , there were 26,275 common shares remaining available for grant under the Incentive Plan of Carrizo Oil & Gas, Inc., as amended (the “Incentive Plan”). The issuance of a restricted stock award, restricted stock unit, or performance share counts as 1.35 shares against the number of common shares available for grant under the Incentive Plan.

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.

Restricted Stock Awards and Units. Under the Incentive Plan, 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, 2017 , unrecognized compensation costs related to unvested restricted stock awards and units was $31.4 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 first quarter of 2017:

During the first quarter of 2017, the Company granted 695,658 restricted stock units to employees and independent contractors with a grant date fair value of $18.8 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. All of these restricted stock units contain a service condition, and certain of these restricted stock units also contain a performance condition. The performance condition has not yet been met. In addition, the Company granted 44,465 restricted stock units to certain employees and independent contractors with a grant date fair value of $1.2 million in lieu of a portion of their annual incentive bonus otherwise payable to them in cash under the Company’s performance-based annual incentive bonus program. These restricted stock units vested substantially concurrent with the time of grant.

Stock Appreciation Rights. SARs can be granted to employees and independent contractors under the Incentive Plan or the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). SARs granted under the Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. As of March 31, 2017 , all outstanding SARs will be settled solely in cash. The liability for SARs as of March 31, 2017 was $6.4 million , of which $6.3 million was classified as “Other current liabilities,” with the remaining $0.1 million classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2016 , the liability for SARs was $11.5 million , of which $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $5.9 million as of March 31, 2017 , and will be recognized over a weighted average period of 1.8 years.

The table below summarizes the activity for SARs for the first quarter of 2017:

During the first quarter of 2017, the Company granted 342,440 SARs under the Cash SAR Plan with a grant date fair value of $4.1 million to certain employees and independent contractors as part of its annual grant of long-term equity incentive awards. The grant date fair value of the SARs was calculated using the Black-Scholes-Merton option pricing model. These SARs will vest ratably over a two -year period and expire five years from the grant date. All of these SARs contain a service condition and performance condition. The performance condition has not yet been met.

The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the first quarter of 2017 :

Performance Shares. Under the Incentive Plan, the Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. The number of performance shares that will vest is based on the 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. As of March 31, 2017 , unrecognized compensation costs related to unvested performance shares was $3.8 million and will be recognized over a weighted average period of 2.1 years.

The table below summarizes performance share activity for the first quarter of 2017 :

During the first quarter of 2017, the Company granted 46,787 target performance shares to certain employees and independent contractors with a grant date fair value of $1.6 million as part of its annual grant of long-term equity incentive awards. The grant date fair value of the performance awards was calculated using a Monte Carlo simulation. In addition to the market condition described above, the performance shares also contain a service condition and performance condition. The performance condition has not yet been met.

The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the first quarter of 2017 :

9. Derivative Instruments

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.

Fixed Price Swaps: The Company receives a fixed price and pays a variable market 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.

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 of existing sold call options and therefore are presented on a net basis in the summary of open crude oil derivative positions below.

Premiums : In lieu of receiving payments for premiums from its counterparties of sold call options, the Company has used the associated premium value to obtain higher fixed prices on fixed price swaps which were executed contemporaneously with those sold call options. The Company elected to defer payment of premiums associated with its purchased call options until the applicable contracts settle on a monthly basis. As of March 31, 2017, the Company had premium obligations of approximately $4.2 million , of which $2.0 million is classified as current derivative liabilities and $2.2 million is classified as noncurrent derivative liabilities on the Company’s consolidated balance sheets. As of December 31, 2016, the Company had premium obligations of approximately $4.6 million , of which $2.0 million was classified as current derivative liabilities and $2.6 million was classified as noncurrent derivative liabilities on the Company’s consolidated balance sheets.

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

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

See “Note 13. Subsequent Events” for details of derivative positions entered into subsequent to March 31, 2017 .

The Company typically has numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, 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. 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.

See “Note 10. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative positions.

(Gain) Loss on Derivatives, Net

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