Edgar Filing: CARRIZO OIL & GAS INC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________

FORM 10-Q

_________________________________________________



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

For the quarterly period ended March 31, 2018



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 þ 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 þ 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	þ	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 þ

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of April 30, 2018 was 82,067,457.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017	2
	Consolidated Statements of Income for the three months ended March 31, 2018 and 2017	3
	Consolidated Statement of Shareholders’ Equity for the three months ended March 31, 2018	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
Part II. Other Information
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
Signatures		43

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, 2018			December 31, 2017
Assets
Current assets
Cash and cash equivalents		$4,885			$9,540
Accounts receivable, net	98,788			107,441
Other current assets	15,528			5,897
Total current assets	119,201			122,878
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,772,927			1,965,347
Unproved properties, not being amortized	617,754			660,287
Other property and equipment, net	10,304			10,176
Total property and equipment, net	2,400,985			2,635,810
Other assets	18,271			19,616
Total Assets		$2,538,457			$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$106,328			$74,558
Revenues and royalties payable	47,231			52,154
Accrued capital expenditures	93,531			119,452
Accrued interest	23,737			28,362
Derivative liabilities	115,259			57,121
Other current liabilities	45,495			41,175
Total current liabilities	431,581			372,822
Long-term debt	1,442,898			1,629,209
Asset retirement obligations	15,518			23,497
Derivative liabilities	70,852			112,332
Deferred income taxes	3,828			3,635
Other liabilities	10,381			51,650
Total liabilities	1,975,058			2,193,145
Commitments and contingencies
Preferred stock
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of March 31, 2018 and 250,000 issued and outstanding as of December 31, 2017	172,118			214,262
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 82,065,561 issued and outstanding as of March 31, 2018 and 81,454,621 issued and outstanding as of December 31, 2017	821			815
Additional paid-in capital	1,918,942			1,926,056
Accumulated deficit	(1,528,482		)	(1,555,974		)
Total shareholders’ equity	391,281			370,897
Total Liabilities and Shareholders’ Equity		$2,538,457			$2,778,304

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

(Unaudited)



	Three Months Ended March 31,
	2018			2017
Revenues
Crude oil		$194,919			$128,092
Natural gas liquids	16,902			7,425
Natural gas	13,459			15,838
Total revenues	225,280			151,355

Costs and Expenses
Lease operating	39,273			29,845
Production taxes	10,575			6,208
Ad valorem taxes	1,973			2,967
Depreciation, depletion and amortization	64,467			54,382
General and administrative, net	27,292			21,703
(Gain) loss on derivatives, net	29,596			(25,316		)
Interest expense, net	15,517			20,571
Loss on extinguishment of debt	8,676			—
Other expense, net	100			974
Total costs and expenses	197,469			111,334

Income Before Income Taxes	27,811			40,021
Income tax expense	(319		)	—
Net Income		$27,492			$40,021
Dividends on preferred stock	(4,863		)	—
Accretion on preferred stock	(753		)	—
Loss on redemption of preferred stock	(7,133		)	—
Net Income Attributable to Common Shareholders		$14,743			$40,021

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.18			$0.61
Diluted		$0.18			$0.61

Weighted Average Common Shares Outstanding
Basic	81,542			65,188
Diluted	82,578			65,778

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, 2017	81,454,621		$815		$1,926,056			($1,555,974	)		$370,897
Stock-based compensation expense	—	—		5,647			—			5,647
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	610,940	6		(12		)	—			(6		)
Dividends on preferred stock	—	—		(4,863		)	—			(4,863		)
Accretion on preferred stock	—	—		(753		)	—			(753		)
Loss on redemption of preferred stock	—	—		(7,133		)	—			(7,133		)
Net income	—	—		—			27,492			27,492
Balance as of March 31, 2018	82,065,561		$821		$1,918,942			($1,528,482	)		$391,281

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,
	2018			2017
Cash Flows From Operating Activities
Net income		$27,492			$40,021
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	64,467			54,382
(Gain) loss on derivatives, net	29,596			(25,316		)
Cash (paid) received for derivative settlements, net	(14,365		)	1,519
Loss on extinguishment of debt	8,676			—
Stock-based compensation expense, net	3,518			2,014
Deferred income taxes	193			—
Non-cash interest expense, net	662			1,091
Other, net	(2,689		)	1,620
Changes in components of working capital and other assets and liabilities-
Accounts receivable	10,738			(2,749		)
Accounts payable	15,526			6,661
Accrued liabilities	(4,317		)	(2,154		)
Other assets and liabilities, net	(773		)	(681		)
Net cash provided by operating activities	138,724			76,408
Cash Flows From Investing Activities
Capital expenditures	(234,685		)	(123,749		)
Acquisitions of oil and gas properties	—			(7,032		)
Proceeds from divestitures of oil and gas properties, net	342,359			17,372
Other, net	(87		)	(417		)
Net cash provided by (used in) investing activities	107,587			(113,826		)
Cash Flows From Financing Activities
Redemption of senior notes	(326,010		)	—
Redemption of preferred stock	(50,030		)	—
Borrowings under credit agreement	694,260			280,504
Repayments of borrowings under credit agreement	(563,860		)	(244,504		)
Payments of debt issuance costs	(150		)	(50		)
Payment of dividends on preferred stock	(4,863		)	—
Other, net	(313		)	(335		)
Net cash provided by (used in) financing activities	(250,966		)	35,615
Net Decrease in Cash and Cash Equivalents	(4,655		)	(1,803		)
Cash and Cash Equivalents, Beginning of Period	9,540			4,194
Cash and Cash Equivalents, End of Period		$4,885			$2,391

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

Consolidated Financial Statements

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”) and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. These financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes in the 2017 Annual Report. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

2. Summary of Significant Accounting Policies

Revenue Recognition

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

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



	Three Months Ended March 31, 2018
	Under ASC 606		Under ASC 605		Increase		% Increase
	(In thousands)
Revenues
Crude oil		$194,919		$194,794		$125	0.1	%
Natural gas liquids	16,902		16,096		806		5.0	%
Natural gas	13,459		12,887		572		4.4	%
Total revenues	225,280		223,777		1,503		0.7	%

Costs and Expenses
Lease operating	39,273		37,770		1,503		4.0	%

Income Before Income Taxes		$27,811		$27,811		$—	—	%

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

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

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

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

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

Recently Adopted Accounting Pronouncements

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

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

Recently Issued Accounting Pronouncements

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

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

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

Net Income Attributable to Common Shareholders Per Common Share

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



	Three Months Ended March 31,
	2018		2017
	(In thousands, except per share amounts)
Net Income Attributable to Common Shareholders		$14,743		$40,021
Basic weighted average common shares outstanding	81,542		65,188
Effect of dilutive instruments	1,036		590
Diluted weighted average common shares outstanding	82,578		65,778
Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.18		$0.61
Diluted		$0.18		$0.61

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



	Three Months Ended March 31,
	2018	2017
	(In thousands)
Dilutive	1,036	590
Anti-dilutive	98	5

3. Acquisitions and Divestitures of Oil and Gas Properties

Acquisitions

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

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

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

Divestitures

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

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

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

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

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

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

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

4. Property and Equipment, Net

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



	March 31, 2018			December 31, 2017
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,486,064			$5,615,153
Accumulated depreciation, depletion and amortization and impairments	(3,713,137		)	(3,649,806		)
Proved properties, net	1,772,927			1,965,347
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	564,984			612,589
Capitalized interest	52,770			47,698
Total unproved properties, not being amortized	617,754			660,287
Other property and equipment	26,332			25,625
Accumulated depreciation	(16,028		)	(15,449		)
Other property and equipment, net	10,304			10,176
Total property and equipment, net		$2,400,985			$2,635,810

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

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

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Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling $10.4 million and $3.8 million for the three months ended March 31, 2018 and 2017.

5. Income Taxes

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

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



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Income before income taxes		$27,811			$40,021
Income tax expense at the statutory rate	(5,840		)	(14,007		)
State income tax expense, net of U.S. federal income taxes	(319		)	(710		)
Tax shortfalls from stock-based compensation expense	(2,526		)	(2,592		)
Decrease in deferred tax assets valuation allowance	8,401			17,369
Other	(35		)	(60		)
Income tax expense		($319	)		$—

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

Tax Cuts and Jobs Act

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

Deferred Tax Assets Valuation Allowance

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

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

For the three months ended March 31, 2018, the Company reduced the valuation allowance by $8.4 million due to a partial release as a result of current period activity. After the impact of the partial release, the valuation allowance as of March 31, 2018 was $324.6 million. For the three months ended March 31, 2017, as a result of adopting Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero. This increase in the valuation allowance was more than offset by a partial release of $17.4 million as a result of activity during the first quarter of 2017.

6. Long-Term Debt

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



	March 31, 2018			December 31, 2017
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$421,700			$291,300
7.50% Senior Notes due 2020	130,000			450,000
Unamortized premium for 7.50% Senior Notes	153			579
Unamortized debt issuance costs for 7.50% Senior Notes	(1,206		)	(4,492		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(7,884		)	(8,208		)
8.25% Senior Notes due 2025	250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(4,290		)	(4,395		)
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,442,898			$1,629,209

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of March 31, 2018, had a borrowing base of $830.0 million, with an elected commitment amount of $800.0 million, and $421.7 million of borrowings outstanding at a weighted average interest rate of 4.24%. As of March 31, 2018, the Company had no letters of credit outstanding. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”) have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

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

The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination.

Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set

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forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of income.



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%	0.375%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
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%

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

The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions and divestitures of oil and gas properties, mergers, transactions with affiliates, hedging transactions and other matters.

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

Redemptions of 7.50% Senior Notes

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

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

7. Commitments and Contingencies

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

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

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8. Preferred Stock and Warrants

On August 10, 2017, the Company closed on the issuance and sale in a private placement of (i) $250.0 million initial liquidation preference (250,000 shares) of 8.875% redeemable preferred stock, par value $0.01 per share (the “Preferred Stock”) and (ii) warrants for 2,750,000 shares of the Company’s common stock, with a term of ten years and an exercise price of $16.08 per share, exercisable only on a net share settlement basis (the “Warrants”), for a cash purchase price equal to $970.00 per share of Preferred Stock, to certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”). The Company used the net proceeds of approximately $236.4 million, net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes.

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



Period	Percentage
On or after December 15, 2017 and on or prior to September 15, 2018	100	%
On or after December 15, 2018 and on or prior to September 15, 2019	75	%
On or after December 15, 2019 and on or prior to September 15, 2020	50	%

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

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

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

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



Period	Percentage
After August 10, 2020 but on or prior to August 10, 2021	104.4375	%
After August 10, 2021 but on or prior to August 10, 2022	102.21875	%
After August 10, 2022	100	%

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


•	Upon the Company’s failure to pay a quarterly dividend within three months of the applicable payment date;


•	On or after August 10, 2024, if the Preferred Shares remain outstanding; or


•	Upon the occurrence of certain changes of control.

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

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


•	Increasing the dividend rate to 12.0% per annum until August 10, 2024 and thereafter to the greater of 12.0% per annum and the one-month LIBOR plus 10.0%;


•	Electing up to two directors to the Company’s Board of Directors; and


•	Requiring approval by the holders of the Preferred Stock to incur indebtedness subject to a leverage ratio, declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year or issuing equity of the Company’s subsidiaries to third parties.

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

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



	March 31, 2018
For the Three Months Ended March 31, 2018
Preferred Stock, beginning of period		$214,262
Redemption of preferred stock	(42,897		)
Accretion of discount on Preferred Stock	753
Preferred Stock, end of period		$172,118

Preferred Stock Dividends and Accretion

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

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

9. Shareholders’ Equity and Stock-Based Compensation

Stock-Based Compensation

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

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

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



	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
For the Three Months Ended March 31, 2018
Unvested restricted stock awards and units, beginning of period	1,482,655			$28.07
Granted	1,347,165			$14.68
Vested	(564,912	)		$31.87
Forfeited	(1,078	)		$29.61
Unvested restricted stock awards and units, end of period	2,263,830			$19.15

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

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

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



	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, 2018
Outstanding, beginning of period	714,238		$27.12
Granted	616,686		$14.67
Exercised	—		$—					$—
Forfeited	—		$—
Expired	—		$—
Outstanding, end of period	1,330,924		$21.35	5.1		$0.7
Vested, end of period	543,018		$27.18
Vested and exercisable, end of period	—		$27.18	3.3		$—

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

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



	Grant Date Fair Value Assumptions
Expected term (in years)	6.0
Expected volatility	54.3	%
Risk-free interest rate	2.8	%
Dividend yield	—	%

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

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



	Target Performance Shares ⁽¹⁾		Weighted Average Grant Date Fair Value
For the Three Months Ended March 31, 2018
Unvested performance shares, beginning of period	144,955			$47.14
Granted	93,771			$19.09
Vested	(49,458	)		$65.51
Forfeited	(7,059	)		$65.51
Unvested performance shares, end of period	182,209			$27.01


(1)	The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company’s final TSR ranking for the approximate three-year performance period.

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

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



	Grant Date Fair Value Assumptions
Number of simulations	500,000
Expected term (in years)	3.00
Expected volatility	61.5	%
Risk-free interest rate	2.4	%
Dividend yield	—	%

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

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



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Restricted stock awards and units		$5,084			$5,849
SARs	(1,415		)	(3,686		)
Performance shares	557			706
	4,226			2,869
Less: amounts capitalized to oil and gas properties	(708		)	(855		)
Total stock-based compensation expense, net		$3,518			$2,014

10. Derivative Instruments

Commodity Derivative Instruments

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

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

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

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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. The Company has incurred premiums on certain of these contracts in order to obtain a higher floor price and/or ceiling price.

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

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

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

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

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



Period	Type of Contract	Index	Volumes (Bbls/d)	Fixed Price ($/Bbl)			Sub-Floor Price ($/Bbl)		Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
2018
Q2 - Q4 2018	Fixed Price Swaps	NYMEX WTI	6,000		$49.55			$—		$—		$—
Q2 - Q4 2018	Basis Swaps	⁽¹⁾	6,000	2.91			—		—		—
Q2 - Q4 2018	Basis Swaps	⁽²⁾	6,000	(0.10		)	—		—		—
Q2 - Q4 2018	Three-Way Collars	NYMEX WTI	24,000	—			39.38		49.06		60.14
Q2 - Q4 2018	Net Sold Call Options	NYMEX WTI	3,388	—			—		—		71.33
2019
Q1 - Q2 2019	Basis Swaps	⁽²⁾	500	(2.99		)	—		—		—
Q1 - Q4 2019	Three-Way Collars	NYMEX WTI	12,000	—			40.00		48.40		60.29
Q1 - Q4 2019	Net Sold Call Options	NYMEX WTI	3,875	—			—		—		73.66
2020
Q1 - Q4 2020	Net Sold Call Options	NYMEX WTI	4,575	—			—		—		75.98


(1)	The Company has entered into crude oil basis swaps in order to fix the differential between LLS-Cushing. The weighted average price differential represents the amount of premium to Cushing for the volumes presented in the table above.


(2)	The Company has entered into crude oil basis swaps in order to fix the differential between Midland-Cushing. The weighted average price differential represents the amount of reduction to Cushing for the volumes presented in the table above.

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



Period	Type of Contract	Index	Volumes (Bbls/d)	Fixed Price ($/Bbl)
2018
Q2 - Q4 2018	Fixed Price Swaps	Ethane - OPIS Mont Belvieu Non-TET	2,200		$12.01
Q2 - Q4 2018	Fixed Price Swaps	Propane - OPIS Mont Belvieu Non-TET	1,500	34.23
Q2 - Q4 2018	Fixed Price Swaps	Butane - OPIS Mont Belvieu Non-TET	200	38.85
Q2 - Q4 2018	Fixed Price Swaps	Isobutane - OPIS Mont Belvieu Non-TET	600	38.98
Q2 - Q4 2018	Fixed Price Swaps	Natural Gasoline - OPIS Mont Belvieu Non-TET	600	55.23

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



Period	Type of Contract	Index	Volumes (MMBtu/d)	Fixed Price ($/Bbl)		Ceiling Price ($/Bbl)
2018
Q2 - Q4 2018	Fixed Price Swaps	NYMEX HH	25,000		$3.01		$—
Q2 - Q4 2018	Sold Call Options	NYMEX HH	33,000	—		3.25
2019
Q1 - Q4 2019	Sold Call Options	NYMEX HH	33,000	—		3.25
2020
Q1 - Q4 2020	Sold Call Options	NYMEX HH	33,000	—		3.50

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability 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 the Company’s 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 and its counterparty’s parent company, as applicable.

Contingent Consideration

As part of the ExL Acquisition in 2017, the Company agreed to the Contingent ExL Consideration that will require payment of $50.0 million per year for each of the years of 2018 through 2021, with a cap of $125.0 million, if the EIA WTI average price is greater than $50.00 per barrel for the respective year. As of March 31, 2018, the estimated fair value of the Contingent ExL Consideration was $91.5 million.

As part of the divestiture of the Company’s Utica assets in 2017, the Company agreed to the Contingent Utica Consideration in which the Company will receive $5.0 million per year for each of the years of 2018 through 2020, if the EIA WTI average price is greater than $50.00, $53.00, and $56.00 for the years of 2018, 2019, and 2020, respectively. As of March 31, 2018, the estimated fair value of the Contingent Utica Consideration was $9.0 million.

As part of the divestiture of the Company’s Marcellus assets in 2017, the Company agreed to the Contingent Marcellus Consideration in which the Company will receive $3.0 million per year for each of the years of 2018 through 2020, with a cap of $7.5 million, if the CME HH average price is greater than $3.13, $3.18, and $3.30 for the years of 2018, 2019, and 2020, respectively. As of March 31, 2018, the estimated fair value of the Contingent Marcellus Consideration was $1.7 million.

-18-

As part of the divestiture of the Company’s Niobrara assets in the first quarter of 2018, the Company agreed to the Contingent Niobrara Consideration in which the Company will receive $5.0 million per year for each of the years of 2018 through 2020, if the EIA WTI average price is above $55.00 for the years of 2018 and 2019 and above $60.00 for 2020. The Company recorded the Contingent Niobrara Consideration at its divestiture date fair value of $7.9 million in the consolidated financial statements. As of March 31, 2018, the estimated fair value of the Contingent Niobrara Consideration was $8.3 million.

The following tables summarize the combined contingent consideration recorded in the consolidated financial statements:



	Consolidated Balance Sheets
	March 31, 2018
	Other Assets - Current		Other Assets - Non-Current		Derivative Liabilities - Current			Derivative Liabilities - Non-Current
	(In thousands)
Contingent ExL Consideration		$—		$—		($47,260	)		($44,195	)
Contingent Utica Consideration	4,685		4,320		—			—
Contingent Marcellus Consideration	360		1,375		—			—
Contingent Niobrara Consideration	4,415		3,850		—			—
Contingent consideration		$9,460		$9,545		($47,260	)		($44,195	)



	Consolidated Balance Sheets
	December 31, 2017
	Other Assets - Current		Other Assets - Non-Current		Derivative Liabilities - Current		Derivative Liabilities - Non-Current
	(In thousands)
Contingent ExL Consideration		$—		$—		$—		($85,625	)
Contingent Utica Consideration	—		7,985		—		—
Contingent Marcellus Consideration	—		2,205		—		—
Contingent Niobrara Consideration	—		—		—		—
Contingent consideration		$—		$10,190		$—		($85,625	)



	Consolidated Statements of Income
	Three Months Ended March 31, 2018
	(Gain) Loss on Derivatives, Net
	(In thousands)
Contingent ExL Consideration		$5,830
Contingent Utica Consideration	(1,020		)
Contingent Marcellus Consideration	470
Contingent Niobrara Consideration	(385		)
Contingent consideration		$4,895

-19-

Derivative Assets and Liabilities

All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the consolidated balance sheets as of March 31, 2018 and December 31, 2017 are summarized below:



	March 31, 2018
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$15,494			($15,027	)		$467
Deferred premium obligations	—			—			—
Contingent consideration	9,460			—			9,460
Other current assets		$24,954			($15,027	)		$9,927
Commodity derivative instruments	9,855			(9,830		)	25
Deferred premium obligations	—			—			—
Contingent consideration	9,545			—			9,545
Other assets-non current		$19,400			($9,830	)		$9,570

Commodity derivative instruments		($73,280	)		$15,027			($58,253	)
Deferred premium obligations	(9,746		)	—			(9,746		)
Contingent consideration	(47,260		)	—			(47,260		)
Derivative liabilities-current		($130,286	)		$15,027			($115,259	)
Commodity derivative instruments	(27,019		)	9,830			(17,189		)
Deferred premium obligations	(9,468		)	—			(9,468		)
Contingent consideration	(44,195		)	—			(44,195		)
Derivative liabilities-non current		($80,682	)		$9,830			($70,852	)



	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—
Deferred premium obligations	—			—			—
Other current assets		$4,869			($4,869	)		$—
Commodity derivative instruments	9,505			(9,505		)	—
Deferred premium obligations	—			—			—
Contingent consideration	10,190			—			10,190
Other assets-non current		$19,695			($9,505	)		$10,190

Commodity derivative instruments		($52,671	)		$4,869			($47,802	)
Deferred premium obligations	(9,319		)	—			(9,319		)
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(24,609		)	9,505			(15,104		)
Deferred premium obligations	(11,603		)	—			(11,603		)
Contingent consideration	(85,625		)	—			(85,625		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)

See “Note 11. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative instruments.

-20-

(Gain) Loss on Derivatives, Net

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of the Company’s commodity derivative instruments and contingent consideration are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations in the consolidated statements of income for the three months ended March 31, 2018 and 2017 is summarized below:



	Three Months Ended March 31,
	2018			2017
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$29,511			($18,480	)
Natural gas liquids	(1,765		)	—
Natural gas	(3,045		)	(6,836		)
Contingent consideration	4,895			—
Total (Gain) Loss on Derivatives, Net		$29,596			($25,316	)

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. The effect of commodity derivative instruments and deferred premium obligations in the consolidated statements of cash flows for the three months ended March 31, 2018 and 2017 is summarized below:



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		($12,123	)		$3,031
Natural gas liquids	(432		)	—
Natural gas	52			(1,149		)
Deferred premium obligations paid	(1,862		)	(363		)
Total Cash Received (Paid) for Derivative Settlements, Net		($14,365	)		$1,519

11. 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.

-21-

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, 2018 and December 31, 2017:



	March 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$492			$19,005
Derivative instrument liabilities		$—		($75,442	)		($91,455	)



	December 31, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$—			$10,190
Derivative instrument liabilities		$—		($62,906	)		($85,625	)

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.

Commodity derivative instruments. The fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model which uses 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, and are therefore designated as Level 2 within the valuation hierarchy. 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 Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the fair value derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company nets the fair values of its derivative assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, 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, 2018 and 2017.

Contingent consideration. The fair values of the Contingent ExL Consideration, the Contingent Utica Consideration, the Contingent Marcellus Consideration and the Contingent Niobrara Consideration were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

-22-

The following tables present reconciliations of changes in the fair values of the financial assets and liabilities related to the Company’s contingent consideration, which were designated as Level 3 within the valuation hierarchy, for the three months ended March 31, 2018:



	Three Months Ended March 31,
	2018
	(In thousands)
Fair value assets, beginning of period		$10,190
Recognition of divestiture date fair value	7,880
Gain (loss) on changes in fair value⁽¹⁾	935
Transfers into (out of) Level 3	—
Fair value assets, end of period		$19,005



	Three Months Ended March 31,
	2018
	(In thousands)
Fair value liability, beginning of period		($85,625	)
Gain (loss) on changes in fair value⁽¹⁾	(5,830		)
Transfers into (out of) Level 3	—
Fair value liability, end of period		($91,455	)


(1)	Included in “(Gain) loss on derivatives, net” in the consolidated statements of income.

See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 10. Derivative Instruments” for further details regarding the contingent consideration.

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

The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as 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.

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 designated 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 unamortized premiums and debt issuance costs, with the fair values measured using quoted secondary market trading prices.



	March 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$128,947		$132,236		$446,087		$459,518
6.25% Senior Notes due 2023	642,116		650,540		641,792		674,375
8.25% Senior Notes due 2025	245,710		262,500		245,605		274,375
Other long-term debt due 2028	4,425		4,348		4,425		4,445

-23-

12. 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.

-24-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)



	March 31, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets	$3,121,696			$105,225			$—		($3,107,720		)		$119,201
Total property and equipment, net	6,075			2,395,752			3,028		(3,870		)	2,400,985
Investment in subsidiaries	(884,965		)	—			—		884,965			—
Other assets	8,725			9,546			—		—			18,271
Total Assets		$2,251,531			$2,510,523			$3,028		($2,226,625	)		$2,538,457

Liabilities and Shareholders’ Equity
Current liabilities	$209,448			$3,329,846			$3,028		($3,110,741		)		$431,581
Long-term liabilities	1,461,955			65,642			—		15,880			1,543,477
Preferred stock	172,118			—			—		—			172,118
Total shareholders’ equity	408,010			(884,965		)	—		868,236			391,281
Total Liabilities and Shareholders’ Equity		$2,251,531			$2,510,523			$3,028		($2,226,625	)		$2,538,457



	December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,441,633			$105,533			$—		($3,424,288	)		$122,878
Total property and equipment, net	5,953			2,630,707			3,028		(3,878		)	2,635,810
Investment in subsidiaries	(999,793		)	—			—		999,793			—
Other assets	9,270			10,346			—		—			19,616
Total Assets		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities		$165,701			$3,631,401			$3,028		($3,427,308	)		$372,822
Long-term liabilities	1,689,466			114,978			—		15,879			1,820,323
Preferred stock	214,262			—			—		—			214,262
Total shareholders’ equity	387,634			(999,793		)	—		983,056			370,897
Total Liabilities and Shareholders’ Equity		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

-25-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

(In thousands)

(Unaudited)



	Three Months Ended March 31, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$20			$225,260			$—		$—			$225,280
Total costs and expenses	87,365			110,113			—		(9		)	197,469
Income (loss) before income taxes	(87,345		)	115,147			—		9			27,811
Income tax expense	—			(319		)	—		—			(319		)
Equity in income of subsidiaries	114,828			—			—		(114,828		)	—
Net income		$27,483			$114,828			$—		($114,819	)		$27,492
Dividends on preferred stock	(4,863		)	—			—		—			(4,863		)
Accretion on preferred stock	(753		)	—			—		—			(753		)
Loss on redemption of preferred stock	(7,133		)	—			—		—			(7,133		)
Net income attributable to common shareholders		$14,734			$114,828			$—		($114,819	)		$14,743



	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
Dividends on preferred stock	—			—		—		—			—
Accretion on preferred stock	—			—		—		—			—
Loss on redemption of preferred stock	—			—		—		—			—
Net income attributable to common shareholders		$40,031			$58,817		$—		($58,827	)		$40,021

-26-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Three Months Ended March 31, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities		($88,377	)		$227,101			$—		$—			$138,724
Net cash provided by investing activities	334,688			107,862			—		(334,963		)	107,587
Net cash used in financing activities	(250,966		)	(334,963		)	—		334,963			(250,966		)
Net decrease in cash and cash equivalents	(4,655		)	—			—		—			(4,655		)
Cash and cash equivalents, beginning of period	9,540			—			—		—			9,540
Cash and cash equivalents, end of period		$4,885			$—			$—		$—			$4,885



	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

-27-

13. Supplemental Cash Flow Information

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



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$14,855			$19,480

Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		($9,677	)		$28,139
Contingent consideration related to divestitures of oil and gas properties	(7,880		)	—

14. Subsequent Events

Hedging

In April 2018, the Company entered into the following crude oil derivative positions at the weighted average contract prices summarized below:



Period	Type of Contract	Index	Volumes (Bbls/d)	Fixed Price ($/Bbl)			Sub-Floor Price ($/Bbl)		Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
2019
Q1 - Q2 2019	Basis Swaps	⁽¹⁾	2,500		($4.00	)		$—		$—		$—
Q3 - Q4 2019	Basis Swaps	⁽¹⁾	3,000	(4.00		)	—		—		—
Q1 - Q4 2019	Three-Way Collars	NYMEX WTI	3,000	—			45.00		55.00		71.21


(1)	The Company has entered into crude oil basis swaps in order to fix the differential between Midland-Cushing. The weighted average price differential represents the amount of reduction to Cushing for the volumes presented in the table above.

Redemption of Other Long-Term Debt

On April 2, 2018, the Company delivered a notice of redemption to the trustee for its 4.375% Convertible Senior Notes due 2028 to call for redemption on May 3, 2018 all of the remaining outstanding convertible senior notes. On May 3, 2018, the Company paid an aggregate redemption price of $4.5 million, which consisted of a redemption price of $4.4 million, equal to 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest of $0.1 million from the last interest payment date up to, but not including, the redemption date.

Twelfth Amendment to the Credit Agreement

On May 4, 2018, the Company entered into the twelfth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $1.0 billion, with an elected commitment amount of $900.0 million, until the next redetermination thereof, (ii) reduce the margins applied to Eurodollar loans from 2.0%-3.0% to 1.5%-2.5%, depending on level of facility usage, (iii) amend the covenant limiting payment of dividends and distributions on equity to increase the Company’s ability to make dividends and distributions on its equity interests and (iv) amend certain other provisions, in each case as set forth therein.

-28-

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 2017 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

First Quarter 2018 Highlights

•

Total production for the three months ended March 31, 2018 was 51,257 Boe/d, an increase of 11% from the three months ended March 31, 2017, primarily due to production from new wells in the Eagle Ford and Delaware Basin and the addition of production from the ExL Acquisition in the third quarter of 2017, partially offset by the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in January 2018.


•	Operated drilling and completion activity for the three months ended March 31, 2018 along with our drilled but uncompleted and producing wells as of March 31, 2018 are summarized in the table below.



	Three Months Ended March 31, 2018				March 31, 2018
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	11	9.0	31	25.8	20	17.3	451	407.6
Delaware Basin	10	6.8	3	2.1	12	9.7	37	30.3
Total	21	15.8	34	27.9	32	27.0	488	437.9


•	Drilling and completion expenditures for the first quarter of 2018 were $209.9 million, all of which were in the Eagle Ford and Delaware Basin. We currently expect to operate five to six rigs and two to three completion crews between the Eagle Ford and Delaware Basin for the remainder of 2018.

•

In the first quarter of 2018, we closed on divestitures of substantially all of our assets in the Niobrara Formation and a portion of our assets in the Eagle Ford for estimated aggregate net proceeds of $379.4 million, subject to post-closing adjustments. In addition, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020 as part of the Niobrara Formation divestiture. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details regarding these divestitures.


•	In January 2018, we called for redemption a total of $320.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. The proceeds for these redemptions were primarily from the Niobrara and Eagle Ford divestitures discussed above. As a result of the redemptions, we recorded a loss on extinguishment of debt of $8.7 million.


•	In January 2018, we redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends. As a result of the redemption, we recorded a loss on redemption of preferred stock of $7.1 million.


•	In January 2018, as a result of the divestiture in the Eagle Ford discussed above, our borrowing base under our revolving credit facility was reduced from $900.0 million to $830.0 million, however, the elected commitment amount remained unchanged at $800.0 million.

•

We recorded net income attributable to common shareholders for the three months ended March 31, 2018 of $14.7 million, or $0.18 per diluted share, as compared to net income attributable to common shareholders for the three months ended March 31, 2017 of $40.0 million, or $0.61 per diluted share. The reduction in net income attributable to common shareholders for the first quarter of 2018 as compared to the net income attributable to common shareholders for the first quarter of 2017 was driven primarily by a loss on derivatives, net of $29.6 million in the first quarter of 2018 as compared to a gain on derivatives, net of $25.3 million in the first quarter 2017 as well as the losses on the partial redemptions of the 7.5% Senior Notes and the Preferred Stock of $8.7 million and $7.1

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million, respectively, partially offset by higher production volumes and commodity prices in the first quarter of 2018 compared to the first quarter of 2017. See “—Results of Operations” below for further details.

Recent Developments

•

In May 2018, we entered into the twelfth amendment to our credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $1.0 billion, with an elected commitment amount of $900.0 million, until the next redetermination thereof, (ii) reduce the margins applied to Eurodollar loans from 2.0%-3.0% to 1.5%-2.5%, depending on level of facility usage, (iii) amend the covenant limiting payment of dividends and distributions on equity to increase our ability to make dividends and distributions on our equity interests and (iv) amend certain other provisions, in each case as set forth therein.


•	Our current 2018 drilling, completion, and infrastructure capital expenditure plan remains at $750.0 million to $800.0 million. See “—Liquidity and Capital Resources—2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy” for additional details.

Results of Operations

Three Months Ended March 31, 2018, Compared to the Three Months Ended March 31, 2017

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,				2018 Period Compared to 2017 Period
	2018		2017		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,072		2,596		476			18	%
NGLs (MBbls)	739		406		333			82	%
Natural gas (MMcf)	4,810		7,028		(2,218		)	(32	%)
Total barrels of oil equivalent (MBoe)	4,613		4,173		440			11	%

Daily production volumes by product -
Crude oil (Bbls/d)	34,136		28,844		5,292			18	%
NGLs (Bbls/d)	8,213		4,508		3,705			82	%
Natural gas (Mcf/d)	53,446		78,088		(24,642		)	(32	%)
Total barrels of oil equivalent (Boe/d)	51,257		46,367		4,890			11	%

Daily production volumes by region (Boe/d) -
Eagle Ford	35,623		32,578		3,045			9	%
Delaware Basin	15,235		2,418		12,817			530	%
Niobrara and other	399		11,371		(10,972		)	(96	%)
Total barrels of oil equivalent (Boe/d)	51,257		46,367		4,890			11	%

Average realized prices -
Crude oil ($ per Bbl)		$63.45		$49.34		$14.11		29	%
NGLs ($ per Bbl)	22.87		18.29		4.58			25	%
Natural gas ($ per Mcf)	2.80		2.25		0.55			24	%
Total average realized price ($ per Boe)		$48.84		$36.27		$12.57		35	%

Revenues (In thousands) -
Crude oil		$194,919		$128,092		$66,827		52	%
NGLs	16,902		7,425		9,477			128	%
Natural gas	13,459		15,838		(2,379		)	(15	%)
Total revenues		$225,280		$151,355		$73,925		49	%

Production volumes for the three months ended March 31, 2018 were 51,257 Boe/d, an increase of 11% from 46,367 Boe/d for the same period in 2017. The increase is primarily due to production from new wells in the Eagle Ford and Delaware Basin

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and the addition of production from the ExL Acquisition in the third quarter of 2017, partially offset by the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in January 2018. Revenues for the three months ended March 31, 2018 increased 49% to $225.3 million from $151.4 million for the same period in 2017 primarily due to higher crude oil prices and increased crude oil and NGL production.

Lease operating expenses for the three months ended March 31, 2018 increased to $39.3 million ($8.51 per Boe) from $29.8 million ($7.15 per Boe) for the same period in 2017. The increase in lease operating expenses is primarily due to increased production in the Eagle Ford and the addition of production from the ExL Acquisition in the third quarter of 2017. The increase in lease operating expense per Boe is primarily due to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties, as a result of the divestiture in the Marcellus Shale in the fourth quarter of 2017 as well as processing fees for certain of our natural gas and NGL processing contracts that are now presented in lease operating expenses as a result of the adoption of ASC 606.

Production taxes increased to $10.6 million (or 4.7% of revenues) for the three months ended March 31, 2018 from $6.2 million (or 4.1% of revenues) for the same period in 2017 primarily as a result of the increase in crude oil and NGL revenues. The increase in production taxes as a percentage of revenues is primarily due to the divestiture of substantially all of our assets in the Marcellus Shale in the fourth quarter of 2017, as production in Marcellus was not subject to production taxes.

Ad valorem taxes decreased to $2.0 million for the three months ended March 31, 2018 from $3.0 million for the same period in 2017. The decrease in ad valorem taxes is due to the divestitures of substantially all of our assets in the Marcellus Shale and Niobrara Formation in the fourth quarter of 2017 and the first quarter of 2018, respectively, as well as the divestiture of a portion of our assets in the Eagle Ford in the first quarter of 2018, partially offset by new wells drilled in the Eagle Ford and new wells acquired in the ExL Acquisition in the third quarter of 2017.

DD&A expense for the three months ended March 31, 2018 increased $10.1 million to $64.5 million ($13.98 per Boe) from $54.4 million ($13.03 per Boe) for the same period in 2017. The increase in DD&A expense is attributable to increased production as well as an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is due primarily to increases in service costs that occurred in the first quarter of 2018 as well as increased proved oil and gas properties related to the ExL Acquisition in the third quarter of 2017, partially offset by the reduction in proved oil and gas properties as a result of the sales of substantially all of our assets in the Utica and Marcellus Shales in the fourth quarter of 2017, the Niobrara Formation in the first quarter of 2018, and a portion of our assets in the Eagle Ford Shale in the first quarter of 2018. The components of our DD&A expense were as follows:



	Three Months Ended March 31,
	2018		2017
	(In thousands)
DD&A of proved oil and gas properties		$63,331		$52,960
Depreciation of other property and equipment	580		646
Amortization of other assets	234		351
Accretion of asset retirement obligations	322		425
Total DD&A		$64,467		$54,382

General and administrative expense, net increased to $27.3 million for the three months ended March 31, 2018 from $21.7 million for the same period in 2017. The increase was primarily due to an increase in stock-based compensation expense, net as a result of a smaller decrease in the fair value of stock appreciation rights for the three months ended March 31, 2018 compared to the decrease in fair value for the three months ended March 31, 2017 as well as an increase in personnel and higher annual bonuses awarded in the first quarter of 2018 compared to the first quarter of 2017.

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We recorded a loss on derivatives, net of $29.6 million and a gain on derivatives, net of $25.3 million for the three months ended March 31, 2018 and 2017, respectively. The components of our (gain) loss on derivatives, net were as follows:



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Crude oil derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period		$29,596			($18,480	)
Gain due to new derivative positions executed during the period	(85		)	—
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	(1,807		)	(6,836		)
Gain due to new derivative positions executed during the period	(1,238		)	—
NGL derivative positions:
Gain due to downward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period	(1,765		)	—
Contingent consideration:
Net loss due to upward shift in the futures curve of forecasted crude oil prices during the period	4,895			—
(Gain) loss on derivatives, net		$29,596			($25,316	)

Interest expense, net for the three months ended March 31, 2018 was $15.5 million as compared to $20.6 million for the same period in 2017. The decrease was due primarily to reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the fourth quarter of 2017 and first quarter of 2018 and an increase in capitalized interest as a result of higher average balances of unevaluated leasehold and seismic costs for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017, primarily as a result of the ExL Acquisition. The decrease was partially offset by interest expense on $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in July 2017 and an increase in interest expense on our revolving credit facility as a result of increased borrowings for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017. The components of our interest expense, net were as follows:



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Interest expense on Senior Notes		$21,486			$21,455
Interest expense on revolving credit facility	3,158			1,426
Amortization of debt issuance costs, premiums, and discounts	1,104			1,186
Other interest expense	137			285
Capitalized interest	(10,368		)	(3,781		)
Interest expense, net		$15,517			$20,571

As a result of our redemption of $320.0 million aggregate principal amount of our 7.50% Senior Notes, we recorded a loss on extinguishment of debt of $8.7 million for the three months ended March 31, 2018, which includes redemption premiums paid to redeem the notes of $6.0 million and non-cash charges of $2.7 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes.

The effective income tax rate for the three months ended March 31, 2018 and 2017 was 1.1% and 0.0% respectively. The variance in the effective income tax rate results from state current and deferred income tax expense of $0.3 million recognized during the first quarter of 2018. This was due to changes to our state apportionment for estimated state deferred tax liabilities as a result of the significant changes in our areas of operations that occurred in late 2017 and early 2018 as well as current period activity. The effective income tax rate was 0.0% in the first quarter of 2017 as a result of a full valuation allowance against our net deferred tax assets driven by impairments of proved oil and gas properties recognized in the third quarter of 2015 and continuing through the third quarter of 2016.

For the three months ended March 31, 2018, we declared and paid $4.9 million of dividends on our Preferred Stock, in cash, which reduced net income to compute net income attributable to common shareholders.

As a result of our redemption of 50,000 shares of Preferred Stock at $1,000.00 per share, or $50.0 million, we recorded a loss on redemption of preferred stock of $7.1 million for the three months ended March 31, 2018, which reduced net income to

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compute net income attributable to common shareholders. This loss was calculated as the difference between the consideration transferred to the holders of the Preferred Stock, excluding accrued and unpaid dividends, of $50.0 million and 20% of the carrying value of the Preferred Stock on the date of redemption plus any direct costs incurred as a result of the redemption.

Liquidity and Capital Resources

2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy. Our 2018 drilling, completion, and infrastructure capital expenditure plan remains unchanged at $750.0 million to $800.0 million. We currently intend to finance the remainder of our 2018 drilling, completion, and infrastructure 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, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, 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. The following is a summary of our capital expenditures for the three months ended March 31, 2018:



	Three Months Ended
	March 31, 2018
	(In thousands)
Drilling, completion, and infrastructure
Eagle Ford		$135,677
Delaware Basin	73,892
All other regions	284
Total drilling, completion, and infrastructure	209,853
Leasehold and seismic	5,520
Total Capital Expenditures ⁽¹⁾		$215,373


(1)	Capital expenditures exclude acquisitions of oil and gas properties, capitalized general and administrative expense, interest expense and asset retirement costs.

Sources and Uses of Cash. Our primary use of cash is related to our drilling, completion and infrastructure capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the three months ended March 31, 2018, 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 revolving credit facility. As of April 30, 2018, our revolving credit facility had a borrowing base of $830.0 million, with an elected commitment amount of $800.0 million, with $450.6 million of borrowings outstanding and no letters of credit issued, which reduce the amounts available under our revolving credit facility. On May 4, 2018, we entered in the twelfth amendment to the credit agreement governing our revolving credit facility which, among other things, established the borrowing base at $1.0 billion, with an elected commitment amount of $900.0 million. 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 “Note 14. Subsequent Events” for further details of the recent twelfth amendment.


•	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.


•	Divestitures. We may consider divesting 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 divest such assets on terms that are acceptable to us. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for details of the divestitures that occurred in early 2018.


•	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 $138.7 million and $76.4 million for the three months ended March 31, 2018 and 2017, respectively. The change was driven primarily by an increase in revenues as a result

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of higher production and commodity prices and a decrease in working capital requirements, partially offset by an increase in the net cash paid for derivative settlements and an increase in operating expenses and cash general and administrative expense.

Net cash provided by investing activities was $107.6 million for the three months ended March 31, 2018 and net cash used in investing activities was $113.8 million for the three months ended March 31, 2017. The change was due primarily to cash received from divestitures of oil and gas properties, partially offset by an increase in capital expenditures. The divestitures of oil and gas properties were related to the divestitures of a portion of our assets in the Eagle Ford Shale, as well as substantially all of our assets in the Niobrara Formation.

Net cash used in financing activities was $251.0 million for the three months ended March 31, 2018 and net cash provided by financing activities for the three months ended March 31, 2017 was $35.6 million. The increase in net cash used in financing activities was due to payments for the redemptions of the 7.50% Senior Notes and the Preferred Stock as well as dividends paid on the Preferred Stock, partially offset by increased borrowings net of repayments under our revolving credit facility in the first quarter of 2018 as compared to the first quarter of 2017.

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, crude oil prices, and settlements of our crude oil derivatives. We currently believe that cash flows from operations and borrowings under our revolving credit facility will 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 revolving credit facility” and “—Financing Arrangements—Senior Secured Revolving Credit Facility” for further details of our revolving credit facility.

•

Contingent consideration. In connection with the ExL Acquisition, we agreed to a contingent payment of $50.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2021 with a cap of $125.0 million. In connection with the sale of our Utica Shale assets, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020. In connection with the sale of our Marcellus Shale assets, we could receive contingent consideration of $3.0 million per year if natural gas prices exceed specified thresholds for each of the years of 2018 through 2020 with a cap of $7.5 million. In connection with the sale of our Niobrara Formation assets, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of each of these contingent considerations. See also “—Volatility of Crude Oil and Natural Gas Prices” for details of the sensitivities to commodity price of each contingent consideration.


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

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The following table sets forth a summary of our outstanding crude oil derivative positions at weighted average contract prices as of April 30, 2018:



Period	Type of Contract	Index	Volumes (Bbls/d)	Fixed Price ($/Bbl)			Sub-Floor Price ($/Bbl)		Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
2018
Q2 - Q4 2018	Fixed Price Swaps	NYMEX WTI	6,000		$49.55			$—		$—		$—
Q2 - Q4 2018	Basis Swaps	⁽¹⁾	6,000	2.91			—		—		—
Q2 - Q4 2018	Basis Swaps	⁽²⁾	6,000	(0.10		)	—		—		—
Q2 - Q4 2018	Three-Way Collars	NYMEX WTI	24,000	—			39.38		49.06		60.14
Q2 - Q4 2018	Net Sold Call Options	NYMEX WTI	3,388	—			—		—		71.33
2019
Q1 - Q4 2019	Basis Swaps	⁽²⁾	3,000	(3.92		)	—		—		—
Q1 - Q4 2019	Three-Way Collars	NYMEX WTI	15,000	—			41.00		49.72		62.48
Q1 - Q4 2019	Net Sold Call Options	NYMEX WTI	3,875	—			—		—		73.66
2020
Q1 - Q4 2020	Net Sold Call Options	NYMEX WTI	4,575	—			—		—		75.98


(1)	We have entered into crude oil basis swaps in order to fix the differential between LLS-Cushing. The weighted average price differential represents the amount of premium to Cushing for the volumes presented in the table above.


(2)	We have entered into crude oil basis swaps in order to fix the differential between Midland-Cushing. The weighted average price differential represents the amount of reduction to Cushing for the volumes presented in the table above.

The following table sets forth a summary of our outstanding NGL derivative positions at weighted average contract prices as of April 30, 2018:



Period	Type of Contract	Index	Volumes (Bbls/d)	Fixed Price ($/Bbl)
2018
Q2 - Q4 2018	Fixed Price Swaps	Ethane - OPIS Mont Belvieu Non-TET	2,200		$12.01
Q2 - Q4 2018	Fixed Price Swaps	Propane - OPIS Mont Belvieu Non-TET	1,500	34.23
Q2 - Q4 2018	Fixed Price Swaps	Butane - OPIS Mont Belvieu Non-TET	200	38.85
Q2 - Q4 2018	Fixed Price Swaps	Isobutane - OPIS Mont Belvieu Non-TET	600	38.98
Q2 - Q4 2018	Fixed Price Swaps	Natural Gasoline - OPIS Mont Belvieu Non-TET	600	55.23

The following table sets forth a summary of our outstanding natural gas derivative positions at weighted average contract prices as of April 30, 2018:



Period	Type of Contract	Index	Volumes (MMBtu/d)	Fixed Price ($/Bbl)		Ceiling Price ($/Bbl)
2018
Q2 - Q4 2018	Fixed Price Swaps	NYMEX HH	25,000		$3.01		$—
Q2 - Q4 2018	Sold Call Options	NYMEX HH	33,000	—		3.25
2019
Q1 - Q4 2019	Sold Call Options	NYMEX HH	33,000	—		3.25
2020
Q1 - Q4 2020	Sold Call Options	NYMEX HH	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 our remaining 2018 drilling, completion, and infrastructure 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 2018 drilling, completion, and infrastructure 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,

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proceeds from divestitures, securities offerings or borrowings to reduce debt or Preferred Stock prior to scheduled maturities through debt or Preferred Stock repurchases, either in the open market or in privately negotiated transactions, through debt or Preferred Stock 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, 2018 (in thousands):



	2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$130,000		$—		$421,700		$904,425		$1,456,125
Cash interest on senior notes and other long-term debt ⁽²⁾	56,006		71,194		71,194		61,444		61,444		83,236		404,518
Cash interest and commitment fees on revolving credit facility ⁽³⁾	15,103		19,772		19,772		19,772		6,810		—		81,229
Capital leases	1,359		1,800		1,050		—		—		—		4,209
Operating leases	3,927		5,127		4,822		4,493		1,854		—		20,223
Drilling rig contracts ⁽⁴⁾	29,777		20,173		1,196		—		—		—		51,146
Delivery commitments ⁽⁵⁾	2,756		3,676		2,757		2,438		10		26		11,663
Produced water disposal commitments ⁽⁶⁾	7,090		18,107		18,197		18,196		18,242		17,276		97,108
Asset retirement obligations and other ⁽⁷⁾	1,462		496		261		53		234		14,970		17,476
Total Contractual Obligations ⁽⁸⁾		$117,480		$140,345		$249,249		$106,396		$510,294		$1,019,933		$2,143,697


(1)	Long-term debt consists of the principal amounts of the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, the 8.25% Senior Notes due 2025, other long-term debt due 2028, and borrowings outstanding under our revolving credit facility which matures in 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).


(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, the 8.25% Senior Notes due 2025 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, 2018 of 4.24%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of March 31, 2018, at the applicable commitment fee rate of 0.50%.


(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 service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.


(6)	Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.


(7)	Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of March 31, 2018. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.


(8)	In connection with the ExL Acquisition, we have agreed to a contingent payment of $50.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2021 with a cap of $125.0 million, which is not included in the table above.

Financing Arrangements

Senior Secured Revolving Credit Facility

We have a senior secured revolving credit facility with a syndicate of banks that, as of March 31, 2018, had a borrowing base of $830.0 million, with an elected commitment amount of $800.0 million, and $421.7 million of borrowings outstanding at a weighted average interest rate of 4.24%. As of March 31, 2018, we had no letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing our senior secured revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures (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) and any outstanding borrowings are due.

On January 31, 2018, as a result of the divestiture in the Eagle Ford Shale, the borrowing base under the senior secured revolving credit facility was reduced from $900.0 million to $830.0 million, however, the elected commitment amount remained unchanged at $800.0 million.

See “Note 6. Long-Term Debt” for details of 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. In addition,

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see “Note 14. Subsequent Events” for details of the twelfth amendment that was entered into in May 2018 which, among other things, established the borrowing base at $1.0 billion, with an elected commitment amount of $900.0 million.

Redemptions of 7.50% Senior Notes

On January 19, 2018, we delivered a notice of redemption to the trustee for our 7.50% Senior Notes to call for redemption on February 18, 2018, $100.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On February 20, 2018, we paid an aggregate redemption price of $105.1 million, which included a redemption premium of $1.9 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $100.0 million of the 7.50% Senior Notes, we recorded a loss on extinguishment of debt of $2.7 million.

On January 31, 2018, we delivered a notice of redemption to the trustee for our 7.50% Senior Notes to call for redemption on March 2, 2018, $220.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On March 2, 2018, we paid an aggregate redemption price of $231.8 million, which includes a redemption premium of $4.1 million as well as accrued and unpaid interest of $7.7 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $220.0 million of the 7.50% Senior Notes, we recorded a loss on extinguishment of debt of $6.0 million.

Redemption of Preferred Stock

On January 19, 2018, we provided a notice to be delivered to the holders of our Preferred Stock under which it called for redemption of 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, on January 24, 2018. We paid $50.5 million on January 24, 2018 upon redemption, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends, with a portion of the proceeds from the divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the divestitures of oil and gas properties. As a result of the redemption, we recorded a loss on redemption of preferred stock of $7.1 million.

Redemption of Other Long-Term Debt

On April 2, 2018, we delivered a notice of redemption to the trustee for our 4.375% Convertible Senior Notes due 2028 to call for redemption on May 3, 2018 all of the remaining outstanding convertible senior notes. On May 3, 2018, we paid an aggregate redemption price of $4.5 million, which consisted of a redemption price of $4.4 million, equal to 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest of $0.1 million from the last interest payment date up to, but not including, the redemption date.

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, contingent consideration, income taxes, commitments and contingencies and preferred stock. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2017 Annual Report. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties”, “Note 8. Preferred Stock”, “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for details of the contingent consideration and preferred stock. We evaluate subsequent events through the date the financial statements are issued.

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The table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, 2018 cost center ceiling to changes in 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 quarter (“12-Month Average Realized Price”). The sensitivity analysis is as of March 31, 2018 and, accordingly, does not consider drilling and completion activity, acquisitions or divestitures of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to March 31, 2018 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, 2018 Actual	$52.89	$2.84	$1,060

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$58.24	$3.15	$1,502	$442
Crude Oil and Natural Gas -10%	$47.53	$2.53	$516	($544)

Crude Oil Price Sensitivity
Crude Oil +10%	$58.24	$2.84	$1,461	$401
Crude Oil -10%	$47.53	$2.84	$567	($493)

Natural Gas Price Sensitivity
Natural Gas +10%	$52.89	$3.15	$1,099	$39
Natural Gas -10%	$52.89	$2.53	$1,020	($40)

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 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, 2018, 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. Beginning in the third quarter of 2015, and continuing through the first quarter of 2018, we concluded that it was more likely than not the deferred tax assets will not be realized. As a result, at the end of each quarter, including March 31, 2018, the Company determined a valuation allowance was required.

For the three months ended March 31, 2018, the Company reduced the valuation allowance by $8.4 million due to a partial release as a result of current period activity. After the impact of the partial release, the valuation allowance as of March 31, 2018 was $324.6 million. For the three months ended March 31, 2017, as a result of adopting 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. This increase was more than offset by a partial release of $17.4 million as a result of activity during the first quarter of 2017.

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

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one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income.

As of March 31, 2018, we have estimated U.S. federal net operating loss carryforwards of $1.2 billion. Our ability to utilize these U.S. loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold.

Due to the issuance of the Preferred Stock and the common stock offerings associated with the ExL Acquisition in 2017, our calculated ownership change percentage increased, however, as of March 31, 2018, we do not believe we have a Section 382 limitation on the ability to utilize our U.S. loss carryforwards. Future equity transactions involving us or 5% shareholders of us (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes and therefore a limitation on the annual utilization of the U.S. loss carryforwards.

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 the pronouncements we recently adopted 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 use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted production and thereby achieve a more predictable level of cash flows to support our drilling, completion, and infrastructure capital expenditure program. We do not enter into derivative instruments for speculative or trading purposes. As of March 31, 2018, our commodity derivative instruments consisted of fixed price swaps, basis swaps, three-way collars and purchased and sold call options. See “Note 10. Derivative Instruments” for further details of our crude oil, NGL and natural gas derivative positions as of March 31, 2018 and “Note 14. Subsequent Events” for further details of our crude oil derivative positions entered into subsequent to March 31, 2018.

We determined that the Contingent ExL Consideration, the Contingent Utica Consideration, the Contingent Marcellus Consideration, and the Contingent Niobrara Consideration are not clearly and closely related to the purchase and sale agreement for the applicable acquisition or divestiture, and therefore bifurcated these embedded features and reflected the associated assets and liabilities at fair value in the consolidated financial statements. The fair values of the contingent consideration were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. Gains and losses as a result of changes in the fair value of the contingent consideration are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the changes occur. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

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The following table sets forth the fair values as of March 31, 2018 as well as the impact on the fair values assuming a 10% increase and a 10% decrease in the respective commodity prices:



	Contingent ExL Consideration			Contingent Utica Consideration		Contingent Marcellus Consideration		Contingent Niobrara Consideration
	(In thousands)
Potential (payment) receipt per year		($50,000	)		$5,000		$3,000		$5,000
Maximum potential (payment) receipt		($125,000	)		$15,000		$7,500		$15,000

Fair value as of March 31, 2018		($91,455	)		$9,005		$1,735		$8,265
10% increase in commodity price	(98,525		)	10,055		2,885		9,625
10% decrease in commodity price	(80,805		)	7,650		970		6,145

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;


•	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, guidance and forecasts, including those 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 including the ExL Acquisition (as described in this Quarterly Report on Form 10-Q) and realize any expected benefits or effects of any acquisitions or the timing, final purchase price, financing or consummation of any acquisitions including the ExL Acquisition;


•	results of the ExL Properties;


•	our use of proceeds from our recent equity and senior notes offerings;


•	possible future divestitures or other disposition transactions and the proceeds, results or benefits of any such transactions, including the timing thereof;


•	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 divestitures;

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•	our ability to complete planned transactions on desirable terms;


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

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,” “possible,” “scheduled,” “should,” “guidance” 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, waivers or amendments under our revolving credit facility in connection with acquisitions, including the ExL Acquisition, other actions by lenders and holders of our capital stock, 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, failure to realize the anticipated benefits of the ExL Acquisition, market conditions and other factors affecting our ability to pay dividends on or redeem the Preferred Stock, integration and other acquisition risks, other factors affecting our ability to reach agreements or complete acquisitions or dispositions, actions by sellers and buyers, effects of purchase price adjustments, 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.

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 2017 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” in our 2017 Annual Report. Except as disclosed in this report, there have been no material changes from the disclosure made in our 2017 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, 2018 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.

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Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended March 31, 2018 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 2017 Annual Report.

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.

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
†+2.1		Purchase and Sale Agreement dated December 9, 2017 between Carrizo Oil & Gas, Inc., Carrizo (Eagle Ford) LLC, and EP Energy E&P Company, L.P., as amended by that certain Closing Agreement and Amendment to Purchase and Sale Agreement dated as of January 31, 2018 between the parties thereto (incorporated herein by reference to Exhibit 2.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (File No. 000-29187-87)).
*10.1		Twelfth Amendment to Credit Agreement, dated as of May 4, 2018, 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


†	Incorporated by reference as indicated.


*	Filed herewith.


+	Schedules to this exhibit have been omitted pursuant to Item 601(b) of Regulation S-K; a copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.

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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, 2018	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	May 9, 2018	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

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