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, 2019

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, if any, every Interactive Data File required to be submitted 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 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	¨
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

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $0.01 par value	CRZO	NASDAQ Global Select Market
(Title of class)	(Trading Symbol)	(Name of exchange on which registered)

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of May 3, 2019 was 92,504,440.

TABLE OF CONTENTS

		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	2
	Consolidated Statements of Income for the three months ended March 31, 2019 and 2018	3
	Consolidated Statements of Shareholders’ Equity for the three months ended March 31, 2019 and 2018	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	39
Part II. Other Information
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	40
Signatures		41

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, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents		$2,173			$2,282
Accounts receivable, net	94,944			99,723
Derivative assets	10,858			39,904
Other current assets	9,669			8,460
Total current assets	117,644			150,369
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	2,514,178			2,333,470
Unproved properties, not being amortized	665,957			673,833
Other property and equipment, net	11,880			11,221
Total property and equipment, net	3,192,015			3,018,524
Deferred income taxes	179,146			—
Operating lease right-of-use assets	71,965			—
Other long-term assets	13,222			16,207
Total Assets		$3,573,992			$3,185,100
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$122,941			$98,811
Revenues and royalties payable	46,027			49,003
Accrued capital expenditures	99,597			60,004
Accrued interest	23,314			18,377
Derivative liabilities	75,994			55,205
Current operating lease liabilities	35,543			—
Other current liabilities	46,508			40,609
Total current liabilities	449,924			322,009
Long-term debt	1,714,764			1,633,591
Asset retirement obligations	21,521			18,360
Long-term operating lease liabilities	42,468			—
Deferred income taxes	7,945			8,017
Other long-term liabilities	30,417			47,797
Total liabilities	2,267,039			2,029,774
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, 2019 and December 31, 2018	175,223			174,422
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 92,503,562 issued and outstanding as of March 31, 2019 and 91,627,738 issued and outstanding as of December 31, 2018	925			916
Additional paid-in capital	2,130,989			2,131,535
Accumulated deficit	(1,000,184		)	(1,151,547		)
Total shareholders’ equity	1,131,730			980,904
Total Liabilities and Shareholders’ Equity		$3,573,992			$3,185,100

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,
	2019			2018
Revenues
Crude oil		$202,744			$194,919
Natural gas liquids	16,837			16,902
Natural gas	13,459			13,459
Total revenues	233,040			225,280
Costs and Expenses
Lease operating	42,031			39,273
Production and ad valorem taxes	14,894			12,548
Depreciation, depletion and amortization	75,322			64,467
General and administrative, net	24,732			27,292
Loss on derivatives, net	83,284			29,596
Interest expense, net	16,451			15,517
Loss on extinguishment of debt	—			8,676
Other expense, net	4,358			100
Total costs and expenses	261,072			197,469
Income (Loss) Before Income Taxes	(28,032		)	27,811
Income tax (expense) benefit	179,395			(319		)
Net Income		$151,363			$27,492
Dividends on preferred stock	(4,360		)	(4,863		)
Accretion on preferred stock	(801		)	(753		)
Loss on redemption of preferred stock	—			(7,133		)
Net Income Attributable to Common Shareholders		$146,202			$14,743
Net Income Attributable to Common Shareholders Per Common Share
Basic		$1.59			$0.18
Diluted		$1.58			$0.18
Weighted Average Common Shares Outstanding
Basic	91,740			81,542
Diluted	92,292			82,578

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount
Balance as of December 31, 2018	91,627,738		$916		$2,131,535			($1,151,547	)		$980,904
Stock-based compensation expense	—	—		4,624			—			4,624
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	875,824	9		(9		)	—			—
Dividends on preferred stock	—	—		(4,360		)	—			(4,360		)
Accretion on preferred stock	—	—		(801		)	—			(801		)
Net income	—	—		—			151,363			151,363
Balance as of March 31, 2019	92,503,562		$925		$2,130,989			($1,000,184	)		$1,131,730
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,
	2019			2018
Cash Flows From Operating Activities
Net income		$151,363			$27,492
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	75,322			64,467
Loss on derivatives, net	83,284			29,596
Cash paid for commodity derivative settlements, net	(2,638		)	(14,365		)
Loss on extinguishment of debt	—			8,676
Stock-based compensation expense, net	4,115			3,518
Deferred income tax (benefit) expense	(179,218		)	193
Non-cash interest expense, net	603			662
Other, net	1,364			(2,689		)
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(4,309		)	10,738
Accounts payable	(14,385		)	15,526
Accrued liabilities	10,568			(4,317		)
Other assets and liabilities, net	(966		)	(773		)
Net cash provided by operating activities	125,103			138,724
Cash Flows From Investing Activities
Capital expenditures	(171,042		)	(234,685		)
Acquisitions of oil and gas properties	8,222			—
Proceeds from divestitures of oil and gas properties	3,107			342,359
Other, net	(880		)	(87		)
Net cash provided by (used in) investing activities	(160,593		)	107,587
Cash Flows From Financing Activities
Redemptions of senior notes	—			(326,010		)
Redemption of preferred stock	—			(50,030		)
Borrowings under credit agreement	470,632			694,260
Repayments of borrowings under credit agreement	(389,920		)	(563,860		)
Payments of credit facility amendment fees	(613		)	(150		)
Payments of dividends on preferred stock	(4,360		)	(4,863		)
Cash paid for settlements of contingent consideration arrangements, net	(40,000		)	—
Other, net	(358		)	(313		)
Net cash provided by (used in) financing activities	35,381			(250,966		)
Net Decrease in Cash and Cash Equivalents	(109		)	(4,655		)
Cash and Cash Equivalents, Beginning of Period	2,282			9,540
Cash and Cash Equivalents, End of Period		$2,173			$4,885

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 natural 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.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

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. 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.

Significant Accounting Policies

The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 2018 Annual Report.

Recently Adopted Accounting Standards

Leases. Effective January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842) (“ASC 842”), using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 significantly changes accounting for leases by requiring that lessees recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions. However, ASC 842 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Upon adoption, the Company implemented policy elections and practical expedients which include the following:

• package of practical expedients which allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance;

• excluding ROU assets and lease liabilities for leases with terms that are less than one year;

• combining lease and non-lease components and accounting for them as a single lease (elected by asset class);

• excluding land easements that existed or expired prior to adoption; and

• policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.

As a result of adopting ASC 842, the Company recorded lease liabilities of approximately $75.2 million and associated ROU assets of approximately $69.1 million on its consolidated balance sheets. The difference between the lease liabilities and ROU assets is due to a rent holiday and lease build-out incentives that were recorded as deferred lease liabilities under legacy lease accounting guidance. The adoption of ASC 842 did not materially change the Company’s consolidated statements of income or consolidated statements of cash flows. See “Note 5. Leases” for further discussion.

Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued. See “Note 15. Subsequent Events” for further discussion.

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3. Acquisitions and Divestitures of Oil and Gas Properties

2019 Acquisitions and Divestitures

The Company did not have any material acquisitions or divestitures for the three months ended March 31,2019.

2018 Acquisitions and Divestitures

Devon Acquisition. On August 13, 2018, the Company entered into a purchase and sale agreement with Devon Energy Production Company, L.P. (“Devon”), a subsidiary of Devon Energy Corporation, to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas (the “Devon Properties”) for an agreed upon price of $215.0 million, with an effective date of April 1, 2018, subject to customary purchase price adjustments (the “Devon Acquisition”). The Company paid $21.5 million as a deposit on August 13, 2018, $183.4 million upon initial closing on October 17, 2018, and received $8.3 million as a post-closing adjustment on March 28, 2019, for an aggregate purchase price of $196.6 million.

The Devon 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. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Preliminary Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$216
Oil and gas properties
Proved properties	47,118
Unproved properties	150,253
Total oil and gas properties		$197,587
Total assets acquired		$197,587
Liabilities
Revenues and royalties payable		$786
Asset retirement obligations	170
Total liabilities assumed		$956
Net Assets Acquired		$196,631

Included in the consolidated statements of income for the three months ended March 31,2019 are total revenues of $4.4 million and net income attributable to common shareholders of $2.7 million from the Devon Acquisition.

Eagle Ford Divestiture. On December 11, 2017, the Company entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of its assets in the Eagle Ford Shale for an agreed upon price of $245.0 million, with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. The Company received $24.5 million as a deposit on December 11, 2017, $211.7 million upon closing on January 31, 2018, $10.0 million for leases that were not conveyed at closing on February 16, 2018, and paid $0.5 million as a post-closing adjustment on July 19, 2018, for aggregate net proceeds of $245.7 million.

Niobrara Divestiture.On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. The Company received $14.0 million as a deposit on November 20, 2017, $122.6 million upon closing on January 19, 2018, and paid $1.0 million as a post-closing adjustment on August 14, 2018, for aggregate net proceeds of $135.6 million. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. See “Note 12. Derivative Instruments” and “Note 13. Fair Value Measurements” for further discussion.

The aggregate net proceeds for each of the 2018 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized.

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4. Property and Equipment, Net

As of March 31, 2019 and December 31, 2018, total property and equipment, net consisted of the following:

	March 31, 2019			December 31, 2018
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$6,533,028			$6,278,321
Accumulated depreciation, depletion and amortization and impairments	(4,018,850		)	(3,944,851		)
Proved properties, net	2,514,178			2,333,470
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	595,217			608,830
Capitalized interest	70,740			65,003
Total unproved properties, not being amortized	665,957			673,833
Other property and equipment	30,550			29,191
Accumulated depreciation	(18,670		)	(17,970		)
Other property and equipment, net	11,880			11,221
Total property and equipment, net		$3,192,015			$3,018,524

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $13.27 and $13.73 for the three months ended March 31,2019 and 2018.

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration, and development activities totaling $9.1 million and $6.6 million for the three months ended March 31,2019 and 2018.

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 $9.0 million and $10.4 million for the three months ended March 31,2019 and 2018.

5. Leases

The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.

Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.

Types of Leases

The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.

Drilling Rigs. The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.

Office Space. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years. The Company has determined that it cannot conclude with reasonable

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certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative, net” in its consolidated statements of income.

Well Equipment. The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating expense” in the Company’s statements of income.

The tables below, which present the components of lease costs, supplemental balance sheet information, and supplemental cash flow information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.

The table below presents the components of the Company’s lease costs for the three months ended March 31,2019.

	Three Months Ended March 31, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs
Amortization of right-of-use assets (1)		$374
Interest on lease liabilities (2)	145
Operating lease costs (3)	14,080
Short-term lease costs (4)	218
Variable lease costs (5)	102
Total lease costs		$14,919

(1) Included as a component of “Depletion, depreciation and amortization” in the consolidated statements of income.

(2) Included as a component of “Interest expense, net” in the consolidated statements of income.

(3) Approximately $11.5 million are costs associated with drilling rigs and are capitalized to “Oil and gas properties” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative, net” and “Lease operating expense” in the consolidated statements of income.

(4) Short-term lease costs are primarily associated with certain well equipment that have lease terms for less than one year and are components of “Lease operating expense” in the consolidated statements of income.

(5) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.

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The table below presents supplemental balance sheet information for the Company’s leases as of March 31, 2019.

	March 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$71,965
Current operating lease liabilities		$35,543
Long-term operating lease liabilities	42,468
Total operating lease liabilities		$78,011
Financing leases:
Other property and equipment, at cost		$7,810
Accumulated depreciation	(4,759		)
Other property and equipment, net		$3,051
Current financing lease liabilities (1)		$1,829
Long-term financing lease liabilities (2)	1,549
Total financing lease liabilities		$3,378

(1) Included in “Other current liabilities” in the consolidated balance sheets.

(2) Included in “Other long-term liabilities” in the consolidated balance sheets.

The table below presents supplemental cash flow information for the Company’s leases for the three months ended March 31,2019.

	Three Months Ended March 31, 2019
	(In thousands)
Supplemental Cash Flow Information
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$2,575
Investing cash flows from operating leases		$13,596
Operating cash flows from financing leases		$145
Financing cash flows from financing leases		$453
ROU assets obtained in exchange for lease liabilities
Operating leases		$11,153
Financing leases		$1,082

The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of March 31, 2019.

	March 31, 2019
Weighted Average Remaining Lease Term (In years)
Operating leases	4.5 years
Financing leases	2.4 years
Weighted Average Discount Rate
Operating leases	8.0	%
Financing leases	13.8	%

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The table below presents the maturity of the Company’s lease liabilities as of March 31, 2019.

	Operating Leases			Financing Leases
	(In thousands)
April - December 2019		$30,983			$1,669
2020	27,098			1,475
2021	7,355			275
2022	3,645			234
2023	3,680			233
2024 and Thereafter	21,499			39
Total lease payments	94,260			3,925
Less: Imputed interest	(16,249		)	(547		)
Total lease liabilities		$78,011			$3,378

6. 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, excluding significant unusual or infrequent items, the tax effects of statutory rate changes, certain changes in the assessment of the realizability of deferred tax assets, and excess tax benefits or deficiencies related to the vesting of stock-based compensation awards, which are recognized as discrete items in the interim period in which they occur.

The Company’s income tax (expense) benefit differed from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 21% for the three months ended March 31, 2019 and 2018, to income (loss) before income taxes as follows:

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Income (loss) before income taxes		($28,032	)		$27,811
Income tax (expense) benefit at the U.S. federal statutory rate	5,887			(5,840		)
State income tax (expense) benefit, net of U.S. federal income tax benefit	248			(319		)
Tax deficiencies related to stock-based compensation	(1,938		)	(2,526		)
Release of valuation allowance	179,146			—
(Increase) decrease in valuation allowance due to current period activity	(3,938		)	8,401
Other	(10		)	(35		)
Income tax (expense) benefit		$179,395			($319	)

Deferred Tax Asset Valuation Allowance

The deferred tax asset valuation allowance was $67.7 million and $242.9 million as of March 31, 2019 and December 31, 2018, respectively. Throughout 2018, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016. As of March 31, 2019, the Company is in a cumulative pre-tax income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and future years, the Company concluded that it is more likely than not that the deferred tax assets would be realized and released $179.1 million of the valuation allowance, which is recognized as an increase in deferred tax assets and an income tax benefit for the three months ended March 31, 2019.

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7. Long-Term Debt

Long-term debt consisted of the following as of March 31, 2019 and December 31, 2018:

	March 31, 2019			December 31, 2018
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$825,143			$744,431
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(6,532		)	(6,878		)
8.25% Senior Notes due 2025	250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(3,847		)	(3,962		)
Long-term debt		$1,714,764			$1,633,591

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of March 31, 2019, had a borrowing base of $1.35 billion, with an elected commitment amount of $1.25 billion, and borrowings outstanding of $825.1 million at a weighted average interest rate of 4.18%. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022, 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 March 27, 2019, the Company entered into the fourteenth amendment to its credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at $1.35 billion, with an elected commitment amount of $1.25 billion, until the next redetermination thereof, (ii) amend the definition of Current Ratio, and (iii) amend certain other definitions and provisions.

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

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

Ratio of Outstanding Borrowings to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	0.25%	1.25%	0.375%
Greater than or equal to 25% but less than 50%	0.50%	1.50%	0.375%
Greater than or equal to 50% but less than 75%	0.75%	1.75%	0.500%
Greater than or equal to 75% but less than 90%	1.00%	2.00%	0.500%
Greater than or equal to 90%	1.25%	2.25%	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 issuance costs and is net of cash and cash equivalents, EBITDA is calculated based on the last four fiscal quarters 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 and excludes the Contingent ExL Consideration, which is described in “Note 12. Derivative Instruments.” As of March 31, 2019, the ratio of Total Debt to EBITDA was 2.40 to 1.00 and the Current Ratio was 1.58 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

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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

During the first quarter of 2018, the Company redeemed $320.0 million of the outstanding aggregate principal amount of its 7.50% Senior Notes at a price equal to 101.875% of par. The Company paid a total of $336.9 million upon the redemptions, which included redemption premiums of $6.0 million and accrued and unpaid interest of $10.9 million. The redemptions were funded primarily from the net proceeds received from the divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of these divestitures. As a result of the redemptions, the Company recorded a loss on extinguishment of debt of $8.7 million, which included the redemption premiums of $6.0 million and the write-off of associated unamortized premiums and debt issuance costs of $2.7 million.

Subsidiary Guarantors

The Company’s Senior Notes are guaranteed by its subsidiary guarantors, which are all 100% owned by the parent company. The guarantees are full and unconditional and joint and several. Carrizo Oil & Gas, Inc., as the parent company, has no independent assets and operations. Any subsidiaries of the parent company, other than the subsidiary guarantors, are minor. In addition, there are no significant restrictions on the ability of the parent company or any guarantor to obtain funds from its subsidiaries by dividend or loan.

8. 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, tax changes, 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.

9. Preferred Stock and Common Stock 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 Preferred Stock is presented as temporary equity in the consolidated balance sheets with the issuance date fair value accreted to the initial liquidation preference using the effective interest method. The Warrants are presented in “Additional paid-in capital” in the consolidated balance sheets at their issuance date fair value.

See “Note 9. Preferred Stock and Common Stock Warrants” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for details of the Company’s redemption options and the rights of the holders of the Preferred Stock.

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 a portion of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any preferred stock dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending:

Period	Percentage
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.

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The table below sets forth a reconciliation of changes in the carrying amount of Preferred Stock for the three months ended March 31,2019 and 2018.

	Three Months Ended March 31,
	2019		2018
	(In thousands)
Preferred Stock, beginning of period		$174,422		$214,262
Redemption of Preferred Stock	—		(42,897		)
Accretion on Preferred Stock	801		753
Preferred Stock, end of period		$175,223		$172,118

Loss on Redemption of 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.

During the first quarter of 2018, the Company redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million redemption price and accrued and unpaid dividends of $0.5 million. The Company recognized a $7.1 million loss on the redemption due to the excess of the $50.0 million redemption price over the $42.9 million redemption date carrying value of the Preferred Stock.

10. Stock-Based Compensation

As of March 31, 2019, there were 152,724 shares of common stock available for grant under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (“2017 Incentive Plan”). The Company has not granted stock appreciation rights to be settled in shares of common stock and has no outstanding stock options. See “Note 11. Stock-Based Compensation” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for details of the Company’s equity-based incentive plans.

Restricted Stock Awards and Units

The table below summarizes restricted stock award and unit activity for the three months ended March 31,2019 and 2018:

	Three Months Ended March 31,
	2019				2018
	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
Unvested, beginning of period	2,266,667			$19.28	1,482,655			$28.07
Granted	1,918,683			$11.01	1,347,165			$14.68
Vested	(851,456	)		$20.64	(564,912	)		$31.87
Forfeited	(13,834	)		$17.16	(1,078	)		$29.61
Unvested, end of period	3,320,060			$14.16	2,263,830			$19.15

Grant activity primarily consisted of restricted stock units to employees as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above and vest ratably over an approximate three-year period. The Company currently intends to settle the restricted stock units granted in the first quarter of 2019 in cash upon vesting if the proposed amendment and restatement of the 2017 Incentive Plan is not approved by shareholders at the Company’s annual meeting of shareholders on May 16, 2019. As such, these restricted stock units were accounted for as liability awards. The liability for these restricted stock units as of March 31, 2019 was $0.6 million and was classified as “Other current liabilities” in the consolidated balance sheets. If the amendment and restatement of the 2017 Incentive Plan is approved, the Company intends to settle these restricted stock units in common stock rather than cash upon vesting.

The aggregate fair value of restricted stock awards and units that vested during the three months ended March 31,2019 and 2018 was $9.8 million and $8.9 million, respectively. As of March 31, 2019, unrecognized compensation costs related to unvested restricted stock awards and units were $42.1 million and will be recognized over a weighted average period of 2.4 years. As of March 31, 2018, unrecognized compensation costs related to unvested restricted stock awards and units were $35.0 million to be recognized over a weighted average period of 2.4 years.

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Cash SARs

The table below summarizes the activity for stock appreciation rights that will be settled in cash (“Cash SARs”) for the three months ended March 31,2019 and 2018:

	Three Months Ended March 31,
	2019				2018
	Cash SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Cash SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)
Outstanding, beginning of period	1,330,924		$21.35		714,238		$27.12
Granted	770,775		$10.98		616,686		$14.67
Exercised	—		$—		—		$—
Forfeited	—		$—		—		$—
Expired	—		$—		—		$—
Outstanding, end of period	2,101,699		$17.55	5.1	1,330,924		$21.35	5.1
Vested, end of period	919,800		$24.34		543,018		$27.18
Vested and exercisable, end of period	—		$24.34	3.2	—		$27.18	3.3

Grant activity primarily consisted of Cash SARs to certain employees as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above. The Cash SARs granted in the first quarter of 2019 and 2018 vest ratably over an approximate three-year period and expire approximately seven years from the grant date.

The grant date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model, was $4.6 million and $4.9 million for the three months ended March 31,2019 and 2018. The following table summarizes the assumptions used and the resulting grant date fair value of the Cash SARs granted during the three months ended March 31,2019 and 2018:

	Three Months Ended March 31,
	2019		2018
Expected term (in years)	6.1		6.0
Expected volatility	56.0	%	54.3	%
Risk-free interest rate	2.6	%	2.8	%
Dividend yield	—	%	—	%
Grant date fair value per Cash SAR	$6.00		$7.89

The aggregate intrinsic value of Cash SARs outstanding as of March 31, 2019 and 2018 was $1.1 million and $0.7 million, respectively, and the aggregate intrinsic value of Cash SARs vested and exercisable as of March 31, 2019 and 2018 was zero. The liability for Cash SARs as of March 31, 2019 was $2.5 million, all of which was classified as “Other current liabilities,” in the consolidated balance sheets. As of December 31, 2018, the liability for Cash SARs was $1.8 million, all of which was classified as “Other current liabilities” in the consolidated balance sheets. As of March 31, 2019, unrecognized compensation costs related to unvested Cash SARs were $7.8 million and will be recognized over a weighted average period of 2.7 years. As of March 31, 2018, unrecognized compensation costs related to unvested Cash SARs were $5.8 million to be recognized over a weighted average period of 2.8 years.

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Performance Shares

The table below summarizes performance share activity for the three months ended March 31,2019 and 2018:

	Three Months Ended March 31,
	2019				2018
	Target Performance Shares (1)		Weighted Average Grant Date Fair Value		Target Performance Shares (1)		Weighted Average Grant Date Fair Value
Unvested, beginning of period	182,209			$27.01	144,955			$47.14
Granted	130,302			$14.20	93,771			$19.09
Vested at end of performance period	(31,244	)		$35.71	(49,458	)		$65.51
Did not vest at end of performance period	(10,407	)		$35.71	(7,059	)		$65.51
Forfeited	—			$—	—			$—
Unvested, end of period	270,860			$19.51	182,209			$27.01

(1) The number of performance shares that vest may vary from the number of target performance shares granted depending on the Company’s final TSR ranking for the approximate three-year performance period.

Grant activity primarily consisted of performance shares as part of the annual grant of long-term equity incentive awards to certain employees that occurred in the first quarter of 2019 and 2018. Each performance share represents the right to receive one share of common stock, however, the number of performance shares that 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 following table presents the results of the Company’s final TSR ranking during the performance periods that ended during the three months ended March 31,2019 and 2018:

	Three Months Ended March 31,
	2019		2018
Target performance shares granted	41,651		56,517
Multiplier	75	%	88	%
Performance shares vested	31,244		49,458
Performance shares that did not vest	10,407		7,059
Aggregate fair value of performance shares vested (In thousands)	$357		$768

For the three months ended March 31,2019 and 2018, the grant date fair value of the performance shares, calculated using a Monte Carlo simulation, was $1.9 million and $1.8 million, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance share for the performance shares granted during the three months ended March 31,2019:

	Three Months Ended March 31,
	2019		2018
Number of simulations	500,000		500,000
Expected term (in years)	3.1		3.0
Expected volatility	58.2	%	61.5	%
Risk-free interest rate	2.5	%	2.4	%
Dividend yield	—	%	—	%
Grant date fair value per performance share	$14.20		$19.09

As of March 31, 2019, unrecognized compensation costs related to unvested performance shares were $3.5 million and will be recognized over a weighted average period of 2.3 years. As of March 31, 2018, unrecognized compensation costs related to unvested performance shares were $3.3 million to be recognized over a weighted average period of 2.4 years.

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Stock-Based Compensation Expense, Net

Stock-based compensation expense associated with restricted stock awards and units, Cash SARs, and performance shares, net of amounts capitalized, is included in “General and administrative, net” in the consolidated statements of income. The Company recognized the following stock-based compensation expense, net for the three months ended March 31,2019 and 2018:

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Restricted stock awards and units		$4,823			$5,084
Cash SARs	760			(1,415		)
Performance shares	435			557
	6,018			4,226
Less: amounts capitalized to oil and gas properties	(1,903		)	(708		)
Total stock-based compensation expense, net		$4,115			$3,518

11. Net Income Attributable to Common Shareholders Per Common Share

The following table summarizes the calculation of net income attributable to common shareholders per common share:

	Three Months Ended March 31,
	2019			2018
	(In thousands, except per share amounts)
Net Income		$151,363			$27,492
Dividends on preferred stock	(4,360		)	(4,863		)
Accretion on preferred stock	(801		)	(753		)
Loss on redemption of preferred stock	—			(7,133		)
Net Income Attributable to Common Shareholders		$146,202			$14,743
Basic weighted average common shares outstanding	91,740			81,542
Dilutive effect of restricted stock and performance shares	552			637
Dilutive effect of common stock warrants	—			399
Diluted weighted average common shares outstanding	92,292			82,578
Net Income Attributable to Common Shareholders Per Common Share
Basic		$1.59			$0.18
Diluted		$1.58			$0.18

The computation of diluted net income attributable to common shareholders per common share excluded restricted stock, performance shares and common stock warrants that were anti-dilutive. The following table presents the weighted average anti-dilutive securities for the periods presented:

	Three Months Ended March 31,
	2019	2018
	(In thousands)
Anti-dilutive restricted stock and performance shares	366	98
Anti-dilutive common stock warrants	2,750	—
Total weighted average anti-dilutive securities	3,116	98

12. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. Since the Company derives a significant portion of its revenues from sales of crude oil, crude oil price volatility represents the Company’s most significant commodity price risk.

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While the use of commodity derivative instruments limits or partially reduces the downside risk of adverse commodity price movements, such use also limits the upside from favorable commodity price movements. The Company does not enter into commodity derivative instruments for speculative purposes.

The Company’s commodity derivative instruments, which settle on a monthly basis over the term of the contract for contracted volumes, consist of over-the-counter price swaps, three-way collars, sold call options, and basis swaps, each of which is described below.

Price swaps are settled based on differences between a fixed price and the settlement price of a referenced index. If the settlement price of the referenced index is below the fixed price, the Company receives the difference from the counterparty. If the referenced settlement price is above the fixed price, the Company pays the difference to the counterparty.

Three-way collars consist of a purchased put option (floor price), a sold call option (ceiling price) and a sold put option (sub-floor price) and are settled based on differences between the floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and sub-floor price. If the settlement price of the referenced index is below the sub-floor price, the Company receives the difference between the floor price and sub-floor price from the counterparty. If the settlement price of the referenced index is between the floor price and sub-floor price, the Company receives the difference between the floor price and the settlement price of the referenced index from the counterparty. If the settlement price of the referenced index is between the floor price and ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty.

Sold call options are settled based on differences between the ceiling price and the settlement price of a referenced index. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty. If the settlement price of the referenced index is below the ceiling price, no payments are due to or from either party. Premiums from the sale of call options have been used to enhance the fixed price of certain contemporaneously executed price swaps. Purchased call options executed contemporaneously with sold call options in order to increase the ceiling price of existing sold call options have been presented on a net basis in the table below.

Basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. If the differential between the settlement prices of the two referenced indexes is greater than the fixed price differential, the Company receives the difference from the counterparty. If the differential between the settlement prices of the two referenced indexes is less than the fixed price differential, the Company pays the difference to the counterparty.

The referenced index of the Company’s price swaps, three-way collars, and sold call options is U.S. New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) for crude oil and NYMEX Henry Hub for natural gas, as applicable. The index price the Company receives on its crude oil basis swaps is Argus WTI Cushing (“WTI Cushing”) plus or minus a fixed price differential and the index price it pays is Argus WTI Midland (“WTI Midland”) or Argus Light Louisiana Sweet (“LLS”). The index price the Company receives on its natural gas basis swaps is NYMEX Henry Hub minus a fixed price differential and the index price it pays is Platt’s Inside FERC West Texas Waha (“Waha”).

The Company has incurred premiums on certain of its commodity derivative instruments in order to obtain a higher floor price and/or higher ceiling price. Payment of these premiums are deferred until the applicable contracts settle on a monthly basis over the term of the contract or, in some cases, during the final 12 months of the contract and are referred to as deferred premium obligations.

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As of March 31, 2019, the Company had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:

Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	2Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	2Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	2Q19	Basis Swaps	WTI Midland-WTI Cushing	7,609	—		—		—		—			($4.38	)
Crude oil	2Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—
Crude oil	3Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	3Q19	Basis Swaps	WTI Midland-WTI Cushing	9,100	—		—		—		—			($4.44	)
Crude oil	3Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—
Crude oil	4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)
Crude oil	4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—
Crude oil	2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—
Crude oil	2020	Three-Way Collars	NYMEX WTI	6,000	—			$45.00		$55.00		$64.69	—
Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	10,658	—		—		—		—			($1.68	)
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—
Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	8,000	—		—		—		—			$0.18

Commodity	Period	Type of Contract	Index	Volumes (MMBtu per day)	Fixed Price ($ per MMBtu)	Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)		Fixed Price Differential ($ per MMBtu)
Natural gas	2Q19	Basis Swaps	Waha-NYMEX Henry Hub	14,000	—	—	—	—			($2.12	)
Natural gas	2Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—
Natural gas	3Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.60	)
Natural gas	3Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—
Natural gas	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.05	)
Natural gas	4Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—
Natural gas	2020	Basis Swaps	Waha-NYMEX Henry Hub	25,811	—	—	—	—			($0.71	)
Natural gas	2020	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.50	—

The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods often resulting in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), 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 commodity derivative instruments who are also lenders under the Company’s credit agreement (“Lender Counterparty”) allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the Lender Counterparty with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties to the Company’s commodity derivative instruments who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”) can require commodity derivative instruments to be novated to a Lender Counterparty if the Company’s net liability position exceeds the Company’s unsecured credit limit with the Non-Lender Counterparty and therefore do not require the posting of cash collateral.

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Because each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, 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 commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. As of March 31, 2019, the Company has outstanding commodity derivative instruments with fifteen counterparties to minimize its credit exposure to any individual counterparty.

Contingent Consideration Arrangements

The purchase and sale agreements for the acquisition of properties in the Delaware Basin from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (the “ExL Acquisition”) in 2017 and divestitures of the Company’s assets in the Niobrara in 2018, and Marcellus and Utica in 2017, included contingent consideration arrangements that require the Company to pay or entitle the Company to receive specified amounts if commodity prices exceed specified thresholds, which are summarized in the tables below. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for further discussion of these transactions. See “—Cash received (paid) for settlements of contingent consideration arrangements, net” below for discussion of the settlements that occurred during the first quarter of 2019.

Contingent ExL Consideration

	Year	Threshold (1)		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			Acquisition Date Fair Value			Remaining Contingent Payments - Aggregate Limit
						(In thousands)
										($52,300	)
Actual Settlement	2018		$50.00	1Q19	Financing		($50,000	)
Remaining Potential Settlements	2019-2021	50.00		(2)	(2)	(50,000		)					($75,000	)

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).

(2) Cash paid for settlements of contingent consideration arrangements 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. Therefore, if the commodity price threshold is reached, $2.3 million of the next contingent payment will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent payments, presented in cash flows from operating activities. If the pricing threshold is met, the payment is made and the cash flow occurs, in the first quarter of the following year.

Contingent Niobrara Consideration

	Year	Threshold (1)	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Divestiture Date Fair Value		Remaining Contingent Payments - Aggregate Limit
					(In thousands)
								$7,880
Actual Settlement	2018	$55.00	1Q19	Financing		$5,000				$10,000
Remaining Potential Settlements	2019	55.00	1Q20	(2)	5,000
	2020	60.00	1Q21	(2)	5,000

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. EIA.

(2) If the commodity price threshold is reached, $2.9 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

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Contingent Marcellus Consideration

	Year	Threshold (1)	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Divestiture Date Fair Value		Remaining Contingent Payments - Aggregate Limit
					(In thousands)
								$2,660
Actual Settlement	2018	$3.13	1Q19	N/A		$—				$6,000
Remaining Potential Settlements	2019	3.18	1Q20	(2)	3,000
	2020	3.30	1Q21	(2)	3,000

(1) The price used to determine whether the specified threshold for each year has been met is the average monthly settlement price per MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc.

(2) For the three months ended March 31,2019, there was no settlement for the Contingent Marcellus Consideration. Therefore, if the commodity price threshold is reached, $2.7 million of the contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

Contingent Utica Consideration

	Year	Threshold (1)	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Divestiture Date Fair Value		Remaining Contingent Payments - Aggregate Limit
					(In thousands)
								$6,145
Actual Settlement	2018	$50.00	1Q19	Financing		$5,000				$10,000
Remaining Potential Settlements	2019	53.00	1Q20	(2)	5,000
	2020	56.00	1Q21	(2)	5,000

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. EIA.

(2) If the commodity price threshold is reached, $1.1 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

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Derivative Assets and Liabilities

The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of March 31, 2019 and December 31, 2018 are summarized below:

	March 31, 2019
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$11,513			($8,208	)		$3,305
Contingent Niobrara Consideration	3,409			—			3,409
Contingent Marcellus Consideration	218			—			218
Contingent Utica Consideration	3,926			—			3,926
Derivative assets		$19,066			($8,208	)		$10,858
Commodity derivative instruments	4,271			(4,173		)	98
Contingent Niobrara Consideration	1,803			—			1,803
Contingent Marcellus Consideration	670			—			670
Contingent Utica Consideration	2,279			—			2,279
Other long-term assets		$9,023			($4,173	)		$4,850
Commodity derivative instruments		($30,843	)		($1,113	)		($31,956	)
Deferred premium obligations	(9,321		)	9,321			—
Contingent ExL Consideration	(44,038		)	—			(44,038		)
Derivative liabilities-current		($84,202	)		$8,208			($75,994	)
Commodity derivative instruments	(14,884		)	1,702			(13,182		)
Deferred premium obligations	(2,471		)	2,471			—
Contingent ExL Consideration	(15,545		)	—			(15,545		)
Other long-term liabilities		($32,900	)		$4,173			($28,727	)

	December 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		$50,406			($20,502	)		$29,904
Contingent Niobrara Consideration	5,000			—			5,000
Contingent Utica Consideration	5,000			—			5,000
Derivative assets		$60,406			($20,502	)		$39,904
Commodity derivative instruments	6,083			(4,236		)	1,847
Contingent Niobrara Consideration	2,035			—			2,035
Contingent Marcellus Consideration	1,369			—			1,369
Contingent Utica Consideration	2,501			—			2,501
Other long-term assets		$11,988			($4,236	)		$7,752
Commodity derivative instruments		($15,345	)		$10,140			($5,205	)
Deferred premium obligations	(10,362		)	10,362			—
Contingent ExL Consideration	(50,000		)	—			(50,000		)
Derivative liabilities-current		($75,707	)		$20,502			($55,205	)
Commodity derivative instruments	(10,751		)	518			(10,233		)
Deferred premium obligations	(3,718		)	3,718			—
Contingent ExL Consideration	(30,584		)	—			(30,584		)
Other long-term liabilities		($45,053	)		$4,236			($40,817	)

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See “Note 13. Fair Value Measurements” for additional information regarding the fair value of the Company’s derivative instruments.

(Gain) loss on derivatives, net

The components of “Loss on derivatives, net” in the consolidated statements of income for the three months ended March 31,2019 and 2018 are summarized below:

	Three Months Ended March 31,
	2019			2018
	(In thousands)
(Gain) loss on derivatives, net
Crude oil		$62,761			$29,511
NGL	(6		)	(1,765		)
Natural gas	(2,070		)	(3,045		)
Contingent ExL Consideration	28,999			5,830
Contingent Niobrara Consideration	(3,177		)	(385		)
Contingent Marcellus Consideration	481			470
Contingent Utica Consideration	(3,704		)	(1,020		)
Loss on derivatives, net		$83,284			$29,596

Cash received (paid) for derivative settlements, net

For the three months ended March 31,2019, the Company paid $50.0 million from the first annual settlement of the Contingent ExL Consideration and received $10.0 million from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. The cash paid and received for those contingent consideration settlements are classified as cash flows from financing activities as each of the settlements were less than their respective acquisition or divestiture date fair values. For the three months ended March 31,2018, there were no settlements of contingent consideration arrangements.

The components of “Cash paid for derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” in the consolidated statements of cash flows for the three months ended March 31,2019 and 2018 are summarized below:

	Three Months Ended March 31,
	2019			2018
Cash Flows From Operating Activities	(In thousands)
Cash received (paid) for commodity derivative settlements, net
Crude oil		($320	)		($12,123	)
NGL	623			(432		)
Natural gas	(300		)	52
Deferred premium obligations	(2,641		)	(1,862		)
Cash paid for commodity derivative settlements, net		($2,638	)		($14,365	)
Cash Flows From Financing Activities
Cash received (paid) for settlements of contingent consideration arrangements, net
Contingent ExL Consideration		($50,000	)		$—
Contingent Niobrara Consideration	5,000			—
Contingent Utica Consideration	5,000			—
Cash paid for settlements of contingent consideration arrangements, net		($40,000	)		$—

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13. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s derivative instrument assets and liabilities measured at fair value on a recurring basis as of March 31, 2019 and December 31, 2018:

	March 31, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$3,403			$—
Contingent Niobrara Consideration	—		5,212			—
Contingent Marcellus Consideration	—		888			—
Contingent Utica Consideration	—		6,205			—
Liabilities
Commodity derivative instruments		$—		($45,138	)		$—
Contingent ExL Consideration	—		(59,583		)	—

	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$31,751			$—
Contingent Niobrara Consideration	—		7,035			—
Contingent Marcellus Consideration	—		1,369			—
Contingent Utica Consideration	—		7,501			—
Liabilities
Commodity derivative instruments		$—		($15,438	)		$—
Contingent ExL Consideration	—		(80,584		)	—

The 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 commodity derivative assets and the Company’s credit quality for commodity derivative liabilities.

Contingent consideration arrangements. The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors, and risk adjusted discount rates, which include adjustments for the counterparties’ credit quality for contingent consideration assets and the Company’s credit quality for the contingent consideration liability. These inputs are substantially

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observable in active markets throughout the full term of the contingent consideration arrangements or can be derived from observable data and are therefore designated as Level 2 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

See “Note 12. Derivative Instruments” for additional information regarding the contingent consideration arrangements.

The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the three months ended March 31,2019.

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

The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured as of the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include forward oil and gas price curves, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs, and a risk adjusted discount rate. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for additional discussion.

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 within the valuation hierarchy. 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.

The fair value measurements of the Preferred Stock are measured as of the issuance date by a third-party valuation specialist 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 valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt. 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 principal amounts of the Company’s senior notes and other long-term debt with the fair values measured using quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy. See “Note 7. Long-Term Debt” for additional discussion.

	March 31, 2019				December 31, 2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)
6.25% Senior Notes due 2023		$650,000		$639,438		$650,000		$599,625
8.25% Senior Notes due 2025	250,000		258,750		250,000		244,375

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14. Supplemental Cash Flow Information

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

	Three Months Ended March 31,
	2019		2018
	(In thousands)
Operating activities:
Cash paid for interest, net of amounts capitalized		$16,451		$14,855
Investing activities:
Increase (decrease) in capital expenditure payables and accruals		$74,666		($9,677	)
Supplemental non-cash investing activities:
Fair value of contingent consideration assets on date of divestiture		$—		($7,880	)
Stock-based compensation expense capitalized to oil and gas properties	1,903		708
Asset retirement obligations capitalized to oil and gas properties	3,226		142
Supplemental non-cash financing activities:
Non-cash loss on extinguishment of debt, net		$—		$2,666

15. Subsequent Events

Commodity Derivative Instruments

In April 2019, the Company entered into the following commodity derivative instruments at weighted average contract volumes and prices:

Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	2Q19	Price Swaps	NYMEX WTI	3,352		$64.80	—		—		—		—
Crude oil	3Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	2020	Three-Way Collars	NYMEX WTI	6,000	—			$46.25		$56.25		$67.39	—

Commodity	Period	Type of Contract	Index	Volumes (MMBtu per day)	Fixed Price ($ per MMBtu)	Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)	Fixed Price Differential ($ per MMBtu)
Natural gas	2Q20	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—		($1.25	)

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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 2018 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 2019 Highlights

• Total production for the three months ended March 31,2019 was 61,960 Boe/d, an increase of 21% from the three months ended March 31,2018, primarily due to production from new wells in the Eagle Ford and Delaware Basin, partially offset by normal production decline.

• Operated drilling and completion activity for the three months ended March 31, 2019 along with our drilled but uncompleted and producing wells as of March 31, 2019 are summarized in the table below.

	Three Months Ended March 31, 2019				March 31, 2019
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	27	24.1	32	31.8	41	38.0	553	495.5
Delaware Basin	8	7.5	11	9.0	9	8.2	84	72.9
Total	35	31.6	43	40.8	50	46.2	637	568.4

• Drilling and completion expenditures for the first quarter of 2019 were $214.7 million, of which approximately 63% were in the Eagle Ford with the balance in the Delaware Basin. As of March 31, 2019, we were operating three rigs, with one located in the Eagle Ford and two located in the Delaware Basin. For the remainder of 2019, we currently expect to operate an average of three to four rigs between the Eagle Ford and Delaware Basin. Our current 2019 drilling, completion, and infrastructure (“DC&I”) capital expenditure plan remains unchanged at $525.0 million to $575.0 million. See “—Liquidity and Capital Resources—2019 DC&I Capital Expenditure Plan and Funding Strategy” for additional details.

• In January 2019, we paid $50.0 million as a result of the first annual settlement of the Contingent ExL Consideration and received $10.0 million from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. See “Note 12. Derivative Instruments” for further discussion.

• In March 2019, we entered into the fourteenth amendment to our credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at $1.35 billion, with an elected commitment amount of $1.25 billion, until the next redetermination thereof, (ii) amend the definition of Current Ratio, and (iii) amend certain other definitions and provisions.

• We recorded net income attributable to common shareholders for the three months ended March 31, 2019 of $146.2 million, or $1.58 per diluted share, as compared to net income attributable to common shareholders for the three months ended March 31, 2018 of $14.7 million, or $0.18 per diluted share. The increase in net income attributable to common shareholders was driven primarily by an income tax benefit of approximately $179.4 million as a result of a release of a substantial portion of our deferred tax asset valuation allowance during the first quarter of 2019, partially offset by a $53.7 million increase in our loss on derivatives, net to $83.3 million for the first quarter of 2019 as compared to $29.6 million for the first quarter of 2018. See “—Results of Operations” below for further details.

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Results of Operations

Comparison of Results Between The Three Months Ended March 31,2019 and 2018

Production volumes

The following table summarizes total production volumes and daily production volumes for the periods indicated:

	Three Months Ended March 31,		Amount Change Between Periods		Percent Change Between Periods
	2019	2018
Total production volumes
Crude oil (MBbls)	3,665	3,072	593		19	%
NGLs (MBbls)	891	739	152		21	%
Natural gas (MMcf)	6,118	4,810	1,308		27	%
Total barrels of oil equivalent (MBoe)	5,576	4,613	963		21	%
Daily production volumes by product
Crude oil (Bbls/d)	40,727	34,136	6,591		19	%
NGLs (Bbls/d)	9,903	8,213	1,690		21	%
Natural gas (Mcf/d)	67,977	53,446	14,531		27	%
Total barrels of oil equivalent (Boe/d)	61,960	51,257	10,703		21	%
Daily production volumes by region (Boe/d)
Eagle Ford	39,533	35,623	3,910		11	%
Delaware Basin	22,427	15,235	7,192		47	%
Other	—	399	(399	)	(100	%)
Total barrels of oil equivalent (Boe/d)	61,960	51,257	10,703		21	%

The increase in production volumes is primarily due to production from new wells in the Eagle Ford and Delaware Basin, partially offset by normal production decline.

Average realized prices and revenues

The following table summarizes average realized prices and revenues for the periods indicated:

	Three Months Ended March 31,				Amount Change Between Periods			Percent Change Between Periods
	2019		2018
Average realized prices
Crude oil ($ per Bbl)		$55.32		$63.45		($8.13	)	(13	%)
NGLs ($ per Bbl)	18.90		22.87		(3.97		)	(17	%)
Natural gas ($ per Mcf)	2.20		2.80		(0.60		)	(21	%)
Total average realized price ($ per Boe)		$41.79		$48.84		($7.05	)	(14	%)
Revenues (In thousands)
Crude oil		$202,744		$194,919		$7,825		4	%
NGLs	16,837		16,902		(65		)	—	%
Natural gas	13,459		13,459		—			—	%
Total revenues		$233,040		$225,280		$7,760		3	%

The increase in revenues is primarily due to higher crude oil and NGL production, partially offset by lower crude oil and NGL prices.

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Lease operating expense

The following table summarizes lease operating expense for the periods indicated:

	Three Months Ended March 31,
	2019				2018
	(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe
Lease operating expense		$42,031		$7.54		$39,273		$8.51

The increase in lease operating expenses is primarily due to costs associated with increased production. The decrease in lease operating expense per Boe is primarily due to the divestiture in the Eagle Ford in the first quarter of 2018, which carried higher per Boe operating expenses as compared to our remaining Eagle Ford properties, as well as an increased proportion of production from wells drilled on properties acquired in the ExL Acquisition, which have lower operating costs per Boe than our other Delaware Basin and Eagle Ford properties.

Production and ad valorem taxes

The following table summarizes production and ad valorem taxes for the periods indicated:

	Three Months Ended March 31,
	2019				2018
	(In thousands, except % of revenues amounts)
	Amount		% of Revenues		Amount		% of Revenues
Production and ad valorem taxes		$14,894	6.4	%		$12,548	5.6	%

The increase in production and ad valorem taxes, as well as the increase of production and ad valorem taxes as a percent of revenues, is primarily due to increased ad valorem taxes as a result of new wells drilled in the Eagle Ford and Delaware Basin and higher property tax valuations as a result of the increase in crude oil prices during 2018.

Depreciation, depletion and amortization

The following table sets forth the components of our depreciation, depletion and amortization (“DD&A”) expense for the periods indicated:

	Three Months Ended March 31,
	2019				2018
	(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe
DD&A of proved oil and gas properties		$74,000		$13.27		$63,331		$13.73
Depreciation of other property and equipment	699		0.13		580		0.13
Amortization of other assets	221		0.04		234		0.05
Accretion of asset retirement obligations	402		0.07		322		0.07
DD&A		$75,322		$13.51		$64,467		$13.98

DD&A expense for the three months ended March 31,2019 increased $10.9 million compared to the three months ended March 31,2018. The increase in DD&A expense is attributable to increased production, partially offset by the decrease in the DD&A rate per Boe. The decrease in the DD&A rate per Boe is due primarily to an increased proportion of proved oil and gas reserves in the Delaware Basin, as well as decreased future development costs in Eagle Ford and the Delaware Basin that occurred subsequent to the first quarter of 2018.

General and administrative expense, net

The following table summarizes general and administrative expense, net for the periods indicated:

	Three Months Ended March 31,
	2019		2018
	(In thousands)
General and administrative expense, net		$24,732		$27,292

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The decrease in general and administrative expense, net was primarily due to lower annual bonuses awarded in the first quarter of 2019 as compared to the first quarter of 2018, partially offset by an increase in stock-based compensation expense, net as a result of an increase in the fair value of Cash SARs for the three months ended March 31, 2019 as compared to a decrease in fair value for the same period in 2018.

(Gain) loss on derivatives, net

The following table sets forth the components of our loss on derivatives, net for the periods indicated:

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Crude oil derivative instruments		$62,761			$29,511
NGL derivative instruments	(6		)	(1,765		)
Natural gas derivative instruments	(2,070		)	(3,045		)
Contingent consideration arrangements	22,599			4,895
Loss on derivatives, net		$83,284			$29,596

The loss on derivatives, net for the three months ended March 31,2019 was primarily due to the upward shift in the futures curve of forecasted crude oil prices from January 1, 2019 to March 31, 2019 on crude oil derivative instruments outstanding at the beginning of 2019 and on our Contingent ExL Consideration.

The loss on derivatives, net for the three months ended March 31,2018 was primarily due to the upward shift in the futures curve of forecasted crude oil prices from January 1, 2018 to March 31, 2018 on crude oil derivative instruments outstanding at the beginning of 2018 and on our Contingent ExL Consideration.

Interest expense, net

The following table sets forth the components of our interest expense, net for the periods indicated:

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Interest expense on Senior Notes		$15,313			$21,486
Interest expense on revolving credit facility	9,054			3,158
Amortization of premiums and debt issuance costs	932			1,104
Other interest expense	145			137
Interest capitalized	(8,993		)	(10,368		)
Interest expense, net		$16,451			$15,517

The increase in interest expense, net was primarily due to increased borrowings and associated interest expense on our revolving credit facility for the three months ended March 31,2019 as compared to the three months ended March 31,2018 as well as the decrease in capitalized interest as a result of a lower weighted average interest rate driven by the higher proportion of borrowings on our revolving credit facility, which carries a lower interest rate than the Senior Notes. The increase was partially offset by reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the first and fourth quarters of 2018.

Loss on extinguishment of debt

As a result of our redemptions of $320.0 million of the outstanding aggregate principal amount of our 7.50% Senior Notes in the first quarter of 2018, we recorded a loss on extinguishment of debt of $8.7 million, which included redemption premiums of $6.0 million paid to redeem the notes and non-cash charges of $2.7 million attributable to the write-off of associated unamortized premiums and debt issuance costs.

Income taxes and deferred tax assets valuation allowance

For the first quarter of 2019, we recognized an income tax benefit of $179.4 million as a result of determining that it was more likely than not that our deferred tax assets would be realized after considering all available evidence (both positive and negative). A significant item of objective positive evidence considered was the cumulative pre-tax income incurred over the three-year period ended March 31, 2019. As a result, we released $179.1 million of the valuation allowance against our deferred tax assets which resulted in an income tax benefit.

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For the first quarter of 2018, we recognized income tax expense of $0.3 million as a result of maintaining a full valuation allowance against our deferred tax assets based on our conclusion that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended March 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the fourth quarter of 2015 and the first three quarters of 2016, which limited our ability to consider subjective positive evidence, such as its projections of future taxable income.

Dividends on preferred stock

For the three months ended March 31,2019 and 2018, we declared, and paid in cash, dividends of $4.4 million and $4.9 million, respectively, on our Preferred Stock.

Loss on redemption of preferred stock

During the first quarter of 2018, we redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million redemption price and accrued and unpaid dividends of $0.5 million. We recognized a $7.1 million loss on the redemption due to the excess of the $50.0 million redemption price over the $42.9 million redemption date carrying value of the Preferred Stock.

Liquidity and Capital Resources

2019 DC&I Capital Expenditure Plan and Funding Strategy. Our 2019 DC&I capital expenditure plan remains unchanged at $525.0 million to $575.0 million. We currently intend to finance the remainder of our 2019 DC&I 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, 2019:

	Three Months Ended
	March 31, 2019
	(In thousands)
DC&I
Eagle Ford		$134,275
Delaware Basin	80,390
Other	52
Total DC&I	214,717
Leasehold and seismic	9,107
Total capital expenditures (1)		$223,824

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

Sources and Uses of Cash. Our primary use of cash is related to our DC&I capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the three months ended March 31,2019, we funded our capital expenditures primarily 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, 2019, our revolving credit facility had a borrowing base of $1.35 billion, with an elected commitment amount of $1.25 billion, with $901.9 million of borrowings outstanding. 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.

• 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.

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• 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 further details.

Overview of Cash Flow Activities.Net cash provided by operating activities was $125.1 million and $138.7 million for the three months ended March 31,2019 and 2018, respectively. The decrease was driven primarily by an increase in working capital requirements and operating expenses as well as a decrease in revenues as a result of lower crude oil and NGL prices, partially offset by an increase in revenues as a result of higher crude oil and NGL production and a decrease in the net cash paid for derivative settlements.

Net cash used in investing activities was $160.6 million for the three months ended March 31,2019 as compared to net cash provided by investing activities was $107.6 million for the corresponding period in 2018. The change was primarily due to the proceeds we received in the first quarter of 2018 related to the divestitures in Eagle Ford and Niobrara, partially offset by a decrease in cash paid for capital expenditures.

Net cash provided by financing activities was $35.4 million for the three months ended March 31,2019 compared to net cash used in financing activities for the three months ended March 31,2018 of $251.0 million. The change was primarily due to payments for the redemptions of our 7.50% Senior Notes and Preferred Stock during the first quarter of 2018 and decreased borrowings, net of repayments under our revolving credit facility during the first quarter of 2019, partially offset by net cash paid for settlements of contingent consideration arrangements in January 2019.

Liquidity/Cash Flow Outlook. 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, to a lesser extent, 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 “Note 7. Long-Term Debt” and “—Sources and Uses of Cash—Borrowings under revolving credit facility” for further details of our revolving credit facility.

• Contingent consideration arrangements. As part of the ExL Acquisition, as well as in each of the divestitures of our assets in Niobrara, Marcellus, and Utica, we agreed to contingent consideration arrangements, where we will receive or be required to pay certain amounts if commodity prices are greater than specified thresholds. See “Note 12. Derivative Instruments” for further details of each of these contingent consideration arrangements and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for details of the sensitivities to commodity price for each contingent consideration arrangement.

• Commodity derivative instruments. We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow.

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As of May 3, 2019, we had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:

Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	2Q19	Price Swaps	NYMEX WTI	3,352		$64.80	—		—		—		—
Crude oil	2Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	2Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	2Q19	Basis Swaps	WTI Midland-WTI Cushing	7,609	—		—		—		—			($4.38	)
Crude oil	2Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—
Crude oil	3Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	3Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	3Q19	Basis Swaps	WTI Midland-WTI Cushing	9,100	—		—		—		—			($4.44	)
Crude oil	3Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—
Crude oil	4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)
Crude oil	4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—
Crude oil	2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—
Crude oil	2020	Three-Way Collars	NYMEX WTI	12,000	—			$45.63		$55.63		$66.04	—
Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	10,658	—		—		—		—			($1.68	)
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—
Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	8,000	—		—		—		—			$0.18

Commodity	Period	Type of Contract	Index	Volumes (MMBtu per day)	Fixed Price ($ per MMBtu)	Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)		Fixed Price Differential ($ per MMBtu)
Natural gas	2Q19	Basis Swaps	Waha-NYMEX Henry Hub	14,000	—	—	—	—			($2.12	)
Natural gas	2Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—
Natural gas	3Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.60	)
Natural gas	3Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—
Natural gas	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.05	)
Natural gas	4Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—
Natural gas	2020	Basis Swaps	Waha-NYMEX Henry Hub	29,541	—	—	—	—			($0.77	)
Natural gas	2020	Sold Call Options	NYMEX Henry Hub	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 2019 DC&I 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 2019 DC&I capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Based on existing market conditions and our expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from divestitures, securities offerings or borrowings to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings.

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Contractual Obligations

The following table sets forth estimates of our contractual obligations as of March 31, 2019 (in thousands):

	April - December 2019		2020		2021		2022		2023		2024 and Thereafter		Total
Long-term debt (1)		$—		$—		$—		$825,143		$650,000		$250,000		$1,725,143
Cash interest on senior notes (2)	50,938		61,250		61,250		61,250		40,938		41,250		316,876
Cash interest and commitment fees on revolving credit facility (3)	27,501		36,627		36,627		12,616		—		—		113,371
Operating leases - other (4)	7,658		9,359		6,550		3,645		3,680		21,499		52,391
Operating leases - drilling rig contracts (5)	23,325		17,739		805		—		—		—		41,869
Delivery commitments (6)	2,849		2,807		2,487		30		7		19		8,199
Produced water disposal commitments (7)	15,001		20,894		20,898		20,954		10,471		9,769		97,987
Asset retirement obligations and other (8)	4,824		2,542		628		488		432		20,784		29,698
Total Contractual Obligations		$132,096		$151,218		$129,245		$924,126		$705,528		$343,321		$2,385,534

(1) Long-term debt consists of the principal amounts of the 6.25% Senior Notes due 2023, the 8.25% Senior Notes due 2025, and borrowings outstanding under our revolving credit facility which matures in 2022.

(2) Cash interest on senior notes includes cash payments for interest on the 6.25% Senior Notes due 2023 and the 8.25% Senior Notes due 2025.

(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, 2019 of 4.18%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of March 31, 2019, at the applicable commitment fee rate of 0.500%.

(4) Other operating leases include contracts for office space and the use of well equipment, vehicles, and other office equipment. The amounts presented above represent gross contractual obligations. Other joint owners in the properties operated by us generally pay for their working interest share of costs associated with the use of well equipment.

(5) Drilling rig contracts represent gross contractual obligations. Other joint owners in the properties operated by us generally pay for their working interest share of such costs.

(6) 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.

(7) 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.

(8) Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of March 31, 2019. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.

Off Balance Sheet Arrangements

We currently have no off balance sheet arrangements.

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 arrangements, 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 2018 Annual Report. See “Note 9. Preferred Stock and Common Stock Warrants”, “Note 12. Derivative Instruments” and “Note 13. Fair Value Measurements” for details of the Preferred Stock and contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, 2019 cost center ceiling to changes in the 12-month average benchmark crude oil and natural gas prices underlying 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, 2019 and, accordingly, does not consider

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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, 2019 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, 2019 Actual	$60.54	$2.18	$1,184
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$66.83	$2.50	$1,762	$578
Crude Oil and Natural Gas -10%	$54.24	$1.86	$606	($578)
Crude Oil Price Sensitivity
Crude Oil +10%	$66.83	$2.18	$1,708	$524
Crude Oil -10%	$54.24	$2.18	$660	($524)
Natural Gas Price Sensitivity
Natural Gas +10%	$60.54	$2.50	$1,238	$54
Natural Gas -10%	$60.54	$1.86	$1,130	($54)

The price of crude oil, which is the commodity price that our cost center ceiling is most sensitive to, increased slightly during the first quarter of 2019 as compared to year end 2018, however, the 12-Month Average Realized Price as of March 31, 2019 decreased when compared to the 12-Month Average Realized Price as of December 31, 2018. We currently estimate that the 12-Month Average Realized Price of crude oil as of June 30, 2019 will be $62.25, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Utilizing this estimated 12-Month Average Realized Price, we estimate that the second quarter of 2019 cost center ceiling will exceed the net book value, less related deferred income taxes, resulting in no impairment of proved oil and gas properties.

This estimate assumes that all other inputs and assumptions are as of March 31, 2019, other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to March 31, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.

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 deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

For the year ended December 31, 2018, we maintained a full valuation allowance against our deferred tax assets based on our conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016, which limited our ability to consider subjective positive evidence, such as its projections of future taxable income. However, as of March 31, 2019, we are in a cumulative pre-tax income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and future years, concluded that it is more likely than not that the deferred tax assets would be realized. As a result, we released $179.1 million of the valuation allowance, which was recognized as an income tax benefit for the three months ended March 31, 2019.

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We will continue to assess the timing and amount of additional releases of the valuation allowance based on available information each reporting period, such as our projections of future taxable income, and currently anticipate that the remaining valuation allowance will be released by December 31, 2019.

As of March 31, 2019, we have estimated U.S. federal net operating loss carryforwards of $1.1 billion that, if not utilized in earlier periods, will expire between 2026 and 2037. 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 offering associated with the ExL Acquisition in 2017, as well as the common stock offering in August 2018, our calculated ownership change percentage increased. However, as of March 31, 2019, 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.

Recently Adopted and Recently Issued Accounting Pronouncements

See “Note 2. Summary of Significant Accounting Policies” for discussion of the pronouncements we recently adopted.

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;

• the use of commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production;

• anticipated trends in our business;

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

• effects of competition on us;

• our future results of operations;

• profitability of drilling locations;

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

• our planned expenditures, prospects and capital expenditure plan;

• future market conditions in the oil and gas industry;

• our ability to make, integrate and develop acquisitions and realize any expected benefits or effects of any acquisitions or the timing, final purchase price, financing or consummation of any acquisitions;

• results of the Devon Properties;

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• 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;

• our ability to complete planned transactions on desirable terms;

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

• realization and other matters concerning deferred tax assets.

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 commodity 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 redeterminations 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, 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 an 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, 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 2018 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 2018 Annual Report. Except as disclosed below, there have been no material changes from the disclosure made in our 2018 Annual Report regarding our exposure to certain market risks.

Commodity Price Risk

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, NGLs, and natural gas, which are affected by changes in market supply and demand and other factors. The markets for crude oil, NGLs, and natural gas have been volatile, especially over the last several years, and these markets will likely continue to be volatile in the future.

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The following table sets forth our crude oil, NGL, and natural gas revenues for the three months ended March 31,2019 as well as the impact on the crude oil, NGL, and natural gas revenues assuming a 10% increase and decrease in our average realized crude oil, NGL, and natural gas prices, excluding the impact of derivative settlements:  

	Three Months Ended March 31, 2019
	Crude oil		NGLs		Natural gas		Total
	(In thousands)
Revenues		$202,744		$16,837		$13,459		$233,040
Impact of a 10% fluctuation in average realized prices		$20,273		$1,684		$1,346		$23,303

We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not enter into commodity derivative instruments for speculative purposes. As of March 31, 2019, our commodity derivative instruments consisted of price swaps, three-way collars, sold call options, and basis swaps. See “Note 12. Derivative Instruments” and “Note 15. Subsequent Events” for further discussion of our commodity derivative instruments as of March 31, 2019 and our commodity derivative instruments entered into subsequent to March 31, 2019, respectively.

The following table sets forth the cash received (paid) for commodity derivative settlements, net, excluding deferred premium obligations, for the three months ended March 31,2019 as well as the impact on the cash received (paid) for commodity derivative settlements, net assuming a 10% increase and decrease in the respective settlement prices:

	Three Months Ended March 31, 2019
	Crude oil			NGLs			Natural gas			Total
	(In thousands)
Cash received (paid) for commodity derivative settlements, net		($320	)		$623			($300	)		$3
Impact of a 10% increase in settlement prices		($2,575	)		($378	)		($362	)		($3,315	)
Impact of a 10% decrease in settlement prices		$8,854			$378			$300			$9,532

During the three months ended March 31, 2019, we paid $50.0 million as a result of the first annual settlement of the Contingent ExL Consideration and received $10.0 million from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. A 10% increase or decrease in the settlement price would have had no impact on the actual settlements related to our Contingent ExL Consideration, Contingent Niobrara Consideration, and Contingent Utica Consideration. A 10% increase in the settlement price would have resulted in a $3.0 million cash receipt related to our Contingent Marcellus Consideration, while a 10% decrease in the settlement price would have had no impact. See “Note 12. Derivative Instruments” for further details on the cash received (paid) for settlements of contingent consideration arrangements, net.

The primary drivers of our commodity derivative instrument fair values are the underlying forward oil and gas price curves. The following table sets forth the average forward oil and gas price curves as of March 31, 2019 for each of the years in which we have commodity derivative instruments:

	2019	2020	2021
Crude oil:
NYMEX WTI	$60.36	$58.75	$56.32
LLS-WTI Cushing	$4.77	$3.20	$2.83
WTI Midland-WTI Cushing	($0.19)	$0.40	$0.60
Natural gas:
NYMEX Henry Hub	$2.80	$2.74	$2.65
Waha-NYMEX Henry Hub	($1.63)	($0.87)	($0.49)

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The following table sets forth the fair values as of March 31, 2019 of our commodity derivative instruments, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves that are shown above:

	Crude oil			NGLs		Natural gas			Total
	(In thousands)
Fair value liability as of March 31, 2019		($30,313	)		$—		$370			($29,943	)
Impact of a 10% increase in forward commodity prices		($38,340	)		$—		$181			($38,159	)
Impact of a 10% decrease in forward commodity prices		$26,738			$—		($1,013	)		$25,725

The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors and risk adjusted discount rates. See “Note 13. Fair Value Measurements” for further discussion.

The following table sets forth the fair values of the contingent consideration arrangements as of March 31, 2019, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves that are shown above:

	Contingent ExL Consideration			Contingent Niobrara Consideration			Contingent Marcellus Consideration			Contingent Utica Consideration
	(In thousands)
Potential (payment) receipt per year		($50,000	)		$5,000			$3,000			$5,000
Maximum remaining potential (payment) receipt		($75,000	)		$10,000			$6,000			$10,000
Fair value (liability) asset as of March 31, 2019		($59,583	)		$5,212			$888			$6,205
Impact of a 10% increase in forward commodity prices		($4,538	)		$1,477			$877			$1,203
Impact of a 10% decrease in forward commodity prices		$9,910			($1,997	)		($422	)		($1,902	)

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding borrowings on our revolving credit facility. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate 6.25% Senior Notes and 8.25% Senior Notes, but can impact their fair values. As of March 31, 2019, we had approximately $1.7 billion of long-term debt outstanding. Of this amount, approximately $0.9 billion was fixed-rate debt with a weighted average interest rate of 7.22% and approximately $0.8 billion was floating-rate debt on outstanding borrowings on our revolving credit facility with a weighted average interest rate of 4.18%. A 1% increase or decrease in the interest rate on outstanding borrowings on our revolving credit facility would have a corresponding increase or decrease in our interest expense of approximately $2.1 million. See “Note 13. Fair Value Measurements” for further details on the fair value of our 6.25% Senior Notes and 8.25% Senior Notes.

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, 2019 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended March 31, 2019 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

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.

Item 1A. Risk Factors

There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our 2018 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
†10.1		Fourteenth Amendment to Credit Agreement, dated as of March 27, 2019, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 28, 2019).
*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.

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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, 2019	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)
Date:	May 9, 2019	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

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