CARRIZO OIL & GAS INC - FORM 10-Q

Attached files

file	filename
EX-10.1 - EXHIBIT 10.1 NINTH AMENDMENT TO CREDIT AGREEMENT - CARRIZO OIL & GAS INC	ex101carrizoninthamendment.htm
EX-32.2 - SECTION 906 CERTIFICATION OF CFO - CARRIZO OIL & GAS INC	ex3221q17.htm
EX-32.1 - SECTION 906 CERTIFICATION OF CEO - CARRIZO OIL & GAS INC	ex3211q17.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CFO - CARRIZO OIL & GAS INC	ex3121q17.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CEO - CARRIZO OIL & GAS INC	ex3111q17.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________

FORM 10-Q

_________________________________________________



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017



o	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 000-29187-87

_________________________________________________

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

_________________________________________________



Texas		76-0415919
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

500 Dallas Street, Suite 2300, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 328-1000

(Registrant’s telephone number)

____________________________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO ¨

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



Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of April 28, 2017 was 65,807,064.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	2
	Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016	3
	Consolidated Statement of Shareholders’ Equity for the three months ended March 31, 2017	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34
Part II. Other Information
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	34
Item 6.	Exhibits	35
Signatures		36

Part I. Financial Information

Item 1. Consolidated Financial Statements (Unaudited)

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)



	March 31, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents		$2,391			$4,194
Accounts receivable, net	67,257			64,208
Derivative assets	1,036			1,237
Other current assets	2,542			3,349
Total current assets	73,226			72,988
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,371,335			1,294,667
Unproved properties, not being amortized	253,270			240,961
Other property and equipment, net	9,599			10,132
Total property and equipment, net	1,634,204			1,545,760
Other assets	7,010			7,579
Total Assets		$1,714,440			$1,626,327

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$51,968			$55,631
Revenues and royalties payable	44,038			38,107
Accrued capital expenditures	69,040			36,594
Accrued interest	20,957			22,016
Accrued lease operating expense	11,919			12,377
Derivative liabilities	7,456			22,601
Other current liabilities	22,650			24,633
Total current liabilities	228,028			211,959
Long-term debt	1,362,046			1,325,418
Asset retirement obligations	21,737			20,848
Derivative liabilities	18,675			27,528
Other liabilities	14,027			17,116
Total liabilities	1,644,513			1,602,869
Commitments and contingencies
Shareholders’ equity
Common stock, $0.01 par value, 90,000,000 shares authorized; 65,796,342 issued and outstanding as of March 31, 2017 and 65,132,499 issued and outstanding as of December 31, 2016	658			651
Additional paid-in capital	1,672,332			1,665,891
Accumulated deficit	(1,603,063		)	(1,643,084		)
Total shareholders’ equity	69,927			23,458
Total Liabilities and Shareholders’ Equity		$1,714,440			$1,626,327

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)



	Three Months Ended March 31,
	2017			2016
Revenues
Crude oil		$128,092			$67,996
Natural gas liquids	7,425			3,440
Natural gas	15,838			9,826
Total revenues	151,355			81,262

Costs and Expenses
Lease operating	29,845			23,675
Production taxes	6,208			3,431
Ad valorem taxes	2,967			2,070
Depreciation, depletion and amortization	54,382			59,577
General and administrative, net	21,703			21,303
(Gain) loss on derivatives, net	(25,316		)	(10,553		)
Interest expense, net	20,571			18,713
Impairment of proved oil and gas properties	—			274,413
Other (income) expense, net	974			(93		)
Total costs and expenses	111,334			392,536

Income (Loss) Before Income Taxes	40,021			(311,274		)
Income tax expense	—			(121		)
Net Income (Loss)		$40,021			($311,395	)

Net Income (Loss) Per Common Share
Basic		$0.61			($5.34	)
Diluted		$0.61			($5.34	)

Weighted Average Common Shares Outstanding
Basic	65,188			58,360
Diluted	65,778			58,360

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)



	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount		Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of December 31, 2016	65,132,499		$651		$1,665,891			($1,643,084	)		$23,458
Stock-based compensation expense	—	—		6,448			—			6,448
Issuance of common stock upon grants of restricted stock awards, net of forfeitures, and vestings of restricted stock units and performance shares	663,843	7		(7		)	—			—
Net income	—	—		—			40,021			40,021
Balance as of March 31, 2017	65,796,342		$658		$1,672,332			($1,603,063	)		$69,927

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Three Months Ended March 31,
	2017			2016
Cash Flows From Operating Activities
Net income (loss)		$40,021			($311,395	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	54,382			59,577
Impairment of proved oil and gas properties	—			274,413
(Gain) loss on derivatives, net	(25,316		)	(10,553		)
Cash received for derivative settlements, net	1,519			51,163
Stock-based compensation expense, net	2,014			11,522
Non-cash interest expense, net	1,091			1,160
Other, net	1,620			1,116
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(2,749		)	(2,065		)
Accounts payable	6,661			(18,711		)
Accrued liabilities	(2,154		)	(1,667		)
Other assets and liabilities, net	(681		)	(692		)
Net cash provided by operating activities	76,408			53,868
Cash Flows From Investing Activities
Capital expenditures - oil and gas properties	(123,749		)	(125,989		)
Acquisitions of oil and gas properties	(7,032		)	—
Proceeds from sales of oil and gas properties, net	17,372			1,785
Other, net	(417		)	(617		)
Net cash used in investing activities	(113,826		)	(124,821		)
Cash Flows From Financing Activities
Borrowings under credit agreement	280,504			73,647
Repayments of borrowings under credit agreement	(244,504		)	(43,097		)
Payments of debt issuance costs	(50		)	(50		)
Other, net	(335		)	(307		)
Net cash provided by financing activities	35,615			30,193
Net Decrease in Cash and Cash Equivalents	(1,803		)	(40,760		)
Cash and Cash Equivalents, Beginning of Period	4,194			42,918
Cash and Cash Equivalents, End of Period		$2,391			$2,158

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

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. 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,

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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:



	Three Months Ended March 31,
	2017		2016
	(In thousands, except per share amounts)
Net Income (Loss)		$40,021		($311,395	)
Basic weighted average common shares outstanding	65,188		58,360
Effect of dilutive instruments	590		—
Diluted weighted average common shares outstanding	65,778		58,360
Net Income (Loss) Per Common Share
Basic		$0.61		($5.34	)
Diluted		$0.61		($5.34	)

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



	Three Months Ended March 31,
	2017	2016
	(In thousands)
Dilutive	590	—
Anti-dilutive ⁽¹⁾	5	665


(1)	For the three months ended March 31, 2016, the Company reported a net loss. As a result, all potentially dilutive common shares outstanding were anti-dilutive.

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.



	Preliminary Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$477
Oil and gas properties
Proved properties	94,664
Unproved properties	70,309
Total oil and gas properties	164,973
Total assets acquired		$165,450

Liabilities
Revenues and royalties payable		$1,442
Other current liabilities	323
Asset retirement obligations	2,054
Other liabilities	1,078
Total liabilities assumed		$4,897
Net Assets Acquired		$160,553

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.

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4. Property and Equipment, Net

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



	March 31, 2017			December 31, 2016
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$4,817,044			$4,687,416
Accumulated depreciation, depletion and amortization and impairments	(3,445,709		)	(3,392,749		)
Proved properties, net	1,371,335			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	221,039			211,067
Capitalized interest	32,231			29,894
Total unproved properties, not being amortized	253,270			240,961
Other property and equipment	23,240			23,127
Accumulated depreciation	(13,641		)	(12,995		)
Other property and equipment, net	9,599			10,132
Total property and equipment, net		$1,634,204			$1,545,760

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.

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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:



	Three Months Ended March 31,
	2017			2016
Impairment of proved oil and gas properties (in thousands)		$—		$274,413
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$39.60			$47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$44.98			$43.13
Percentage increase (decrease)	14		%	(9	%)

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:



	Three Months Ended March 31,
	2017			2016
	(In thousands)
Income (loss) before income taxes		$40,021			($311,274	)
Income tax (expense) benefit at the statutory rate	(14,007		)	108,946
State income tax (expense) benefit, net of U.S. federal income taxes	(710		)	1,619
Tax shortfalls from stock-based compensation expense	(2,592		)	—
Deferred tax assets valuation allowance	17,369			(110,679		)
Other	(60		)	(7		)
Income tax expense		$—			($121	)

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.

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

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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:



	March 31, 2017			December 31, 2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2018		$123,000			$87,000
7.50% Senior Notes due 2020	600,000			600,000
Unamortized premium for 7.50% Senior Notes	960			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(7,189		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(9,150		)	(9,454		)
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,362,046			$1,325,418

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.



Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	1.00%	2.00%	0.500%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.500%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	0.500%

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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:



	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
For the Three Months Ended March 31, 2017
Unvested restricted stock awards and units, beginning of period	1,111,710			$36.93
Granted	749,396			$27.07
Vested	(569,145	)		$39.48
Forfeited	(3,933	)		$29.42
Unvested restricted stock awards and units, end of period	1,288,028			$30.09

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

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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:



	Stock Appreciation Rights		Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)
For the Three Months Ended March 31, 2017
Outstanding, beginning of period	722,638			$23.69
Granted	342,440			$26.94
Exercised	(100,000	)		$17.28					$1.3
Forfeited	—		—
Outstanding, end of period	965,078			$25.51	3.4		$2.5
Exercisable, end of period	436,739			$23.62	1.8		$2.0

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:



	Grant Date Fair Value Assumptions
Expected term (in years)	4.24
Expected volatility	54.3	%
Risk-free interest rate	1.8	%
Dividend yield	—	%
Grant date fair value	$12.00

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.

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



	Performance Shares		Weighted Average Grant Date Fair Value
For the Three Months Ended March 31, 2017
Unvested performance shares, beginning of period	154,510			$58.44
Granted	46,787			$35.14
Vested ⁽¹⁾	(56,342	)		$68.15
Forfeited	—		—
Unvested performance shares, end of period	144,955			$47.14


(1)	The vested performance shares presented in the table above are the target performance shares that were granted in 2014. The Company’s final TSR ranking relative to the specified industry peer group resulted in the vesting of 164% of the target performance shares granted, or an additional 35,858 shares.

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:



	Grant Date Fair Value Assumptions
Number of simulations	500,000
Expected term (in years)	2.98
Expected volatility	59.2	%
Risk-free interest rate	1.5	%
Dividend yield	—	%
Grant date fair value	$35.14

Stock-Based Compensation Expense, Net

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



	Three Months Ended March 31,
	2017			2016
	(In thousands)
Restricted stock awards and units		$5,849			$11,594
Stock appreciation rights	(3,686		)	1,232
Performance shares	706			616
	2,869			13,442
Less: amounts capitalized to oil and gas properties	(855		)	(1,920		)
Total stock-based compensation expense, net		$2,014			$11,522

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.

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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:



Period	Type of Contract	Crude Oil Volumes (in Bbls/d)	Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q2 2017	Fixed Price Swaps	12,000		$50.13
Q3 2017	Fixed Price Swaps	6,000		$54.15
Q4 2017	Fixed Price Swaps	3,000		$55.01
FY 2018	Sold Call Options	2,488				$60.00
FY 2018	Net Sold Call Options	900				$75.00
FY 2019	Sold Call Options	2,975				$62.50
FY 2019	Net Sold Call Options	900				$77.50
FY 2020	Sold Call Options	3,675			$65.00
FY 2020	Net Sold Call Options	900			$80.00

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



Period	Type of Contract	Natural Gas Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q2 - Q4 2017	Fixed Price Swaps	20,000		$3.30
Q2 - Q4 2017	Sold Call Options	33,000				$3.00
FY 2018	Sold Call Options	33,000				$3.25
FY 2019	Sold Call Options	33,000				$3.25
FY 2020	Sold Call Options	33,000				$3.50

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.

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Derivative Assets and Liabilities

All derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. The combined derivative instrument fair value assets and liabilities recorded in the Company’s consolidated balance sheets as of March 31, 2017 and December 31, 2016 are summarized below:



	March 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Derivative assets
Derivative assets-current		$2,417			($1,381	)		$1,036
Derivative assets-non current	106			(106		)	—
Derivative liabilities
Derivative liabilities-current	(8,837		)	1,381			(7,456		)
Derivative liabilities-non current	(18,781		)	106			(18,675		)
Total		($25,095	)		$—			($25,095	)



	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Derivative assets
Derivative assets-current		$6,507			($5,270	)		$1,237
Derivative assets-non current	1,313			(1,313		)	—
Derivative liabilities
Derivative liabilities-current	(27,871		)	5,270			(22,601		)
Derivative liabilities-non current	(28,841		)	1,313			(27,528		)
Total		($48,892	)		$—			($48,892	)

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:



	Three Months Ended March 31,
	2017			2016
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		($18,480	)		($21,891	)
Natural gas	(6,836		)	11,338
Total (Gain) Loss on Derivatives, Net		($25,316	)		($10,553	)

The cash flow impacts of the Company’s derivative instruments are presented as separate line items within the net cash provided by operating activities in the Company’s consolidated statements of cash flows.

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10. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016:



	March 31, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative assets		$—		$1,036			$—
Derivative liabilities		$—		($21,970	)		$—



	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative assets		$—		$1,237			$—
Derivative liabilities		$—		($45,552	)		$—

The Company uses Level 2 inputs to measure the fair value of the Company’s commodity derivative instruments based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments including forward oil and gas price curves, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities.

The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments 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. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the three months ended March 31, 2017 and 2016.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate.

The fair value measurements of asset retirement obligations are measured on a nonrecurring basis when a well is drilled or acquired or when production equipment and facilities are installed or acquired using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

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Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt, which are classified as Level 1 under the fair value hierarchy. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of debt premiums and debt issuance costs, with the fair values measured using Level 1 inputs based on quoted secondary market trading prices.



	March 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$593,771		$616,500		$593,447		$624,750
6.25% Senior Notes due 2023	640,850		650,000		640,546		672,750
Other long-term debt due 2028	4,425		4,425		4,425		4,419

11. Condensed Consolidating Financial Information

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

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)



	March 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,724,856			$66,199			$—		($2,717,829	)		$73,226
Total property and equipment, net	41,196			1,593,134			3,800		(3,926		)	1,634,204
Investment in subsidiaries	(1,223,475		)	—			—		1,223,475			—
Other assets	6,855			155			—		—			7,010
Total Assets		$1,549,432			$1,659,488			$3,800		($1,498,280	)		$1,714,440

Liabilities and Shareholders’ Equity
Current liabilities		$90,083			$2,854,994			$3,800		($2,720,849	)		$228,028
Long-term liabilities	1,372,638			27,969			—		15,878			1,416,485
Total shareholders’ equity	86,711			(1,223,475		)	—		1,206,691			69,927
Total Liabilities and Shareholders’ Equity		$1,549,432			$1,659,488			$3,800		($1,498,280	)		$1,714,440



	December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,735,830			$63,513			$—		($2,726,355	)		$72,988
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)



	Three Months Ended March 31, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$82			$151,273		$—		$—			$151,355
Total costs and expenses	18,868			92,456		—		10			111,334
Income (loss) before income taxes	(18,786		)	58,817		—		(10		)	40,021
Income tax expense	—			—		—		—			—
Equity in income of subsidiaries	58,817			—		—		(58,817		)	—
Net income		$40,031			$58,817		$—		($58,827	)		$40,021



	Three Months Ended March 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$115			$81,147			$—		$—			$81,262
Total costs and expenses	29,912			362,248			—		376			392,536
Loss before income taxes	(29,797		)	(281,101		)	—		(376		)	(311,274		)
Income tax expense	—			—			—		(121		)	(121		)
Equity in loss of subsidiaries	(281,101		)	—			—		281,101			—
Net loss		($310,898	)		($281,101	)		$—		$280,604			($311,395	)

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Three Months Ended March 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities		($47,297	)		$123,705			$—		$—			$76,408
Net cash provided by (used in) investing activities	9,879			(114,212		)	—		(9,493		)	(113,826		)
Net cash provided by (used in) financing activities	35,615			(9,493		)	—		9,493			35,615
Net decrease in cash and cash equivalents	(1,803		)	—			—		—			(1,803		)
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$2,391			$—			$—		$—			$2,391



	Three Months Ended March 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities		($2,156	)		$56,024			$—			$—			$53,868
Net cash used in investing activities	(68,797		)	(122,849		)	(740		)	67,565			(124,821		)
Net cash provided by financing activities	30,193			66,825			740			(67,565		)	30,193
Net decrease in cash and cash equivalents	(40,760		)	—			—			—			(40,760		)
Cash and cash equivalents, beginning of period	42,918			—			—			—			42,918
Cash and cash equivalents, end of period		$2,158			$—			$—			$—			$2,158

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12. Supplemental Cash Flow Information

Supplemental cash flow disclosures and non-cash investing activities are presented below:



	Three Months Ended March 31,
	2017		2016
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$19,480		$17,553
Cash paid for income taxes	—		—

Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		$28,139		($27,989	)
Stock-based compensation expense capitalized to oil and gas properties	855		1,920
Asset retirement obligations capitalized to oil and gas properties	447		518
Other non-cash investing activities	343		1,485

13. Subsequent Events

Hedging

In April 2017, the Company entered into the following crude oil derivative positions:



Period	Type of Contract	Crude Oil Volumes (in Bbls/d)	Weighted Average Sub-Floor Price ($/Bbl)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q3 2017	Fixed Price Swaps	6,000				$53.28
Q4 2017	Fixed Price Swaps	6,000				$53.28
FY 2018	Three-Way Collars	6,000		$40.00		$50.00		$65.00

In order to obtain a higher weighted average ceiling price on the three-way collars, the Company incurred premiums of approximately $2.8 million, the payments for which are deferred until the applicable contracts settle on a monthly basis.

Sanchez Acquisition

In April 2017, the Company paid $9.8 million for the remaining outstanding leases that were not conveyed to the Company at the initial closing on December 14, 2016 or at the subsequent closing on January 9, 2017. The Company currently expects its allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date will be finalized during the fourth quarter of 2017.

Ninth Amendment to Credit Agreement

On May 4, 2017, the Company entered into a ninth amendment to its credit agreement governing the revolving credit facility to, among other things (i) extend the maturity date of the revolving credit facility to 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, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, (iii) increase the borrowing base from $600.0 million to $900.0 million, of which $800.0 million has been committed by lenders, until the next redetermination thereof, (iv) replace the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio covenant that requires such ratio not to exceed 4.00 to 1.00, (v) remove the covenant requiring a minimum EBITDA to Interest Expense ratio, (vi) reduce the commitment fee from 0.50% to 0.375% when utilization of lender commitments is less than 50% of the borrowing base amount, (vii) remove the restriction from borrowing under the credit facility if the Company has or, after giving effect to the borrowing, will have a Consolidated Cash Balance in excess of $50.0 million, (viii) remove the mandatory repayment of borrowings to the extent the Consolidated Cash Balance exceeds $50.0 million if either (a) the Company’s ratio of Total Debt to EBITDA exceeds 3.50 to 1.00 or (b) the availability under the credit facility is equal to or less than 20% of the then effective borrowing base, (ix) permit the issuance of unlimited Senior Unsecured Debt, subject to certain conditions, including pro forma compliance with the Company’s financial covenants, and (x) increase certain covenant baskets and thresholds. The capitalized terms which are not defined in this note to the consolidated financial statements have the meaning given to such terms in the credit agreement.

-23-

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

The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our 2016 Annual Report. The following discussion and analysis contains statements, including, but not limited to, statements related to our plans, strategies, objectives, and expectations. Please see “Forward-Looking Statements” for further details about these statements.

General Overview

Operational Results. Total production for the three months ended March 31, 2017 increased 10% from the three months ended March 31, 2016 to 46,367 Boe/d primarily due to increased production from new wells in the Eagle Ford and Delaware Basin, production from the Sanchez Acquisition, and increased production in the Marcellus due to a lower level of voluntary curtailments compared to the first quarter of 2016, partially offset by normal production declines. Crude oil production for the three months ended March 31, 2017 was 28,844 Bbls/d, an increase of 12% from the three months ended March 31, 2016, primarily driven by increased production from new wells in the Eagle Ford and Delaware Basin and the Sanchez Acquisition, partially offset by normal production declines. For further discussion of production, see “—Results of Operations” below.

See the table below for details of our operated drilling and completion activity:



	Three Months Ended March 31, 2017				March 31, 2017
	Drilled		Completed		Drilled But Uncompleted		Producing		Rig count
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Rig count
Eagle Ford	24	20.1	29	28.7	29	23.9	463	399.4	3
Delaware Basin	—	—	—	—	2	2.0	6	5.6	—
Niobrara	—	—	—	—	—	—	130	57.9	—
Marcellus	—	—	—	—	11	4.3	81	26.0	—
Utica and Other	—	—	—	—	—	—	4	3.1	—
Total	24	20.1	29	28.7	42	30.2	684	492.0	3

Drilling and completion expenditures for the first quarter of 2017 were $128.2 million, of which 87% were in the Eagle Ford where, as of March 31, 2017, we were operating three rigs and two frac crews. Our current 2017 capital expenditure plan includes $530.0 million to $550.0 million for drilling and completion and $45.0 million for leasehold and seismic, which was recently increased from $20.0 million. The focus for our remaining 2017 drilling and completion capital expenditures is currently on the continued exploration and development of oil-focused plays, such as the Eagle Ford and Delaware Basin, where approximately 90% of our currently remaining 2017 drilling and completion capital expenditure plan is allocated. See “—Liquidity and Capital Resources—2017 Capital Expenditure Plan and Funding Strategy” for additional details.

Senior Secured Revolving Credit Facility. On May 4, 2017, we entered into entered into a ninth amendment to our credit agreement governing the revolving credit facility which, among other things, (i) extended the maturity date of the revolving credit facility to 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, (ii) increased the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, and (iii) increased the borrowing base from $600.0 million to $900.0 million, of which $800.0 million has been committed by lenders, until the next redetermination thereof. See “Note 13. Subsequent Events” for further details.

Financial Results. We recorded net income for the three months ended March 31, 2017 of $40.0 million, or $0.61 per diluted share, as compared to a net loss for the three months ended March 31, 2016 of $311.4 million, or $5.34 per diluted share. The net income for the first quarter of 2017 as compared to the net loss for the first quarter of 2016 was driven primarily by an increase in revenues as a result of higher realized crude oil pricing and production as well as no impairment of proved oil and gas properties during the first quarter of 2017 compared to an impairment of proved oil and gas properties of $274.4 million recognized during the first quarter of 2016. See “—Results of Operations” below for further details.

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Results of Operations

Three Months Ended March 31, 2017, Compared to the Three Months Ended March 31, 2016

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,				2017 Period Compared to 2016 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	2,596		2,348		248			11	%
NGLs (MBbls)	406		414		(8		)	(2	%)
Natural gas (MMcf)	7,028		6,373		655			10	%
Total barrels of oil equivalent (MBoe)	4,173		3,824		349			9	%

Daily production volumes by product -
Crude oil (Bbls/d)	28,844		25,806		3,038			12	%
NGLs (Bbls/d)	4,508		4,547		(39		)	(1	%)
Natural gas (Mcf/d)	78,088		70,033		8,055			12	%
Total barrels of oil equivalent (Boe/d)	46,367		42,025		4,342			10	%

Daily production volumes by region (Boe/d) -
Eagle Ford	32,578		30,971		1,607			5	%
Delaware Basin	2,418		140		2,278			1,627	%
Niobrara	2,765		3,186		(421		)	(13	%)
Marcellus	7,928		6,026		1,902			32	%
Utica and other	678		1,702		(1,024		)	(60	%)
Total barrels of oil equivalent (Boe/d)	46,367		42,025		4,342			10	%

Average realized prices -
Crude oil ($ per Bbl)		$49.34		$28.96		$20.38		70	%
NGLs ($ per Bbl)	18.29		8.31		9.98			120	%
Natural gas ($ per Mcf)	2.25		1.54		0.71			46	%
Total average realized price ($ per Boe)		$36.27		$21.25		$15.02		71	%

Revenues (In thousands) -
Crude oil		$128,092		$67,996		$60,096		88	%
NGLs	7,425		3,440		3,985			116	%
Natural gas	15,838		9,826		6,012			61	%
Total revenues		$151,355		$81,262		$70,093		86	%

Production volumes for the three months ended March 31, 2017 were 46,367 Boe/d, an increase of 10% from 42,025 Boe/d for the same period in 2016. The increase is primarily due to increased production from new wells in the Eagle Ford and Delaware Basin, production from the Sanchez Acquisition, and increased production in the Marcellus due to a lower level of voluntary curtailments compared to the first quarter of 2016, partially offset by normal production declines. Revenues for the three months ended March 31, 2017 increased 86% to $151.4 million compared to $81.3 million for the same period in 2016 primarily due to higher average realized crude oil prices as well as the increased production described above.

Lease operating expenses for the three months ended March 31, 2017 increased to $29.8 million ($7.15 per Boe) from $23.7 million ($6.19 per Boe) for the same period in 2016. The increase in lease operating expenses is primarily due to increased production from new wells in the Eagle Ford and Delaware Basin and increased workover costs on wells recently acquired in the Sanchez Acquisition. The increase in lease operating expense per Boe is primarily due to the workover costs described above partially offset by an increased proportion of production attributable to Marcellus production which carries lower per Boe operating costs.

Production taxes increased to $6.2 million (or 4.1% of revenues) for the three months ended March 31, 2017 from $3.4 million (or 4.2% of revenues) for the same period in 2016 primarily as a result of the increase in crude oil, NGL, and natural gas

-25-

revenues. The decrease in production taxes as a percentage of revenues for the three months ended March 31, 2017 as compared to the same period in 2016 is due primarily to an increased proportion of total revenues attributable to Marcellus production, which is not subject to production taxes.

Ad valorem taxes increased to $3.0 million for the three months ended March 31, 2017 from $2.1 million for the same period in 2016. The increase in ad valorem taxes is due to an increase in our annual estimate of ad valorem taxes for 2017 due to higher expected property tax valuations as a result of the increase in crude oil prices, as well as new wells drilled in the Eagle Ford in 2016.

Depreciation, depletion and amortization (“DD&A”) expense for the first quarter of 2017 decreased $5.2 million to $54.4 million ($13.03 per Boe) from the DD&A expense for the first quarter of 2016 of $59.6 million ($15.58 per Boe). The decrease in DD&A expense is attributable to the decrease in the DD&A rate per Boe, partially offset by increased production. The DD&A rate per Boe decreased primarily due to impairments of our proved oil and gas properties recorded during the second and third quarter of 2016, reductions in estimated future development costs primarily as a result of reduced service costs that occurred in the second and fourth quarters of 2016, and the addition of crude oil reserves in the fourth quarter of 2016. The components of our DD&A expense were as follows:



	Three Months Ended March 31,
	2017		2016
	(In thousands)
DD&A of proved oil and gas properties		$52,960		$58,203
Depreciation of other property and equipment	646		673
Amortization of other assets	351		373
Accretion of asset retirement obligations	425		328
Total DD&A		$54,382		$59,577

We 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, we 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:



	Three Months Ended March 31,
	2017			2016
Impairment of proved oil and gas properties (in thousands)		$—		$274,413
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$39.60			$47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$44.98			$43.14
Percentage increase (decrease)	14		%	(9	%)

General and administrative expense, net increased to $21.7 million for the three months ended March 31, 2017 from $21.3 million for the corresponding period in 2016. The increase was primarily due to higher annual bonuses awarded in the first quarter of 2017 compared to the first quarter of 2016 partially offset by a decrease in stock-based compensation expense, net as a result of a decrease in the fair value of stock appreciation rights for the three months ended March 31, 2017 compared to an increase in fair value for the three months ended March 31, 2016.

-26-

We recorded a gain on derivatives, net of $25.3 million and $10.6 million for the three months ended March 31, 2017 and 2016, respectively. The components of our gain on derivatives, net were as follows:



	Three Months Ended March 31,
	2017		2016
	(In thousands)
Crude oil derivative positions:
Gain due to downward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period		$18,480		$14,836
Gain due to new derivative positions executed during the period (net of deferred premiums)	—		6,957
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period	6,836		—
Loss due to new derivative positions executed during the period	—		(11,240		)
Gain on derivatives, net		$25,316		$10,553

Interest expense, net for the three months ended March 31, 2017 was $20.6 million as compared to $18.7 million for the same period in 2016. The increase was due primarily to the decrease in capitalized interest as a result of lower average balances of unproved properties in the first quarter of 2017 as compared to the first quarter of 2016. The components of our interest expense, net were as follows:



	Three Months Ended March 31,
	2017			2016
	(In thousands)
Interest expense on Senior Notes		$21,455			$21,455
Interest expense on revolving credit facility	1,426			677
Amortization of debt issuance costs, premiums, and discounts	1,186			1,976
Other interest expense	285			254
Capitalized interest	(3,781		)	(5,649		)
Interest expense, net		$20,571			$18,713

The effective income tax rate for the first quarter of 2017 and 2016 was 0.0%. This is as a result of a full valuation allowance against our net deferred tax assets driven primarily by the impairments of proved oil and gas properties we recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016.

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Liquidity and Capital Resources

2017 Capital Expenditure Plan and Funding Strategy. Our 2017 drilling and completion capital expenditure plan remains unchanged at $530.0 million to $550.0 million, while our 2017 leasehold and seismic capital expenditure plan is increased from $20.0 million to $45.0 million. We currently intend to finance our 2017 capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including the availability of drilling rigs, the cost of completion services, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. Below is a summary of our capital expenditures through March 31, 2017:



	Three Months Ended
	March 31, 2017
	(In thousands)
Drilling and completion
Eagle Ford		$111,472
Delaware Basin	10,360
All other regions	6,412
Total drilling and completion	128,244
Leasehold and seismic ⁽¹⁾	14,516
Total ⁽²⁾		$142,760


(1)	Leasehold and seismic capital expenditures exclude amounts paid for the remaining outstanding leases that were not conveyed to the Company at the initial closing of the Sanchez Acquisition on December 14, 2016. See “Note 3. Acquisition” for additional details of the Sanchez Acquisition.


(2)	Our capital expenditure plan and the capital expenditures included above exclude capitalized general and administrative expense, capitalized interest and capitalized asset retirement obligations.

Sources and Uses of Cash. Our primary use of cash is related to our drilling and completion capital expenditure plan and, to a lesser extent, our leasehold and seismic capital expenditure plan. For the three months ended March 31, 2017, we funded our capital expenditures with cash provided by operations and borrowings under our revolving credit facility. Potential sources of future liquidity include the following:


•	Cash provided by operations. Cash flows from operations are highly dependent on crude oil prices. As such, we hedge a portion of our forecasted production to reduce our exposure to commodity price volatility in order to achieve a more predictable level of cash flows.

•

Borrowings under our revolving credit facility. As of April 28, 2017, our revolving credit facility had a borrowing base of $600.0 million, with $171.0 million of borrowings outstanding and $0.4 million in letters of credit issued, which reduce the amounts available under our revolving credit facility. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility. See “—Financing Arrangements—Senior Secured Revolving Credit Facility” for details of the recent ninth amendment to the credit agreement governing our revolving credit facility.


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

•

Asset sales. In order to fund our capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us. We continue to explore sales of non-core properties. We may also consider the sale of properties in areas we have viewed as core, such as the Delaware Basin, particularly if we believe that sales prices for such assets would allow us to deploy capital more effectively in other basins or other parts of the same basin. There can be no assurance, however, that any sales will occur on terms we find to be acceptable, or at all.


•	Joint ventures. Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both.

Overview of Cash Flow Activities. Net cash provided by operating activities was $76.4 million and $53.9 million for the three months ended March 31, 2017 and 2016, respectively. The change was driven primarily by an increase in revenues as a result of higher realized crude oil pricing and production and a decrease in working capital requirements, partially offset by a decrease in the net cash received from derivative settlements and an increase in cash general and administrative expense.

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Net cash used in investing activities was $113.8 million and $124.8 million for the three months ended March 31, 2017 and 2016, respectively. The change was due primarily to increased proceeds from sales of oil and gas properties, partially offset by cash paid for the Sanchez Acquisition in the first quarter of 2017 as compared to the same period in 2016. The sales of oil and gas properties in the first quarter of 2017 were primarily related to the sale of 368 net acres in the Delaware Basin for net proceeds of $15.3 million.

Net cash provided by financing activities was $35.6 million and $30.2 million for the three months ended March 31, 2017 and 2016, respectively. The change was due to increased borrowings net of repayments under our revolving credit facility in the first quarter of 2017 as compared to the same period in 2016.

Liquidity/Cash Flow Outlook. Economic downturns may adversely affect our ability to access capital markets in the future. Cash flows from operations are primarily driven by crude oil production, commodity prices and settlements of our commodity derivatives. We currently believe that cash flows from operations and borrowings under our revolving credit facility provide adequate financial flexibility and will be sufficient to fund our immediate cash flow requirements.

•

Revolving credit facility. The borrowing base under our revolving credit facility is affected by assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices. Our borrowing base may decrease if our administrative agent reduces the crude oil and natural gas prices from those used to determine our existing borrowing base. See “—Sources and Uses of Cash—Borrowings under our revolving credit facility” and “—Financing Arrangements—Senior Secured Revolving Credit Facility” for further details of our revolving credit facility.


•	Hedging. To manage our exposure to commodity price risk and to provide a level of certainty in the cash flows to support our drilling and completion capital expenditure plan, we hedge a portion of our forecasted production.

As of April 28, 2017, we had the following crude oil derivative positions:



Period	Type of Contract	Crude Oil Volumes (in Bbls/d	Weighted Average Sub-Floor Price ($/Bbl)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q2 2017	Fixed Price Swaps	12,000				$50.13
Q3 2017	Fixed Price Swaps	12,000				$53.71
Q4 2017	Fixed Price Swaps	9,000				$53.86
FY 2018	Three-Way Collars	6,000		$40.00		$50.00		$65.00
FY 2018	Sold Call Options	2,488						$60.00
FY 2018	Net Sold Call Options	900						$75.00
FY 2019	Sold Call Options	2,975						$62.50
FY 2019	Net Sold Call Options	900						$77.50
FY 2020	Sold Call Options	3,675						$65.00
FY 2020	Net Sold Call Options	900					$80.00

As of April 28, 2017, we had the following natural gas derivative positions:



Period	Type of Contract	Natural Gas Volumes (in MMBtu/d	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q2 - Q4 2017	Fixed Price Swaps	20,000		$3.30
Q2 - Q4 2017	Sold Call Options	33,000				$3.00
FY 2018	Sold Call Options	33,000				$3.25
FY 2019	Sold Call Options	33,000				$3.25
FY 2020	Sold Call Options	33,000				$3.50

If cash flows from operations and borrowings under our revolving credit facility and the other sources of cash described under “—Sources and Uses of Cash” are insufficient to fund the remainder of our 2017 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our remaining 2017 capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Based on existing market conditions and our expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from asset sales, securities offerings or borrowings to

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reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings.

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of March 31, 2017 (in thousands):



	2017		2018		2019		2020		2021		2022 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$123,000		$—		$600,000		$—		$654,425		$1,377,425
Cash interest on senior notes and other long-term debt ⁽²⁾	63,319		85,819		85,819		85,819		40,819		62,180		423,775
Cash interest and commitment fees on revolving credit facility ⁽³⁾	4,561		3,035		—		—		—		—		7,596
Capital leases	1,392		1,823		1,800		1,050		—		—		6,065
Operating leases	3,450		4,549		4,497		4,476		4,450		1,854		23,276
Drilling rig contracts ⁽⁴⁾	17,633		3,957		—		—		—		—		21,590
Delivery commitments ⁽⁵⁾	6,591		8,611		7,298		4,826		3,680		291		31,297
Asset retirement obligations and other ⁽⁶⁾	1,933		1,662		235		105		276		20,842		25,053
Total Contractual Obligations		$98,879		$232,456		$99,649		$696,276		$49,225		$739,592		$1,916,077


(1)	Long-term debt consists of the principal amounts of the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, other long-term debt due 2028, and borrowings outstanding under our revolving credit facility which matures in 2018.


(2)	Cash interest on senior notes and other long-term debt includes cash payments for interest on the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023 and other long-term debt due 2028.

(3)

Cash interest on our revolving credit facility was calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of March 31, 2017 of 2.95%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of March 31, 2017, at the commitment fee rate of 0.50%. See “Note 13. Subsequent Events” for details of the changes to our revolving credit facility subsequent to March 31, 2017.


(4)	Drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will generally be billed for their working interest share of such costs.


(5)	Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation throughput commitments. We may incur volume deficiency fees from time to time if we elect to voluntarily curtail production due to market or operational considerations.


(6)	Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of March 31, 2017. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.

Financing Arrangements

Senior Secured Revolving Credit Facility

As of March 31, 2017, we had a senior secured revolving credit facility with a syndicate of banks that had a borrowing base of $600.0 million, with $123.0 million of borrowings outstanding at a weighted average interest rate of 2.95% and $0.4 million in letters of credit outstanding. As of March 31, 2017, the credit agreement governing our senior secured 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 our 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.

On May 4, 2017, we entered into a ninth amendment to our credit agreement governing the revolving credit facility to, among other things (i) extend the maturity date of the revolving credit facility to 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, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, (iii) increase the borrowing base from $600.0 million to $900.0 million, of which $800.0 million has been committed by lenders, until the next redetermination thereof, (iv) replace the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio covenant that requires such ratio not to exceed 4.00 to 1.00, (v) remove the covenant requiring a minimum EBITDA to Interest Expense ratio, (vi) reduce the commitment fee from 0.50% to 0.375% when utilization of lender commitments is less than 50% of the borrowing base amount, (vii) remove the restriction from borrowing under the credit facility if we have or, after giving effect to the borrowing, will have a Consolidated Cash Balance in excess of $50.0 million, (viii) remove the mandatory repayment of borrowings to the extent the Consolidated Cash Balance exceeds $50.0 million if either (a) our ratio of Total Debt to EBITDA exceeds 3.50 to 1.00 or (b) the availability under the credit facility is equal to or less than 20% of the then effective borrowing base, (ix) permit the issuance of unlimited Senior Unsecured Debt, subject to certain conditions, including pro forma compliance with our financial covenants, and (x) increase certain covenant

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baskets and thresholds. The capitalized terms which are not defined in this section of our quarterly report have the meaning given to such terms in the credit agreement.

See “Note 6. Long-Term Debt” for additional details of the senior secured revolving credit facility including rates of interest on outstanding borrowings, commitment fees on the unused portion of lender commitments, and the financial covenants we are subject to under the terms of the credit agreement.

7.50% Senior Notes due 2020

We have the right to redeem all or a portion of the principal amount of the 7.50% Senior Notes at redemption prices of 103.75% until September 14, 2017, 101.875% beginning September 15, 2017 until September 14, 2018 and 100% beginning September 15, 2018 and thereafter, in each case plus accrued and unpaid interest. In connection with any redemption or repurchase of notes, we could enter into other transactions, which include refinancing of the 7.50% Senior Notes.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, income taxes and commitments and contingencies. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2016 Annual Report. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, 2017 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of March 31, 2017 and, accordingly, does not consider drilling and completion activity, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to March 31, 2017 that may require revisions to estimates of proved reserves.



	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
March 31, 2017 Actual	$44.98	$2.05	$423

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$49.73	$2.34	$816	$393
Crude Oil and Natural Gas -10%	$40.25	$1.76	$45	($378)

Crude Oil Price Sensitivity
Crude Oil +10%	$49.73	$2.05	$774	$351
Crude Oil -10%	$40.25	$2.05	$78	($345)

Natural Gas Price Sensitivity
Natural Gas +10%	$44.98	$2.34	$464	$41
Natural Gas -10%	$44.98	$1.76	$385	($38)

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. We assess the realizability of our 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. We consider all available evidence (both positive

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and negative) when determining whether a valuation allowance is required. In making this assessment, we evaluated possible sources of taxable income that may be available to realize the benefit of 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 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 our potential for future growth. We also have estimated U.S. federal net operating loss carryforwards of $759.1 million as of March 31, 2017. Beginning in the third quarter of 2015, we concluded in each subsequent quarterly evaluation that it is more likely than not the deferred tax assets will not be realized and based on evaluation of evidence available as of March 31, 2017, our previous conclusion remains unchanged. 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, we 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.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our 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 us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we may have additional valuation allowance increases with no significant deferred income tax expense or benefit.

We classify interest and penalties associated with income taxes as interest expense. We follow the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized.

Recently Adopted and Recently Issued Accounting Pronouncements

See “Note 2. Summary of Significant Accounting Policies” for discussion of our recent adoption of ASU 2016-09 as well as the recently issued accounting pronouncements from the Financial Accounting Standards Board.

Volatility of Crude Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of crude oil, which are affected by changes in market supply and demand, overall economic activity, global political environment, weather, inventory storage levels and other factors, as well as the level and prices at which we have hedged our future production.

We review the carrying value of our oil and gas properties on a quarterly basis under the full cost method of accounting. See “Note 4. Property and Equipment, Net” for additional details.

We use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support our drilling and completion capital expenditure program. We do not enter into derivative instruments for speculative or trading purposes. As of March 31, 2017, our commodity derivative instruments consisted of fixed price swaps and purchased and sold call options. See “Note 9. Derivative Instruments” for further details of our crude oil and natural gas derivative positions as of March 31, 2017 and “Note 13. Subsequent Events—Hedging” for further details of the crude oil derivative positions entered into subsequent to March 31, 2017.

Forward-Looking Statements

This quarterly report contains statements concerning our intentions, expectations, projections, assessments of risks, estimations, beliefs, plans or predictions for the future, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among others, statements regarding:


•	our growth strategies;

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•	our ability to explore for and develop oil and gas resources successfully and economically;


•	our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;


•	our estimates regarding timing and levels of production;


•	changes in working capital requirements, reserves, and acreage;


•	commodity price risk management activities and the impact on our average realized prices;


•	anticipated trends in our business;


•	availability of pipeline connections and water disposal on economic terms;


•	effects of competition on us;


•	our future results of operations;


•	profitability of drilling locations;


•	our liquidity and our ability to finance our exploration and development activities, including accessibility of borrowings under our revolving credit facility, our borrowing base, modification to financial covenants, and the result of any borrowing base redetermination;


•	our planned expenditures, prospects and capital expenditure plan;


•	future market conditions in the oil and gas industry;


•	our ability to make, integrate and develop acquisitions and realize any expected benefits or effects of completed acquisitions;


•	possible future sales or other transactions;


•	the benefits, effects, availability of and results of new and existing joint ventures and sales transactions;


•	our ability to maintain a sound financial position;


•	receipt of receivables and proceeds from sales;


•	our ability to complete planned transactions on desirable terms;


•	the impact of governmental regulation, taxes, market changes and world events; and

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “scheduled,” “should,” or other similar words. Such statements rely on assumptions and involve risks and uncertainties, many of which are beyond our control, including, but not limited to, those relating to a worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, impairments of proved oil and gas properties, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base determinations (including determinations by lenders) and availability under our revolving credit facility, evaluations of us by lenders under our revolving credit facility, other actions by lenders, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, acquisition risks, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture parties, results of exploration activities, the availability, market conditions and completion of land acquisitions and dispositions, costs of oilfield services, completion and connection of wells, and other factors detailed in this quarterly report.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

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Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under Part I, “Item 1A. Risk Factors” and other sections of our 2016 Annual Report and in our other filings with the SEC, including this quarterly report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our 2016 Annual Report. Except as disclosed in this report, there have been no material changes from the disclosure made in our 2016 Annual Report regarding our exposure to certain market risks.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of March 31, 2017 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended March 31, 2017 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

Item 1A. Risk Factors

There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

The following exhibits are required by Item 601 of Regulation S-K and are filed as part of this report:



Exhibit Number		Exhibit Description
*10.1		Ninth Amendment to Credit Agreement, dated as of May 4, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto.
*31.1	–	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	–	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	–	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	–	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101	–	Interactive Data Files

* Filed herewith.

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Signatures

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



		Carrizo Oil & Gas, Inc. (Registrant)

Date:	May 9, 2017	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	May 9, 2017	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

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