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 June 30, ~~2018~~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)~~ (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 ¨Yes ☑ 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 ¨Yes ☑ 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~~Accelerated Filer

þ☑

Accelerated ~~filer~~Filer

~~Non-accelerated filer~~☐

Non-accelerated Filer

~~Smaller reporting company~~

¨☐

Smaller reporting company

☐

Emerging growth company

¨☐

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

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

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 August ~~1, 2018~~2, 2019 was ~~82,114,492.~~92,552,930.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of June 30, ~~2018~~2019 and December 31, ~~2017~~2018	2
	Consolidated Statements of Income for the three and six months ended June 30, ~~2018~~2019 and ~~2017~~2018	3
	Consolidated ~~Statement~~Statements of Shareholders’ Equity for the three and six months ended June 30, 2019 and 2018	4
	Consolidated Statements of Cash Flows for the six months ended June 30, ~~2018~~2019 and ~~2017~~2018	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3129
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4540
Item 4.	Controls and Procedures	4642
Part II. Other Information
Item 1.	Legal Proceedings	4743
Item 1A.	Risk Factors	4743
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4746
Item 3.	Defaults Upon Senior Securities	4746
Item 4.	Mine Safety Disclosures	4746
Item 5.	Other Information	47
Item 6.	Exhibits	47
Signatures		48

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)


	June 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents		$2,099			$9,540			$2,282			$2,282
Accounts receivable, net	111,100			107,441			98,444			99,723
Derivative assets	10,928			—			13,621			39,904
Other current assets	8,378			5,897			9,472			8,460
Total current assets	132,505			122,878			123,819			150,369
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,959,951			1,965,347			2,587,341			2,333,470
Unproved properties, not being amortized	597,892			660,287			656,976			673,833
Other property and equipment, net	10,582			10,176			11,188			11,221
Total property and equipment, net	2,568,425			2,635,810			3,255,505			3,018,524
Other assets	20,909			19,616
Deferred income taxes							177,723			—
Operating lease right-of-use assets							64,615			—
Other long-term assets							13,666			16,207
Total Assets		$2,721,839			$2,778,304			$3,635,328			$3,185,100

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$113,651			$74,558			$102,943			$98,811
Revenues and royalties payable	53,280			52,154			54,662			49,003
Accrued capital expenditures	117,934			119,452			74,005			60,004
Accrued interest	21,126			28,362			18,700			18,377
Derivative liabilities	145,520			57,121			64,751			55,205
Operating lease liabilities							34,049			—
Other current liabilities	52,020			41,175			51,430			40,609
Total current liabilities	503,531			372,822			400,540			322,009
Long-term debt	1,502,307			1,629,209			1,731,418			1,633,591
Asset retirement obligations	16,305			23,497			22,111			18,360
Derivative liabilities	87,933			112,332
Operating lease liabilities							36,526			—
Deferred income taxes	4,164			3,635			8,218			8,017
Other liabilities	8,273			51,650
Other long-term liabilities							20,101			47,797
Total liabilities	2,122,513			2,193,145			2,218,914			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 June 30, 2018 and 250,000 issued and outstanding as of December 31, 2017	172,858			214,262
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of June 30, 2019 and December 31, 2018							176,056			174,422
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 82,107,544 issued and outstanding as of June 30, 2018 and 81,454,621 issued and outstanding as of December 31, 2017	821			815
Common stock, $0.01 par value, 180,000,000 shares authorized; 92,552,930 issued and outstanding as of June 30, 2019 and 91,627,738 issued and outstanding as of December 31, 2018							926			916
Additional paid-in capital	1,918,820			1,926,056			2,132,131			2,131,535
Accumulated deficit	(1,493,173		)	(1,555,974		)	(892,699		)	(1,151,547		)
Total shareholders’ equity	426,468			370,897			1,240,358			980,904
Total Liabilities and Shareholders’ Equity		$2,721,839			$2,778,304			$3,635,328			$3,185,100

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

(Unaudited)

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
Revenues
Crude oil
$229,798

$142,806

$424,717

$270,898
Natural gas liquids 21,269
7,786
38,171
15,211
Natural gas 12,906
15,891
26,365
31,729
Total revenues 263,973
166,483
489,253
317,838

Costs and Expenses
Lease operating 35,151
36,048
74,424
65,893
Production taxes 12,487
7,143
23,062
13,351
Ad valorem taxes 3,640
1,073
5,613
4,040
Depreciation, depletion and amortization 72,430
59,072
136,897
113,454
General and administrative, net 18,265
11,596
45,557
33,299
(Gain) loss on derivatives, net 67,714
(26,065 ) 97,310
(51,381 )
Interest expense, net 15,599
21,106
31,116
41,677
Loss on extinguishment of debt —
—
8,676
—
Other expense, net 2,895
204
2,995
1,178
Total costs and expenses 228,181
110,177
425,650
221,511

Income Before Income Taxes 35,792
56,306
63,603
96,327
Income tax expense (483 ) —
(802 ) —
Net Income
$35,309

$56,306

$62,801

$96,327
Dividends on preferred stock (4,474 ) —
(9,337 ) —
Accretion on preferred stock (740 ) —
(1,493 ) —
Loss on redemption of preferred stock —
—
(7,133 ) —
Net Income Attributable to Common Shareholders
$30,095

$56,306

$44,838

$96,327

Net Income Attributable to Common Shareholders Per Common Share
Basic
$0.37

$0.86

$0.55

$1.47
Diluted
$0.36

$0.85

$0.54

$1.46

Weighted Average Common Shares Outstanding
Basic 82,058
65,767
81,802
65,479
Diluted 83,853
65,908
83,240
65,866

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

~~CARRIZO OIL & GAS, INC.~~

~~CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY~~

~~(In thousands, except share amounts)~~

~~(Unaudited)~~

Common Stock Additional
Paid-in
Capital
Accumulated Deficit Total
Shareholders’
Equity
Shares Amount
Balance as of December 31, 2017 81,454,621

$815

$1,926,056

($1,555,974 )
$370,897
Stock-based compensation expense —
—
10,757
—
10,757
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares 652,923
6
(30 ) —
(24 )
Dividends on preferred stock —
—
(9,337 ) —
(9,337 )
Accretion on preferred stock —
—
(1,493 ) —
(1,493 )
Loss on redemption of preferred stock —
—
(7,133 ) —
(7,133 )
Net income —
—
—
62,801
62,801
Balance as of June 30, 2018 82,107,544

$821

$1,918,820

($1,493,173 )
$426,468



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues
Crude oil		$245,212			$229,798			$447,956			$424,717
Natural gas liquids	14,159			21,269			30,996			38,171
Natural gas	5,596			12,906			19,055			26,365
Total revenues	264,967			263,973			498,007			489,253

Costs and Expenses
Lease operating	44,514			35,151			86,545			74,424
Production and ad valorem taxes	17,793			16,127			32,687			28,675
Depreciation, depletion and amortization	80,766			72,430			156,088			136,897
General and administrative, net	17,301			18,265			42,033			45,557
(Gain) loss on derivatives, net	(20,449		)	67,714			62,835			97,310
Interest expense, net	18,024			15,599			34,475			31,116
Loss on extinguishment of debt	—			—			—			8,676
Other (income) expense, net	(2,766		)	2,895			1,592			2,995
Total costs and expenses	155,183			228,181			416,255			425,650

Income Before Income Taxes	109,784			35,792			81,752			63,603
Income tax (expense) benefit	(2,299		)	(483		)	177,096			(802		)
Net Income		$107,485			$35,309			$258,848			$62,801
Dividends on preferred stock	(4,452		)	(4,474		)	(8,812		)	(9,337		)
Accretion on preferred stock	(833		)	(740		)	(1,634		)	(1,493		)
Loss on redemption of preferred stock	—			—			—			(7,133		)
Net Income Attributable to Common Shareholders		$102,200			$30,095			$248,402			$44,838

Net Income Attributable to Common Shareholders Per Common Share
Basic		$1.10			$0.37			$2.70			$0.55
Diluted		$1.10			$0.36			$2.69			$0.54

Weighted Average Common Shares Outstanding
Basic	92,497			82,058			92,121			81,802
Diluted	92,700			83,853			92,479			83,240

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)



	Three Months Ended June 30, 2019 and 2018
	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount		Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of March 31, 2019	92,503,562		$925		$2,130,989			($1,000,184	)		$1,131,730
Stock-based compensation expense	—	—		6,428			—			6,428
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	49,368	1		(1		)	—			—
Dividends on preferred stock	—	—		(4,452		)	—			(4,452		)
Accretion on preferred stock	—	—		(833		)	—			(833		)
Net income	—	—		—			107,485			107,485
Balance as of June 30, 2019	92,552,930		$926		$2,132,131			($892,699	)		$1,240,358

Balance as of March 31, 2018	82,065,561		$821		$1,918,942			($1,528,482	)		$391,281
Stock-based compensation expense	—	—		5,110			—			5,110
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	41,983	—		(18		)	—			(18		)
Dividends on preferred stock	—	—		(4,474		)	—			(4,474		)
Accretion on preferred stock	—	—		(740		)	—			(740		)
Net income	—	—		—			35,309			35,309
Balance as of June 30, 2018	82,107,544		$821		$1,918,820			($1,493,173	)		$426,468



	Six Months Ended June 30, 2019 and 2018
	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount		Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of December 31, 2018	91,627,738		$916		$2,131,535			($1,151,547	)		$980,904
Stock-based compensation expense	—	—		11,052			—			11,052
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	925,192	10		(10		)	—			—
Dividends on preferred stock	—	—		(8,812		)	—			(8,812		)
Accretion on preferred stock	—	—		(1,634		)	—			(1,634		)
Net income	—	—		—			258,848			258,848
Balance as of June 30, 2019	92,552,930		$926		$2,132,131			($892,699	)		$1,240,358

Balance as of December 31, 2017	81,454,621		$815		$1,926,056			($1,555,974	)		$370,897
Stock-based compensation expense	—	—		10,757			—			10,757
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	652,923	6		(30		)	—			(24		)
Dividends on preferred stock	—	—		(9,337		)	—			(9,337		)
Accretion on preferred stock	—	—		(1,493		)	—			(1,493		)
Loss on redemption of preferred stock	—	—		(7,133		)	—			(7,133		)
Net income	—	—		—			62,801			62,801
Balance as of June 30, 2018	82,107,544		$821		$1,918,820			($1,493,173	)		$426,468

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2019			2018
Cash Flows From Operating Activities
Net income		$62,801			$96,327			$258,848			$62,801
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	136,897			113,454			156,088			136,897
(Gain) loss on derivatives, net	97,310			(51,381		)
Cash (paid) received for derivative settlements, net	(38,448		)	1,258
Loss on derivatives, net							62,835			97,310
Cash paid for commodity derivative settlements, net							(7,160		)	(38,448		)
Loss on extinguishment of debt	8,676			—			—			8,676
Stock-based compensation expense, net	10,724			3,596			7,969			10,724
Deferred income taxes	529			—
Deferred income tax (benefit) expense							(177,521		)	529
Non-cash interest expense, net	1,262			2,074			1,271			1,262
Other, net	3,975			2,767			2,079			3,975
Changes in components of working capital and other assets and liabilities-
Accounts receivable	2,437			(8,094		)	(7,824		)	2,437
Accounts payable	3,878			14,486			(6,544		)	3,878
Accrued liabilities	(12,883		)	5,650			12,733			(12,883		)
Other assets and liabilities, net	(1,286		)	(982		)	(978		)	(1,286		)
Net cash provided by operating activities	275,872			179,155			301,796			275,872
Cash Flows From Investing Activities
Capital expenditures	(430,639		)	(290,625		)	(362,478		)	(430,639		)
Acquisitions of oil and gas properties	—			(16,533		)	8,222			—
Deposit for acquisition of oil and gas properties	—			(75,000		)
Proceeds from divestitures of oil and gas properties, net	345,789			18,201
Proceeds from divestitures of oil and gas properties							6,034			345,789
Other, net	(1,096		)	(2,479		)	(38		)	(1,096		)
Net cash used in investing activities	(85,946		)	(366,436		)	(348,260		)	(85,946		)
Cash Flows From Financing Activities
Redemptions of senior notes	(330,435		)	—			—			(330,435		)
Redemption of preferred stock	(50,030		)	—			—			(50,030		)
Borrowings under credit agreement	1,126,856			919,097			898,890			1,126,856
Repayments of borrowings under credit agreement	(933,156		)	(723,797		)	(801,993		)	(933,156		)
Payments of debt issuance costs	(627		)	(4,368		)
Payment of commitment fee for issuance of preferred stock	—			(5,000		)
Payments of credit facility amendment fees							(613		)	(627		)
Payments of dividends on preferred stock	(9,337		)	—			(8,812		)	(9,337		)
Cash paid for settlements of contingent consideration arrangements, net							(40,000		)	—
Other, net	(638		)	(617		)	(1,008		)	(638		)
Net cash provided by (used in) financing activities	(197,367		)	185,315			46,464			(197,367		)
Net Decrease in Cash and Cash Equivalents	(7,441		)	(1,966		)	—			(7,441		)
Cash and Cash Equivalents, Beginning of Period	9,540			4,194			2,282			9,540
Cash and Cash Equivalents, End of Period		$2,099			$2,228			$2,282			$2,099

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

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” or “Carrizo”), 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.

~~Consolidated Financial Statements~~Proposed Merger of the Company with Callon

On July 14, 2019, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Callon Petroleum Company, a Delaware corporation (“Callon”). Pursuant to the Merger Agreement, the Company will be merged with and into Callon, with Callon continuing as the surviving entity (the “Merger”). The Merger was structured as a direct merger with the closing expected to occur in the fourth quarter of 2019.

On and subject to the terms and conditions set forth in the Merger Agreement, upon closing of the Merger, each share of Carrizo’s common stock, par value $0.01 per share, issued and outstanding immediately prior to the effective time of the Merger will automatically be converted into the right to receive 2.05 shares of Callon’s common stock, par value $0.01 per share (the “Exchange Ratio”). Callon’s common stock is listed and traded on the New York Stock Exchange (the “NYSE”) under the ticker symbol CPE. Pursuant to the Merger Agreement, three members of the Company’s board of directors will become directors of Callon immediately after the effective time of the Merger.

Pursuant to the terms of the Merger Agreement, each issued and outstanding share of the Company’s 8.875% redeemable preferred stock, par value $0.01 per share (the “Preferred Stock”), will either be converted into the right to receive one share of 8.875% redeemable preferred stock, par value $0.01 per share, of Callon, which will have substantially the same terms as the Preferred Stock or will be redeemed for an amount in cash specified in the Merger Agreement (the “Preferred Redemption”). Callon is obligated to deposit the amount required to effect the Preferred Redemption (the “Preferred Deposit”) no later than the open of business on the date of the closing of the Merger, though the Company is permitted to fund such amount if Callon fails to do so.

In connection with the proposed Merger, restricted stock awards and units and performance shares that are outstanding immediately prior to closing will generally become vested and converted into shares of Callon common stock based on the Exchange Ratio. Stock appreciation rights that will be settled in cash (“Cash SARs”) that are outstanding immediately prior to the closing will be canceled and converted into a vested stock appreciation right covering shares of Callon common stock, with the calculation of such conversion described in the Merger Agreement.

The completion of the Merger is subject to certain customary mutual closing conditions, including (i) the receipt of the required approvals from the shareholders of the Company and Callon, (ii) either (a) the approval by the holders of Preferred Stock or (b) the Preferred Deposit having been deposited and the Preferred Redemption having occurred, (iii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), which was terminated effective August 6, 2019, and (iv) the receipt by each party of a customary opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986. The obligation of each party to complete the Merger is also conditioned upon the other party’s representations and warranties being true and correct, subject to certain materiality exceptions, and the other party having performed in all material respects its obligations under the Merger Agreement.

The Merger Agreement contains termination rights for each of the Company and Callon, including, among other things, (i) by either the Company or Callon if the other party’s board of directors changes its recommendation with respect to the transactions contemplated by the Merger Agreement or if the other party willfully breaches the covenant not to solicit alternative business combination proposals from third parties, (ii) by the Company, if its board of directors changes its recommendation with respect to the transactions contemplated by the Merger Agreement and substantially concurrently the Company enters into an acquisition agreement providing for a Company Superior Proposal, as defined in the Merger Agreement, (iii) by the Company or Callon, if the approvals of either their common shareholders shall not have been obtained, (iv) by the Company or Callon, if in certain circumstances, the other party breaches or fails to perform any of its representations, warranties or covenants in the Merger Agreement, and (v) by the Company or Callon, if the Merger shall not have been consummated by February 14, 2020, with a possible extension to April 14, 2020 in certain circumstances. Upon termination of the Merger Agreement under differing specified circumstances, (i) the Company would be required to pay Callon a termination fee of $47.4 million or to reimburse Callon up to $7.5 million in expenses or (ii) Callon would be required to pay the Company a termination fee of $57.0 million or to reimburse the Company up to $7.5 million in expenses.

The capitalized terms which are not defined in this description of the proposed Merger, shall have the meaning given to such terms in the Merger Agreement. Additional information on the proposed Merger is included in the Form 8-K filed with the SEC on July 15, 2019 and in this Quarterly Report on Form 10-Q, including “Part II. Other Information—Item 1A. Risk Factors”.

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. These financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes in the 2017 Annual Report. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

Significant Accounting Policies

The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting ~~Policies~~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.

~~Revenue Recognition~~Recently Adopted Accounting Standards

~~Impact of ASC 606 Adoption~~.Leases. Effective January 1, ~~2018,~~2019, the Company adopted ASU No. ~~2014-09, Revenue From Contracts With Customers~~2016-02, Leases (Topic ~~606)~~842) (“ASC ~~606”~~842”), using the modified retrospective ~~method~~approach and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect adjustment in retained ~~earnings.~~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 ~~comparative information for~~difference between the ~~three~~lease liabilities and ~~six months ended June 30, 2017 has not been recast~~ROU assets is due to a rent holiday and ~~continues to be reported~~lease build-out incentives that were recorded as deferred lease liabilities under ~~the~~legacy lease accounting ~~standards in effect for that period. Additionally,~~guidance. The adoption of ASC ~~606~~842 did not ~~impact net~~materially change the Company’s consolidated statements of income ~~attributable to common shareholders and the Company does not expect that it will do so in future periods.~~or consolidated statements of cash flows. See “Note 6. Leases” for further discussion.

Subsequent Events

The ~~tables below summarizes~~Company evaluates subsequent events through the ~~impact of adoption~~date the financial statements are issued. See “Note 16. Subsequent Events” for ~~the three and six months ended June 30, 2018:~~further discussion.

Three Months Ended June 30, 2018
Under ASC 606 Under ASC 605 Increase % Increase
(In thousands)
Revenues
Crude oil
$229,798

$229,658

$140
0.1 %
Natural gas liquids 21,269
20,139
1,130
5.6 %
Natural gas 12,906
12,272
634
5.2 %
Total revenues 263,973
262,069
1,904
0.7 %

Costs and Expenses
Lease operating 35,151
33,247
1,904
5.7 %

Income Before Income Taxes
$35,792

$35,792

$—
— %

Six Months Ended June 30, 2018
Under ASC 606 Under ASC 605 Increase % Increase
(In thousands)
Revenues
Crude oil
$424,717

$424,452

$265
0.1 %
Natural gas liquids 38,171
36,235
1,936
5.3 %
Natural gas 26,365
25,159
1,206
4.8 %
Total revenues 489,253
485,846
3,407
0.7 %

Costs and Expenses
Lease operating 74,424
71,017
3,407
4.8 %

Income Before Income Taxes
$63,603

$63,603

$—
— %

Changes to crude oil, NGL, and natural gas revenues and lease operating expense are due to the conclusion that the Company controls the product throughout processing before transferring to the customer for certain natural gas processing arrangements. Therefore, any transportation, gathering, and processing fees incurred prior to transfer of control are included in lease operating expense.3. Revenue Recognition

The Company’s revenues are comprised solely of revenues from customers and include the sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on ~~our~~its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable.

The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, receivables from contracts with customers were ~~$87.1~~$76.9 million and ~~$85.6~~$77.1 million, respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of ~~income.~~operations.

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

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

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

~~Recently Adopted Accounting Pronouncements~~

~~Business Combinations.~~ ~~In January 2017, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition~~4. Acquisitions and Divestitures of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or divestitures) of assets or businesses. Effective January 1, 2018, the Company adopted ASU 2017-01 using the prospective methodOil and ~~will apply the clarified definition of a business to future acquisition~~Gas Properties

2019 Acquisitions and ~~divestitures.~~

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

~~Recently Issued Accounting Pronouncements~~

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

The Company is in the process of reviewing and determining the contracts to which ASU 2016-02 applies with the assistance of a third party consultant. These include contracts such as non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements, and contracts for the use of vehicles and well equipment. The Company continues to review current accounting policies, controls, processes, and disclosures that will change as a result of adopting the new standard. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities due to the required recognition of right-of-use (“ROU”) assets and corresponding lease liabilities, (ii) increases in depreciation, depletion and amortization and interest expense, (iii) decreases in lease operating and general and administrative expense and (iv) additional disclosures, however, the full impact to the Company’s consolidated financial statements and related disclosures is still being evaluated. Currently, the Company plans to make certain elections allowing the Companydid not ~~to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements, and not to recognize ROU assets~~have any material acquisitions or lease liabilities for short-term leases. The Company plans to adopt the guidance on the effective date of January 1, 2019. As permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.

Other than as disclosed above or in the Company’s 2017 Form 10-K, there are no other accounting standard updates applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of June 30, 2018, and through the filing of this report.

~~Net Income Attributable to Common Shareholders Per Common Share~~

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

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017

(In thousands, except
per share amounts)
Net Income Attributable to Common Shareholders
$30,095

$56,306

$44,838

$96,327
Basic weighted average common shares outstanding 82,058
65,767
81,802
65,479
Effect of dilutive instruments 1,795
141
1,438
387
Diluted weighted average common shares outstanding 83,853
65,908
83,240
65,866
Net Income Attributable to Common Shareholders Per Common Share
Basic
$0.37

$0.86

$0.55

$1.47
Diluted
$0.36

$0.85

$0.54

$1.46

~~The table below presents the a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding~~divestitures for the three and six months ended June 30, 2019. See “Note 1. Nature of Operations” for details of the proposed Merger which was announced on July 15, 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, paid $183.4 million upon initial closing on October 17, 2018, and ~~2017:~~

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(In thousands)
Basic weighted average common shares outstanding 82,058
65,767
81,802
65,479
Dilutive unvested restricted stock awards and units 833
141
640
387
Dilutive unvested performance shares 134
—
158
—
Dilutive exercisable common stock warrants 828
—
640
—
Diluted weighted average common shares outstanding 83,853
65,908
83,240
65,866
received $8.3 million as a post-closing adjustment on March 28, 2019, for an aggregate purchase price of $196.6 million.

The ~~table below presents~~Devon Acquisition was accounted for as a ~~summary~~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 ~~common shares outstanding that were excluded from~~oil and gas properties. Significant inputs into the ~~computation~~calculation included future commodity prices, estimated volumes of ~~diluted~~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		$197,371
Total assets acquired		$197,587

Liabilities
Revenues and royalties payable		$786
Asset retirement obligations	170
Total liabilities assumed		$956
Net Assets Acquired		$196,631

The results of operations for the Devon Acquisition have been included in the Company’s consolidated statements of income since the October 17, 2018 closing date, including total revenues and net income attributable to common shareholders ~~per common share~~ for the three and six months ended June 30, ~~2018 and 2017, as their inclusion would be anti-dilutive:~~

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(In thousands)
Anti-dilutive unvested restricted stock awards and units 16
101
17
16
Anti-dilutive unvested performance shares —
108
2
62
Anti-dilutive exercisable common stock warrants —
—
—
—
Total anti-dilutive 16
209
19
78

~~3. Acquisitions and Divestitures of Oil and Gas Properties~~

~~Acquisitions~~

~~ExL Acquisition.~~ On August 10, 2017, the Company closed on the acquisition of oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) for aggregate cash consideration of $679.8 million (the “ExL Acquisition”). See “Note 10. Derivative Instruments” for information regarding the contingent consideration arrangement associated with the ExL Acquisition.

The consolidated statements of income for the three and six months ended June 30, 2018 include total revenues and net income attributable to common shareholders from the ExL Acquisition, representing activity of the acquired properties2019 as shown in the table below:



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(In thousands)
Total revenues		$4,342		$8,718

Net Income Attributable to Common Shareholders		$2,020		$4,716

Three Months Ended Six Months Ended
June 30, 2018
(In thousands)
Total revenues
$52,771

$96,239

Net income attributable to common shareholders
$42,048

$76,851

~~Divestitures~~

Eagle ~~Ford.~~Ford Divestiture. On ~~January 31, 2018,~~December 11, 2017, the Company ~~sold~~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 ~~to EP Energy E&P Company, L.P. The Company received aggregate net proceeds of $245.7 million, which represents~~for an agreed upon price of $245.0 million, ~~plus purchase price adjustments, which were primarily related to the net cash flows from the~~with an effective date of October 1, 2017, subject to ~~the~~adjustment and customary terms and conditions. The Company received $24.5 million as a deposit on December 11, 2017, $211.7 million upon closing ~~date.~~

~~Niobrara.~~Onon 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 ~~sold~~entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara ~~Formation. Estimated~~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 ~~are $134.7 million, subject~~of $135.6 million. As part of this divestiture, the Company agreed to ~~post-closing adjustments. See “Note 10. Derivative Instruments” for information regarding the~~a contingent consideration arrangement ~~associated with this divestiture.~~(the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. See “Note 13. Derivative Instruments” and “Note 14. 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.~~

~~Marcellus.~~ ~~Effective August 2008, the Company’s wholly-owned subsidiary, Carrizo (Marcellus) LLC, entered into a joint venture~~properties with ACP II Marcellus LLC (“ACP II”), an affiliate of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP, together with its affiliates, “Avista”). As of June 30, 2018, the Avista Marcellus joint venture holds no ~~material assets~~gain or obligations, has no interest in any wells or leases, and intends to divest all remaining immaterial assets. There have been no revenues, expenses, or operating cash flows in the Avista Marcellus joint venture during the years ended December 31, 2015, 2016 and 2017 or during the six months ended June 30, 2018. Concurrently with the sale of the remaining immaterial assets, the Avista Marcellus joint venture and associated joint venture agreements will terminate.

Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP. ACP II’s Board of Managers has the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACP II. Mr. Webster is not a member of ACP II’s Board of Managers. The terms of the Avista Marcellus joint venture were approved by a special committee of the Company’s independent directors.loss recognized.

4.5. Property and Equipment, Net

As of June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, total property and equipment, net consisted of the following:



	June 30, 2019			December 31, 2018
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$6,685,543			$6,278,321
Accumulated depreciation, depletion and amortization and impairments	(4,098,202		)	(3,944,851		)
Proved properties, net	2,587,341			2,333,470
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	580,369			608,830
Capitalized interest	76,607			65,003
Total unproved properties, not being amortized	656,976			673,833
Other property and equipment	30,580			29,191
Accumulated depreciation	(19,392		)	(17,970		)
Other property and equipment, net	11,188			11,221
Total property and equipment, net		$3,255,505			$3,018,524

June 30,
2018 December 31,
2017
(In thousands)
Oil and gas properties, full cost method
Proved properties
$5,744,434

$5,615,153
Accumulated depreciation, depletion and amortization and impairments (3,784,483 ) (3,649,806 )
Proved properties, net 1,959,951
1,965,347
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs 539,836
612,589
Capitalized interest 58,056
47,698
Total unproved properties, not being amortized 597,892
660,287
Other property and equipment 27,223
25,625
Accumulated depreciation (16,641 ) (15,449 )
Other property and equipment, net 10,582
10,176
Total property and equipment, net
$2,568,425

$2,635,810

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was ~~$13.74~~$13.28 and ~~$12.43~~$13.74 for the three months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively, and ~~$13.73~~$13.28 and ~~$12.55~~$13.73 for the six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration, and development activities totaling ~~$6.1~~$3.8 million and ~~$1.9~~$6.1 million for the three months

ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively, and ~~$12.7~~$12.9 million and ~~$7.3~~$12.7 million for the six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling ~~$8.7~~

$8.6 million and ~~$4.0~~$8.7 million for the three months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively, and ~~$19.1~~$17.6 million and ~~$7.8~~$19.1 million for the six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

5.6. 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 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 and six months ended June 30, 2019.



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs
Amortization of right-of-use assets ⁽¹⁾		$410		$784
Interest on lease liabilities ⁽²⁾	131		276
Operating lease costs ⁽³⁾	8,700		22,780
Short-term lease costs ⁽⁴⁾	245		463
Variable lease costs ⁽⁵⁾	50		152
Total lease costs		$9,536		$24,455


(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)	For the three and six months ended June 30, 2019, approximately $6.1 millionand$17.6 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.

The table below presents supplemental balance sheet information for the Company’s leases as of June 30, 2019.



	June 30, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$64,615

Current operating lease liabilities		$34,049
Long-term operating lease liabilities	36,526
Total operating lease liabilities		$70,575

Financing leases:
Other property and equipment, at cost		$7,810
Accumulated depreciation	(5,170		)
Other property and equipment, net		$2,640

Current financing lease liabilities ⁽¹⁾		$1,918
Long-term financing lease liabilities ⁽²⁾	1,034
Total financing lease liabilities		$2,952


(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 six months ended June 30, 2019.



	Six Months Ended June 30, 2019
	(In thousands)
Supplemental Cash Flow Information
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$5,338
Investing cash flows from operating leases		$22,896
Operating cash flows from financing leases		$276
Financing cash flows from financing leases		$879

ROU assets obtained in exchange for lease liabilities
Operating leases		$9,404
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 June 30, 2019.



	June 30, 2019
Weighted Average Remaining Lease Term (In years)
Operating leases	5.1 years
Financing leases	2.3 years

Weighted Average Discount Rate
Operating leases	8.0	%
Financing leases	12.9	%

The table below presents the maturity of the Company’s lease liabilities as of June 30, 2019.



	Operating Leases			Financing Leases
	(In thousands)
July - December 2019		$20,842			$1,113
2020	27,856			1,475
2021	7,726			275
2022	3,697			234
2023	3,680			232
2024 and Thereafter	21,608			39
Total lease payments	85,409			3,368
Less: Imputed interest	(14,834		)	(416		)
Total lease liabilities		$70,575			$2,952

7. Income Taxes

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

The Company’s income tax ~~expense differs~~(expense) benefit differed from the income tax ~~expense~~(expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 21% for the three and six months ended June 30, ~~2018~~2019 and ~~35% for the three and six months ended June 30, 2017,~~2018, to income before income taxes as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands)
Income before income taxes		$109,784			$35,792			$81,752			$63,603
Income tax expense at the U.S. federal statutory rate	(23,055		)	(7,517		)	(17,168		)	(13,357		)
State income tax expense, net of U.S. federal income tax benefit	(874		)	(487		)	(626		)	(806		)
Tax deficiencies related to stock-based compensation	(176		)	(16		)	(2,114		)	(2,542		)
(Recapture) release of valuation allowance	(1,423		)	—			177,723			—
Decrease in valuation allowance due to current period activity	23,211			8,048			19,273			16,449
Other	18			(511		)	8			(546		)
Income tax (expense) benefit		($2,299	)		($483	)		$177,096			($802	)

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(In thousands)
Income before income taxes
$35,792

$56,306

$63,603

$96,327
Income tax expense at the statutory rate (7,517 ) (19,707 ) (13,357 ) (33,714 )
State income tax expense, net of U.S. federal income taxes (487 ) (1,017 ) (806 ) (1,727 )
Tax shortfalls from stock-based compensation expense (16 ) (164 ) (2,542 ) (2,756 )
Decrease in deferred tax assets valuation allowance 8,048
20,948
16,449
38,317
Other (511 ) (60 ) (546 ) (120 )
Income tax expense
($483 )
$—

($802 )
$—
Deferred Tax Asset Valuation Allowance

Significant changes in the Company’s operations, including the ExL Acquisition in the Delaware Basin in the third quarter of 2017 and divestitures of substantially all of the Company’s assets in the Utica and Marcellus in the fourth quarter of 2017 and the Niobrara in the first quarter of 2018, resulted in changes to the Company’s state apportionment for estimated stateThe deferred tax ~~liabilities. As a result~~asset valuation allowance was $45.9 million and $242.9 million as of ~~these changes,~~June 30, 2019 and December 31, 2018, respectively. Throughout 2018, the Company ~~recorded current~~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 ~~state income~~ tax ~~expense~~assets would not be realized. A significant item of ~~$0.5 million and $0.8 million for~~objective negative evidence considered was the ~~three and six months ended June 30, 2018, respectively.~~

~~Tax Cuts and Jobs Act~~

~~On December 22, 2017,~~cumulative pre-tax loss incurred over the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the U.S. federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. Due to the uncertainty regarding the application of ASC 740 in thethree-year period ~~of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 which allowed the Company to provide a provisional estimate of the impacts of the Act in earnings for the year~~ ended December 31, ~~2017 and also provided a one-year measurement period in which the Company would record additional impacts from the enactment of the Act as they are identified. As of June 30,~~ 2018, ~~the Company has not made any changes~~primarily due to the provisional estimate recorded in earnings for the year ended December 31, 2017. While the Company has made a reasonable estimate of the effects on its existing deferred tax balances, it has not completed its accounting for the tax effects of the enactment of the Act and will continue to monitor provisions with discrete rate impacts, such as the limitation on executive compensation for subsequent events and additional guidance provided within the one year measurement period.

~~Deferred Tax Assets Valuation Allowance~~

~~Primarily as a result of the~~ impairments of proved oil and gas properties recognized ~~beginning~~ in the ~~third quarter~~first three quarters of ~~2015~~2016. As of March 31, 2019 and ~~continuing through the third quarter of 2016,~~June 30, 2019, the Company ~~had~~is in a cumulative ~~historical three year~~three-year pre-tax ~~loss~~income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and a net deferred tax asset position at June 30, 2018. The Company then assessed the realizability of its deferred tax assets and, beginning in the third quarter of 2015 and continuing through the second quarter of 2018,future years, the Company concluded that it ~~was~~is more likely than not that the deferred tax assets ~~will not~~would be realized and ~~that a~~released $179.1 million of the valuation allowance ~~was required~~during the first quarter of 2019. During the second quarter of 2019, the Company reduced the prior valuation allowance release by $1.4 million as a result of updating the Company’s forecasted taxable income for 2019 bringing the cumulative release of the valuation allowance to ~~reduce~~$177.7 million. The reduction of the ~~net~~release of the valuation allowance in the second quarter of 2019 is recognized as a decrease in deferred tax assets ~~to zero. As~~and an increase in income tax expense, while the cumulative release of ~~June 30, 2018 and December 31, 2017, the valuation allowance was $316.5 million and $333.0 million, respectively. See~~

~~the table above for changes in~~ the valuation allowance for the ~~three and~~ six months ended June 30, ~~2018~~2019 is recognized as an increase in deferred tax assets and 2017, which primarily related to activity during each respective period and, for the three and six months ended June 30, 2017, the effect of adopting ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.an income tax benefit.

6.8. Long-Term Debt

Long-term debt consisted of the following as of June 30, ~~2018~~2019 and December 31, ~~2017:~~2018:



	June 30, 2019			December 31, 2018
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$841,328			$744,431
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(6,180		)	(6,878		)
8.25% Senior Notes due 2025	250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(3,730		)	(3,962		)
Long-term debt		$1,731,418			$1,633,591

June 30,
2018 December 31,
2017
(In thousands)
Senior Secured Revolving Credit Facility due 2022
$485,000

$291,300
7.50% Senior Notes due 2020 130,000
450,000
Unamortized premium for 7.50% Senior Notes 139
579
Unamortized debt issuance costs for 7.50% Senior Notes (1,095 ) (4,492 )
6.25% Senior Notes due 2023 650,000
650,000
Unamortized debt issuance costs for 6.25% Senior Notes (7,554 ) (8,208 )
8.25% Senior Notes due 2025 250,000
250,000
Unamortized debt issuance costs for 8.25% Senior Notes (4,183 ) (4,395 )
Other long-term debt due 2028 —
4,425
Long-term debt
$1,502,307

$1,629,209

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of June 30, ~~2018~~,2019, had a borrowing base of ~~$1.0~~$1.35 billion, with an elected commitment amount of ~~$900.0 million,~~$1.25 billion, and borrowings outstanding of ~~$485.0~~$841.3 million at a weighted average interest rate of ~~3.74%~~4.14%. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022, ~~(subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”) have not been redeemed or refinanced on or prior to such time),~~ when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

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

~~On May 4, 2018,~~March 27, 2019, the Company entered into the ~~twelfth~~fourteenth amendment to its credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at ~~$1.0~~$1.35 billion, with an elected commitment amount of ~~$900.0 million,~~$1.25 billion, until the next redetermination thereof, (ii) ~~reduce the applicable margin for Eurodollar loans from 2.0%-3.0% to 1.5%-2.5%, depending on level of facility usage, (iii)~~ amend the ~~covenant limiting payment~~definition of ~~dividends~~Current Ratio, and ~~distributions on equity to increase the Company’s ability to make dividends and distributions on its equity interests and (iv)~~(iii) amend certain other ~~provisions, in each case as set forth therein.~~definitions and provisions.

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

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



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%

Ratio of Outstanding Borrowings to Lender Commitments
Applicable Margin for
Base Rate Loans

Applicable Margin for
Eurodollar Loans
Commitment Fee
Less than 25% 0.50% 1.50% 0.375%
Greater than or equal to 25% but less than 50% 0.75% 1.75% 0.375%
Greater than or equal to 50% but less than 75% 1.00% 2.00% 0.500%
Greater than or equal to 75% but less than 90% 1.25% 2.25% 0.500%
Greater than or equal to 90% 1.50% 2.50% 0.500%

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt ~~premiums and debt~~ issuance costs and is net of cash and cash equivalents, EBITDA ~~will be~~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.~~commitments and excludes the Contingent ExL Consideration, which is described in “Note 13. Derivative Instruments.” As of June 30, ~~2018,~~2019, the ratio of Total Debt to EBITDA was ~~2.53~~2.40 to 1.00 and the Current Ratio was ~~1.49~~1.73 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings.

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

~~The credit agreement is subject~~Due to ~~customary events~~the proposed Merger, our regular redetermination scheduled for the fall of ~~default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect~~2019 was postponed 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).~~occur on or about February 14, 2020.

~~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. ~~Upon~~The Company paid a total of $336.9 million upon the redemptions, ~~the Company paid $336.9 million,~~ which included redemption premiums of $6.0 million ~~as well as~~and accrued and unpaid interest of $10.9 ~~million~~million. The redemptions were funded primarily from the ~~last interest payment date up to, but not including,~~net proceeds received from the ~~redemption date.~~divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note 4. 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 ~~paid to redeem the notes~~ and ~~non-cash charges of $2.7 million attributable to~~ the write-off of associated unamortized ~~premium~~premiums and debt issuance ~~costs.~~

~~Redemption~~costs of ~~Other Long-Term Debt~~$2.7 million.

On May 3, 2018, the Company redeemed the remaining $4.4 million outstanding aggregate principal amount of its 4.375% Convertible Senior Notes due 2028 at a price equal to 100% of par. Upon the redemption, the Company paid $4.5 million, which included accrued and unpaid interest of $0.1 ~~million~~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 ~~the last interest payment date up to, but not including, the redemption date.~~its subsidiaries by dividend or loan.

9. Commitments and Contingencies

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

The results of operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, ~~natural gas regulation,~~ tax ~~increases,~~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.

8.10. Preferred Stock and Common Stock Warrants

See “Note 1. Nature of Operations” for discussion of the impact to the Preferred Stock as a result of the proposed Merger.

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”)~~Preferred Stock and (ii) warrants for 2,750,000 shares of the Company’s common stock, with a term of ten years and an exercise price of $16.08 per share, exercisable only on a net share settlement basis (the “Warrants”), for a cash purchase price equal to $970.00 per share of Preferred Stock, to certain funds managed or sub-advised by GSO Capital Partners LP and its ~~affiliates (the “GSO Funds”).~~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.

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



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

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

The table below sets forth a reconciliation of changes in the carrying amount of Preferred Stock ~~outstanding is not mandatorily redeemable, but can be redeemed at~~for the ~~Company’s option~~six months ended June 30, 2019 and ~~in certain circumstances, at the option~~2018.



	Six Months Ended June 30,
	2019		2018
	(In thousands)
Preferred Stock, beginning of period		$174,422		$214,262
Redemption of Preferred Stock	—		(42,897		)
Accretion on Preferred Stock	1,634		1,493
Preferred Stock, end of period		$176,056		$172,858

Loss on Redemption of ~~the holders of the~~ Preferred ~~Stock.~~ 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. In

During the first quarter of 2018, the Company redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred ~~Stock. Upon redemption, the Company paid~~Stock, for $50.5 million, ~~which consisted~~consisting of ~~$1,000.00 per share of Preferred Stock redeemed, plus~~the $50.0 million redemption price and accrued and unpaid dividends ~~with~~of $0.5 million. The Company recognized a ~~portion~~$7.1 million loss on the redemption due to the excess of the ~~proceeds from~~$50.0 million redemption price over the ~~divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for information regarding divestitures.~~

~~In addition, at any time on or prior to August 10, 2020, the Company may redeem all or part~~$42.9 million redemption date carrying value of the Preferred ~~Stock in cash at a redemption premium~~Stock.

11. Stock-Based Compensation

See “Note 1. Nature of 104.4375%, plus accrued and unpaid dividends and the present value on the redemption date of all quarterly dividends that would be payable from the redemption date through August 10, 2020. After August 10, 2020, the Company may redeem all or partOperations” for discussion of the ~~Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends.~~



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

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

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

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

~~Upon the occurrence of certain changes of control.~~

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

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

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

~~Electing up to two directors~~impact to the Company’s ~~Board of Directors;~~restricted stock awards and

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

~~The Preferred Stock is presented as temporary equity in the consolidated balance sheets with the issuance date fair value accreted to the redemption value using the effective interest method.~~

~~The table below summarizes changes in the carrying amount of Preferred Stock for the six months ended June 30, 2018:~~



	~~June 30, 2018~~
	~~(In thousands)~~
~~Preferred Stock, beginning of period~~		~~$214,262~~
~~Redemption of preferred stock~~	~~(42,897~~		)
~~Accretion on Preferred Stock~~	~~1,493~~
~~Preferred Stock, end of period~~		~~$172,858~~

~~Preferred Stock Dividends, Accretion,~~ units, performance shares, and ~~Loss on Redemption~~

Dividends, accretion, and loss on redemption of preferred stock are presented in the consolidated statements of income as a reduction of net income to compute net income attributable to common shareholders.

For the three months ended June 30, 2018, the Company declared and paid $4.5 million of cash dividends to the holders of record of the Preferred Stock on June 15, 2018. For the six months ended June 30, 2018, the Company declared and paid $9.3 million of cash dividends to the holders of the Preferred Stock on June 15, 2018 and March 15, 2018.

~~For the three and six months ended June 30, 2018, the Company recorded accretion on Preferred Stock of $0.7 million and $1.5 million, respectively.~~

~~As a result of the redemption described above, the Company recorded a loss on redemption of preferred stock of $7.1 million, which included $0.1 million of direct costs incurred~~Cash SARs as a result of the ~~redemption~~proposed Merger.

At the Company’s annual meeting on May 16, 2019, the shareholders approved the proposal to amend and a non-cash charge of $7.0 million attributable to the difference between $50.0 million, which was the consideration transferred to the holders of the Preferred Stock excluding accrued and unpaid dividends, and $42.9 million, which was 20% of the carrying value of the Preferred Stock on the date of redemption.

~~9. Stock-Based Compensation~~

~~Equity-Based Incentive Awards Plans~~

~~The Company grants equity-based incentive awards under~~restate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the ~~“2017~~“A&R 2017 Incentive Plan”) ~~and~~,which included an increase to the ~~Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The~~number of shares available for issuance under the A&R 2017 Incentive ~~Plan replaced the Incentive Plan~~Plan. As of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”) and, from the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan. However, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. Under the 2017 Incentive Plan, the Company can grant restricted stock awards and units, stock appreciation rights that can be settled inJune 30, 2019, there were 3,164,691 shares of common stock ~~or cash at~~available for grant under the ~~option of the~~A&R 2017 Incentive Plan assuming all future grants will be full value stock awards. The Company ~~performance shares, stock options, and cash awards to employees, independent contractors, and non-employee directors. Under the Cash SAR Plan, the Company can grant~~has not granted stock appreciation rights ~~that may only be settled in cash (“Cash SARs”) to employees and independent contractors.~~

The 2017 Incentive Plan provides that up to 2,675,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan at the effective date of the 2017 Incentive Plan, may be issued (the “Maximum Share Limit”). Each restricted stock award, restricted stock unit, or performance share granted under the 2017 Incentive Plan counts as

~~1.35 shares against the Maximum Share Limit. Each stock option and stock appreciation right~~ to be settled in shares of common stock ~~(“Stock SAR”) granted under~~and has no outstanding stock options. See “Note 11. Stock-Based Compensation” of the ~~2017 Incentive Plan counts as 1.00 share against~~Notes to Consolidated Financial Statements in the ~~Maximum Share Limit. Each stock appreciation right to be settled in shares~~2018 Annual Report for details of ~~common stock or cash (“Incentive SAR”) granted under~~ the 2017 Incentive Plan counts as 1.00 share against the Maximum Share Limit up to the date the Company, if it so chooses, affirmatively elects to settle the stock appreciation right in cash. Each stock appreciation right to be settled in cash (“Incentive Cash SAR”) granted under the 2017 Incentive Plan or Cash SAR does not count against the Maximum Share Limit. As of June 30, 2018, there were 326,774 common shares remaining available for grant under the 2017 Incentive Plan.Company’s equity-based incentive plans.

Restricted Stock Awards and Units

~~As of June 30, 2018, unrecognized compensation costs related to unvested restricted stock awards and units was $30.5 million and will be recognized over a weighted average period of 2.2 years.~~

The table below summarizes restricted stock award and unit activity for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,
	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	3,320,060			$14.16	2,263,830				$19.15
Granted	115,936			$11.90	1,250		��		$15.43
Vested	(52,639	)		$25.20	(43,992	)			$25.76
Forfeited	(47,464	)		$12.05	(9,915	)			$18.04
Unvested, end of period	3,335,893			$13.94	2,211,173				$19.02


	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Six Months Ended June 30,
Unvested restricted stock awards and units, beginning of period	1,482,655			$28.07
					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	1,348,415			$14.68	2,034,619			$11.06	1,348,415			$14.68
Vested	(608,904	)		$31.43	(904,973	)		$20.91	(608,904	)		$31.43
Forfeited	(10,993	)		$19.17	(60,420	)		$13.14	(10,993	)		$19.17
Unvested restricted stock awards and units, end of period	2,211,173			$19.02
Unvested, end of period					3,335,893			$13.94	2,211,173			$19.02

~~During~~Grant activity for the three months ended June 30, 2019 primarily consisted of restricted stock units to non-employee directors for their service for the 2019-2020 director term. These grants to the non-employee directors vest on the earlier of the date of the 2020 Annual Meeting of Shareholders and June 30, 2020. Grant activity for the six months ended June 30, ~~2018, the Company granted 1,348,415 restricted stock awards and units~~2019 primarily ~~consisting~~consisted of ~~1,343,412~~ restricted stock units to employees ~~and independent contractors~~ as part of ~~its~~the annual grant of long-term equity incentive awards ~~during~~that occurred in the first quarter of ~~2018.~~each of the years presented in the table above. These restricted stock units ~~had~~vest ratably over an approximate three-year period.

As a ~~grant date~~result of the approval of the A&R 2017 Incentive Plan by shareholders, the Compensation Committee determined that the Company would settle the restricted stock units granted in the first quarter of 2019 in common stock rather than cash upon vesting. As such, the Company modified these restricted stock units, which were previously accounted for as liability awards to equity awards and reclassified the fair value of ~~$19.7 million and will vest ratably over a three-year period.~~

~~Stock Appreciation Rights (“SARs”)~~

As of June 30, 2018, all outstanding SARs are either Cash SARs or Incentive Cash SARs and will be settled in cash. The liability for SARs as of June 30, 2018 was $8.7 million, all of which was classified as “Other current liabilities,”these awards to shareholders’ equity in the consolidated balance sheets.

The aggregate fair value of restricted stock awards and units that vested during the three months ended June 30, 2019 and 2018 was $0.7 million and $1.0 million, respectively, and $10.5 million and $9.9 million for the six months ended June 30, 2019 and 2018, respectively. As of ~~December 31, 2017, the liability for SARs was $4.4 million, all of which was classified as “Other liabilities” in the consolidated balance sheets. Unrecognized~~June 30, 2019 and 2018, unrecognized compensation costs related to unvested ~~SARs was $11.3~~restricted stock awards and units were $38.3 million ~~as of June 30, 2018,~~ and ~~will~~$30.5 million, respectively, to be recognized over a weighted average period of ~~2.6~~2.2 years.

Cash SARs

There was no activity for Cash SARs for the three months ended June 30, 2019 and 2018. The table below summarizes the activity for Cash SARs for the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
	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	4.9	1,330,924		$21.35	4.8
Vested, end of period	919,800		$24.34		543,018		$27.18
Vested and exercisable, end of period	—		$24.34	3.0	543,018		$27.18	3.0

SARs
Weighted
Average
Exercise
Prices

Weighted Average Remaining Life
(In years)

Aggregate Intrinsic Value
(In millions)

Aggregate Intrinsic Value of Exercises
(In millions)
Outstanding, beginning of period 714,238

$27.12

Granted 616,686

$14.67

Exercised —

$—

$—
Forfeited —

$—

Expired —

$—

Outstanding, end of period 1,330,924

$21.35
4.8
$9.1

Vested, end of period 543,018

$27.18

Vested and exercisable, end of period 543,018

$27.18
3.04
$0.5

~~During the six months ended June 30, 2018, the Company granted 616,686 Incentive~~Grant activity consisted of Cash SARs to certain employees ~~and independent contractors, all~~as part of ~~which~~the annual grant of long-term equity incentive awards that occurred in the first quarter of ~~2018 as part~~each of the ~~Company’s annual grant of long-term equity incentive awards. These Incentive~~years presented in the table above. The Cash SARs ~~will~~granted in the first quarter of 2019 and 2018 vest ratably over aan approximate three-year period and expire approximately seven years from the grant date.

The grant date fair value of the ~~Incentive~~ Cash SARs, calculated using the Black-Scholes-Merton option pricing model, was $4.6 million and $4.9 ~~million.~~million for the six months ended June 30, 2019 and 2018. The following table summarizes the assumptions used ~~to calculate~~and the resulting grant date fair value of the ~~Incentive~~ Cash SARs granted during the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
	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



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

~~Performance Shares~~

The aggregate intrinsic value of Cash SARs outstanding as of June 30, 2019 and 2018 was zero and $9.1 million, respectively, and the aggregate intrinsic value of Cash SARs vested and exercisable as of June 30, 2019 and 2018 was zero and $0.5 million. As of June 30, 2019 and December 31, 2018, the liabilities for Cash SARs were $2.1 million and $1.8 million, all of which was classified as “Other current liabilities,” in the respective consolidated balance sheets. As of June 30, 2019 and 2018, unrecognized compensation costs related to unvested ~~performance shares was $2.9~~Cash SARs were $5.1 million and ~~will~~$11.3 million, respectively, to be recognized over a weighted average period of ~~2.2 years.~~2.4 years and 2.6 years, respectively.

Performance Shares

There was no performance share activity for the three months ended June 30, 2019 and 2018. The table below summarizes performance share activity for the six months ended June 30, 2019 and 2018:



	Six Months Ended June 30,
	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

Target Performance Shares ⁽¹⁾

Weighted Average Grant Date
Fair Value
Unvested performance shares, beginning of period 144,955

$47.14
Granted 93,771

$19.09
Vested at end of performance period (49,458 )
$65.51
Did not vest at end of performance period (7,059 )
$65.51
Forfeited —

$—
Unvested performance shares, end of period 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.

~~During~~Grant activity consisted of performance shares as part of the ~~six months ended June 30, 2018, the Company granted 93,771 target performance shares~~annual grant of long-term equity incentive awards to certain employees ~~and independent contractors, all of which~~that occurred in the first quarter of ~~2018 as part of the Company’s annual grant of long-term equity incentive awards.~~2019 and 2018. Each performance share represents the right to receive one share of common stock, however, the number of performance shares that ~~will~~ vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three-year performance period, the last day of which is also the vesting date.

~~Also during~~The following table presents the ~~six months ended June 30, 2018, the Company vested 49,458 performance shares that were granted in 2015. As a result~~results of the Company’s final TSR ranking during the performance ~~period, a multiplier of 88% was applied to~~periods that ended during the ~~56,517 target performance shares that were granted in 2015, resulting in 7,059 performance shares that did not vest.~~six months ended June 30, 2019 and 2018:

~~The~~



	Six Months Ended June 30,
	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 millions)	$0.4		$0.8

For the six months ended June 30, 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.~~million, respectively. The following table summarizes the assumptions used ~~to calculate~~and the resulting grant date fair value ofper performance share for the ~~performance shares granted~~grant activity during the six months ended June 30, ~~2018:~~2019:



	Six Months Ended June 30,
	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



	~~Grant Date Fair Value Assumptions~~
~~Number of simulations~~	~~500,000~~
~~Expected term (in years)~~	~~3.0~~
~~Expected volatility~~	~~61.5~~	%
~~Risk-free interest rate~~	~~2.4~~	%
~~Dividend yield~~	—	%

As of June 30, 2019 and 2018, unrecognized compensation costs related to unvested performance shares were $3.1 million and $2.9 million, respectively, to be recognized over a weighted average period of 2.1 years and 2.2 years, respectively.

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 ~~reflected as~~included in “General and administrative, ~~expense,~~ net” in the consolidated statements of income.

The Company recognized the following stock-based compensation expense, net for the three and six months ended June 30, ~~2018~~2019 and ~~2017:~~2018:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands)
Restricted stock awards and units		$5,358			$4,720			$10,181			$9,804
Cash SARs	(426		)	5,788			334			4,373
Performance shares	436			406			871			963
	5,368			10,914			11,386			15,140
Less: amounts capitalized to oil and gas properties	(1,514		)	(3,708		)	(3,417		)	(4,416		)
Total stock-based compensation expense, net		$3,854			$7,206			$7,969			$10,724

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(In thousands)
Restricted stock awards and units
$4,720

$5,024

$9,804

$10,873
SARs 5,788
(3,783 ) 4,373
(7,469 )
Performance shares 406
574
963
1,280
10,914
1,815
15,140
4,684
Less: amounts capitalized to oil and gas properties (3,708 ) (233 ) (4,416 ) (1,088 )
Total stock-based compensation expense, net
$7,206

$1,582

$10,724

$3,596

~~10.~~12. 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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands, except per share amounts)
Net Income		$107,485			$35,309			$258,848			$62,801
Dividends on preferred stock	(4,452		)	(4,474		)	(8,812		)	(9,337		)
Accretion on preferred stock	(833		)	(740		)	(1,634		)	(1,493		)
Loss on redemption of preferred stock	—			—			—			(7,133		)
Net Income Attributable to Common Shareholders		$102,200			$30,095			$248,402			$44,838

Basic weighted average common shares outstanding	92,497			82,058			92,121			81,802
Dilutive effect of restricted stock and performance shares	203			967			358			798
Dilutive effect of common stock warrants	—			828			—			640
Diluted weighted average common shares outstanding	92,700			83,853			92,479			83,240

Net Income Attributable to Common Shareholders Per Common Share
Basic		$1.10			$0.37			$2.70			$0.55
Diluted		$1.10			$0.36			$2.69			$0.54

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 June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
	(In thousands)
Anti-dilutive restricted stock and performance shares	3,077	16	1,526	19
Anti-dilutive common stock warrants	2,750	—	2,750	—
Total weighted average anti-dilutive securities	5,827	16	4,276	19

13. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to ~~reduce its exposure to~~mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and ~~thereby~~ achieve a more predictable level of cash ~~flows to support~~flow. Since the Company derives a significant portion of its revenues from sales of crude oil, crude oil price volatility represents the Company’s ~~capital expenditure program and fixed costs.~~most significant commodity price risk. 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 ~~or trading~~ 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, ~~basis swaps, and purchased and~~ sold call options, and basis swaps, each of which ~~are~~is described below.

Price ~~Swaps:~~ ~~The Company receives~~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 ~~an index price~~the difference to the ~~counterparty over specified periods for contracted volumes.~~counterparty.

~~Three-Way Collars:~~ ~~A three-way collar is a combination~~Three-way collars consist of ~~options including~~ a purchased put option ~~(fixed floor~~(floor price), a sold call option ~~(fixed ceiling~~(ceiling price) and a sold put option ~~(fixed sub-floor~~(sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the published index price is and are settled based on differences between the ~~fixed~~floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and ~~the fixed~~ sub-floor ~~price or is above the fixed ceiling price, the Company receives the fixed floor price or pays the index price, respectively.~~price. If the settlement price of the referenced index ~~price~~ is below the ~~fixed~~ 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 ~~plus~~and sub-floor price, the Company receives the difference between the ~~fixed~~ floor price and the ~~fixed sub-floor price.~~settlement price of the referenced index from the counterparty. If the settlement price of the referenced index ~~price~~ is between the ~~fixed~~ floor price and ~~fixed~~ 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 ~~these contracts~~its commodity derivative instruments in order to obtain a higher floor price and/or higher ceiling price.

~~Basis Swaps:~~ Basis swaps fix the price differential between a published index price and the applicable local index price under which our production is sold. For the Company’s Permian oil production, the basis swaps fix the price differential between the Midland WTI price and the Cushing WTI price and for the Company’s Eagle Ford oil production, the basis swaps fix the price differential between the LLS price and the Cushing WTI price.

~~Sold Call Options~~: These contracts give the counterparty the right, but not the obligation, to buy contracted volumes from the Company over specified periods and prices in the future. At settlement, if the index price exceeds the fixed price of the call option, the Company pays the counterparty the excess. If the index price settles below the fixed price of the call option, no payment is due from either party. These contracts require the counterparty to pay premiums to the Company that represent the fair value of the call option as of the date of sale. All of the Company’s natural gas sold call options were executed contemporaneously with certain crude oil price swaps to increase the fixed price on those crude oil price swaps. Those certain crude oil price swaps settled prior to 2018.

~~Purchased Call Options~~: These contracts give the Company the right, but not the obligation, to buy contracted volumes from the counterparty over specified periods and prices in the future. At settlement, if the index price exceeds the fixed price of the call option, the counterparty pays the Company the excess. If the index price settles below the fixed price of the call option, no payment is due from either party. These contracts require the Company to pay premiums to the counterparty that represent the fair value of the call option as of the date of purchase. All of the Company’s purchased crude oil call options were executed contemporaneously with sold crude oil call options to increase the fixed price on a portion of the existing sold crude oil call options and therefore are presented on a net basis as “Net Sold Call Options” in the table below.

~~Premiums~~: In order to increase the fixed price on a portion of the Company’s existing sold call options, the Company incurred premiums on its purchased call options. Additionally, in order to obtain a higher floor price and/or ceiling price, the Company incurred premiums on certain of its three-way collars. Payment of these premiums are deferred until the applicable contracts settle on a monthly basis ~~throughout~~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.

~~The following table sets forth a summary of the Company’s outstanding crude oil derivative positions as~~

As of June 30, ~~2018~~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	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

Period Type of Contract Index
Volumes
(Bbls/d)
Fixed Price ($/Bbl) Sub-Floor Price ($/Bbl) Floor Price ($/Bbl) Ceiling Price ($/Bbl)
2018
Q3-Q4 Price Swaps NYMEX WTI 6,000

$49.55

$—

$—

$—
Q3-Q4 Three-Way Collars NYMEX WTI 24,000
—
39.38
49.06
60.14
Q3-Q4 Basis Swaps
LLS-Cushing WTI ⁽¹⁾
18,000
5.11
—
—
—
Q3-Q4 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
6,000
(0.10 ) —
—
—
Q3-Q4 Net Sold Call Options NYMEX WTI 3,388
—
—
—
71.33
2019
Q1-Q4 Three-Way Collars NYMEX WTI 15,000
—
41.00
49.72
62.48
Q1-Q2 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
3,000
(3.83 ) —
—
—
Q3 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
3,500
(4.18 ) —
—
—
Q4 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
6,000
(3.71 ) —
—
—
Q1-Q4 Net Sold Call Options NYMEX WTI 3,875
—
—
—
73.66
2020
Q1-Q4 Net Sold Call Options NYMEX WTI 4,575
—
—
—
75.98



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	3Q19	Basis Swaps	Waha-NYMEX Henry Hub	42,500	—	—	—	—			($1.49	)
Natural gas	3Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—

Natural gas	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	42,500	—	—	—	—			($1.30	)
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	—


~~(1)~~	~~The index price paid under these basis swaps is LLS and the index price received is Cushing WTI plus the fixed price differential.~~


~~(2)~~	~~The index price paid under these basis swaps is Midland WTI and the index price received is Cushing WTI less the fixed price differential.~~

~~The following table sets forth a summary of the Company’s outstanding NGL derivative positions as of June 30, 2018 at weighted average contract prices:~~

Period Type of Contract Index
Volumes
(Bbls/d)

Fixed Price
($/Bbl)
2018
Q3-Q4 Price Swaps Ethane - OPIS Mont Belvieu Non-TET 2,200

$12.01
Q3-Q4 Price Swaps Propane - OPIS Mont Belvieu Non-TET 1,500
34.23
Q3-Q4 Price Swaps Butane - OPIS Mont Belvieu Non-TET 200
38.85
Q3-Q4 Price Swaps Isobutane - OPIS Mont Belvieu Non-TET 600
38.98
Q3-Q4 Price Swaps Natural Gasoline - OPIS Mont Belvieu Non-TET 600
55.23

~~The following table sets forth a summary of the Company’s outstanding natural gas derivative positions as of June 30, 2018 at weighted average contract prices:~~

Period Type of Contract Index
Volumes
(MMBtu/d)

Fixed Price
($/MMBtu)

Ceiling Price
($/MMBtu)
2018
Q3-Q4 Price Swaps NYMEX HH 25,000

$3.01

$—
Q3-Q4 Sold Call Options NYMEX HH 33,000
—
3.25
2019
Q1-Q4 Sold Call Options NYMEX HH 33,000
—
3.25
2020
Q1-Q4 Sold Call Options NYMEX HH 33,000
—
3.50

The Company typically has numerous ~~hedge positions~~commodity derivative instruments outstanding with a counterparty that ~~span several~~were executed at various dates, for various contract types, commodities and time periods ~~and~~ often ~~result~~resulting in both commodity derivative asset and liability positions ~~held~~ 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 ~~ISDA master agreements,~~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 ~~where~~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 to be novated to a Lender~~ Counterparty and therefore do not require the posting of cash collateral.

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 June 30, 2019, the Company has outstanding commodity derivative instruments with fifteen counterparties to minimize its credit exposure to any individual counterparty.

Contingent Consideration Arrangements

~~In connection with~~The purchase and sale agreements for the acquisition of properties in the Delaware Basin from ExL ~~Acquisition~~Petroleum Management, LLC and ExL Petroleum Operating Inc. (the “ExL Acquisition”) in ~~each of the~~2017 and divestitures of the Company’s assets in the Niobrara in ~~the first quarter of~~ 2018, and ~~the~~ Marcellus and Utica in ~~the fourth quarter of~~ 2017, ~~the Company agreed to~~included contingent consideration arrangements that ~~could allow~~require the Company to pay or entitle the Company to receive ~~or be required to pay certain~~specified amounts if commodity prices ~~are above specific~~exceed specified thresholds, which are summarized in the ~~table~~tables below. If the pricing threshold for the respective contingent consideration arrangement is met, the payment is made or received in the first quarter of the following year. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” ~~included in this Quarterly Report on Form 10-Q as well as “Note 3. Acquisitions and Divestitures~~ of ~~Oil and Gas Properties” included~~the Notes to Consolidated Financial Statements in the ~~2017~~2018 Annual Report for ~~details~~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 ~~Acquisition and each of the divestitures discussed above.~~Consideration

Contingent Receipt (Payment) - Annual Contingent Receipt (Payment) - Aggregate Limit
Contingent Consideration Arrangements Years
Threshold ⁽¹⁾
(In thousands)
Contingent ExL Consideration 2018 $50.00
($50,000 )
2019 50.00 (50,000 )
2020 50.00 (50,000 )
2021 50.00 (50,000 )
($125,000 )

Contingent Niobrara Consideration 2018 $55.00
$5,000

2019 55.00 5,000

2020 60.00 5,000
—

Contingent Marcellus Consideration 2018 $3.13
$3,000

2019 3.18 3,000

2020 3.30 3,000

$7,500

Contingent Utica Consideration 2018 $50.00
$5,000

2019 53.00 5,000

2020 56.00 5,000
—



	Year	Threshold ⁽¹⁾		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			Remaining Contingent Payments - Aggregate Limit			Acquisition Date Fair Value
						(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 ~~specific~~specified threshold for each year has been met is the average daily closing spot price ~~of a~~per barrel of ~~West Texas Intermediate~~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 ~~Contingent ExL Consideration, Contingent Niobrara Consideration, and Contingent Utica Consideration and~~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.

Contingent Niobrara Consideration



	Year	Threshold ⁽¹⁾	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Remaining Contingent Payments - Aggregate Limit		Divestiture Date Fair Value
					(In thousands)
										$7,880

Actual Settlement	2018	$55.00	1Q19	Financing		$5,000

Remaining Potential Settlements	2019	55.00	1Q20	⁽²⁾	5,000			$10,000
	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.

Contingent Marcellus Consideration



	Year	Threshold ⁽¹⁾	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Remaining Contingent Payments - Aggregate Limit		Divestiture Date Fair Value
					(In thousands)
										$2,660

Actual Settlement	2018	$3.13	1Q19	N/A		$—

Remaining Potential Settlements	2019	3.18	1Q20	⁽²⁾	3,000			$6,000
	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 ~~of a~~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 first quarter of 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		Remaining Contingent Payments - Aggregate Limit		Divestiture Date Fair Value
					(In thousands)
										$6,145

Actual Settlement	2018	$50.00	1Q19	Financing		$5,000

Remaining Potential Settlements	2019	53.00	1Q20	⁽²⁾	5,000			$10,000
	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.

Derivative Assets and Liabilities

~~All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value.~~ The ~~deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity~~ derivative instrument asset and liability fair value asset or liability pursuant to the netting arrangements described above. Each of the contingent consideration arrangements discussed above were determined to be embedded derivatives and are recorded in the consolidated balance sheets as either an asset or liability measured at fair value at the acquisition or divestiture date, as well as each subsequent balance sheet date.

~~The combined derivative instrument fair value assets and liabilities, including deferred premium obligations,~~values recorded in the consolidated balance sheets as of June 30, ~~2018~~2019 and December 31, ~~2017~~2018 are summarized below:


	June 30, 2018									June 30, 2019
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)									(In thousands)
Commodity derivative instruments		$32,422			($31,259	)		$1,163			$21,704			($15,582	)		$6,122
Contingent Niobrara Consideration	4,820			—			4,820			3,409			—			3,409
Contingent Marcellus Consideration	130			—			130			3			—			3
Contingent Utica Consideration	4,815			—			4,815			4,087			—			4,087
Derivative assets		$42,187			($31,259	)		$10,928			$29,203			($15,582	)		$13,621
Commodity derivative instruments	13,418			(13,418		)	—			10,303			(8,243		)	2,060
Contingent Niobrara Consideration	5,150			—			5,150			1,538			—			1,538
Contingent Marcellus Consideration	1,400			—			1,400			447			—			447
Contingent Utica Consideration	5,730			—			5,730			1,970			—			1,970
Other assets		$25,698			($13,418	)		$12,280
Other long-term assets											$14,258			($8,243	)		$6,015

Commodity derivative instruments		($118,953	)		$21,813			($97,140	)		($26,390	)		$8,024			($18,366	)
Deferred premium obligations	(9,446		)	9,446			—			(7,558		)	7,558			—
Contingent ExL Consideration	(48,380		)	—			(48,380		)	(46,385		)	—			(46,385		)
Derivative liabilities-current		($176,779	)		$31,259			($145,520	)		($80,333	)		$15,582			($64,751	)
Commodity derivative instruments	(40,006		)	5,748			(34,258		)	(10,988		)	6,474			(4,514		)
Deferred premium obligations	(7,670		)	7,670			—			(1,769		)	1,769			—
Contingent ExL Consideration	(53,675		)	—			(53,675		)	(14,413		)	—			(14,413		)
Derivative liabilities-non current		($101,351	)		$13,418			($87,933	)
Other long-term liabilities											($27,170	)		$8,243			($18,927	)



	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	)

December 31, 2017
Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets
(In thousands)
Commodity derivative instruments
$4,869

($4,869 )
$—
Derivative assets
$4,869

($4,869 )
$—
Commodity derivative instruments 9,505
(9,505 ) —
Contingent Niobrara Consideration —
—
—
Contingent Marcellus Consideration 2,205
—
2,205
Contingent Utica Consideration 7,985
—
7,985
Other assets
$19,695

($9,505 )
$10,190

Commodity derivative instruments
($52,671 )
($4,450 )
($57,121 )
Deferred premium obligations (9,319 ) 9,319
—
Derivative liabilities-current
($61,990 )
$4,869

($57,121 )
Commodity derivative instruments (24,609 ) (2,098 ) (26,707 )
Deferred premium obligations (11,603 ) 11,603
—
Contingent ExL Consideration (85,625 ) —
(85,625 )
Derivative liabilities-non current
($121,837 )
$9,505

($112,332 )

See “Note ~~11.~~14. Fair Value Measurements” for additional information regarding the fair value of the Company’s derivative instruments.

(Gain) ~~Loss~~loss on ~~Derivatives, Net~~derivatives, net

The ~~Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result~~components of ~~changes in the fair value of the Company’s commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as~~ “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the deferred premium obligations are incurred. The effects of commodity derivative instruments, deferred premium obligations and contingent consideration arrangements in the consolidated statements of income for the three and six months ended June 30, ~~2018~~2019 and ~~2017~~2018 are summarized below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands)
(Gain) loss on derivatives, net
Crude oil		($20,915	)		$53,437			$41,846			$82,948
NGL	—			6,564			(6		)	4,799
Natural gas	(1,600		)	153			(3,670		)	(2,892		)
Contingent ExL Consideration	1,215			10,600			30,214			16,430
Contingent Niobrara Consideration	265			(1,705		)	(2,912		)	(2,090		)
Contingent Marcellus Consideration	438			205			919			675
Contingent Utica Consideration	148			(1,540		)	(3,556		)	(2,560		)
(Gain) loss on derivatives, net		($20,449	)		$67,714			$62,835			$97,310

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil derivatives
$53,437

($29,736 )
$82,948

($48,163 )
NGL derivatives 6,564
—
4,799
—
Natural gas derivatives 153
(3,883 ) (2,892 ) (10,719 )
Deferred premium obligations —
7,554
—
7,501
Contingent ExL Consideration 10,600
—
16,430
—
Contingent Niobrara Consideration (1,705 ) —
(2,090 ) —
Contingent Marcellus Consideration 205
—
675
—
Contingent Utica Consideration (1,540 ) —
(2,560 ) —
(Gain) Loss on Derivatives, Net
$67,714

($26,065 )
$97,310

($51,381 )

Cash ~~Received (Paid)~~received (paid) for ~~Derivative Settlements, Net~~derivative settlements, net

~~Cash flows are impacted to the extent that settlements of commodity derivatives, including deferred premium obligations, and~~There were no settlements of contingent consideration arrangements ~~result in cash receipts or payments during~~for the ~~period~~three months ended June 30, 2019. For the six months ended June 30, 2019, the Company paid $50.0 million from the first annual settlement of the Contingent ExL Consideration and ~~are presented~~received $10.0 million from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as ~~“Cash received (paid)~~the specified pricing thresholds for ~~derivative settlements, net” in the consolidated statements of cash flows. Cash payments made to settle~~fiscal year 2018 for each contingent consideration ~~liabilities~~arrangement were exceeded. The cash paid and received for those contingent consideration settlements are classified as cash flows from financing activities ~~up to~~as each of the ~~divestiture~~settlements were less than their respective acquisition or ~~acquisition~~divestiture date fair ~~value with any excess classified as cash flows from operating activities.~~values. For the three and six months ended June 30, 2018, ~~and 2017, the Company did not receive or pay cash for the~~there were no settlements of contingent consideration arrangements.

The ~~net cash received (paid)~~components of “Cash paid for derivative settlements, net” and “Cash paid for settlements of ~~commodity derivatives and deferred premium obligations~~contingent consideration arrangements, net” in the consolidated statements of cash flows for the three and six months ended June 30, ~~2018~~2019 and ~~2017~~2018 are summarized below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Cash Flows From Operating Activities	(In thousands)
Cash received (paid) for commodity derivative settlements, net
Crude oil		($3,698	)		($21,210	)		($4,018	)		($33,333	)
NGL	—			(756		)	623			(1,188		)
Natural gas	1,925			488			1,625			540
Deferred premium obligations	(2,749		)	(2,605		)	(5,390		)	(4,467		)
Cash paid for commodity derivative settlements, net		($4,522	)		($24,083	)		($7,160	)		($38,448	)

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	)		$—

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
Cash Flows from Operating Activities (In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil derivatives
($21,210 )
$409

($33,333 )
$3,441
NGL derivatives (756 ) —
(1,188 ) —
Natural gas derivatives 488
(104 ) 540
(1,253 )
Deferred premium obligations (2,605 ) (566 ) (4,467 ) (930 )
Cash Received (Paid) for Derivative Settlements, Net
($24,083 )
($261 )
($38,448 )
$1,258

~~11.~~

14. 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 ~~commodity~~ derivative instrument ~~and contingent consideration arrangement~~ assets and liabilities measured at fair value on a recurring basis as of June 30, ~~2018~~2019 and December 31, ~~2017:~~2018:



	June 30, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$8,182			$—
Contingent Niobrara Consideration	—		4,947			—
Contingent Marcellus Consideration	—		450			—
Contingent Utica Consideration	—		6,057			—

Liabilities
Commodity derivative instruments		$—		($22,880	)		$—
Contingent ExL Consideration	—		(60,798		)	—



	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$~~1,163~~31,751			$—
Contingent Niobrara Consideration	—		7,035			—		~~9,970~~
Contingent Marcellus Consideration	—		1,369			—		~~1,530~~
Contingent Utica Consideration	—		7,501			—		~~10,545~~

Liabilities
Commodity derivative instruments		$—		($~~131,398~~15,438	)		$—
Contingent ExL Consideration	—		(80,584		)	—		~~(102,055~~	)

~~December 31, 2017~~

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(In thousands)~~

~~Assets~~

~~Commodity derivative instruments~~

$—

~~Contingent Niobrara Consideration~~

—

~~Contingent Marcellus Consideration~~

—

~~2,205~~

~~Contingent Utica Consideration~~

—

~~7,985~~

~~Liabilities~~

~~Commodity derivative instruments~~

$—

~~($83,828~~

)

$—

~~Contingent ExL Consideration~~

—

~~(85,625~~

)

The ~~commodity derivative and contingent consideration arrangement~~ 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.

The Company typically has numerous hedge positions that span several time periods and often result in both commodity derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the commodity derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company nets the fair values of its assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the six months ended June 30, 2018 and 2017.

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 ~~volatility factors. As some of these assumptions~~the Company’s credit quality for the contingent consideration liability. These inputs are ~~not~~ substantially

observable in active markets throughout the full term of the contingent consideration arrangements ~~the contingent consideration arrangements were~~or can be derived from observable data and are therefore designated as Level 32 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

The following table presents the reconciliation of changes in the fair values of the contingent consideration arrangements, which were designated as Level 3 within the valuation hierarchy, for the six months ended June 30, 2018:

Contingent Consideration Arrangements
Assets Liability
For the Six Months Ended June 30, 2018 (In thousands)
Beginning of period
$10,190

($85,625 )
Recognition of divestiture date fair value 7,880
—
Gain (loss) on changes in fair value, net⁽¹⁾
3,975
(16,430 )
Transfers into (out of) Level 3 —
—
End of period
$22,045

($102,055 )


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

See “Note ~~10.~~13. 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 six months ended June 30, 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 4. 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 ~~inputs.~~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 ~~carrying~~principal amounts of the Company’s senior notes and other long-term debt ~~which are designated as Level 1 under the fair value hierarchy, net of unamortized premiums and debt issuance costs,~~ with the fair values measured using quoted secondary market trading ~~prices.~~prices which are designated as Level 1 within the valuation hierarchy. See “Note 8. Long-Term Debt” for additional discussion.



	June 30, 2019				December 31, 2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)
6.25% Senior Notes due 2023		$650,000		$626,438		$650,000		$599,625
8.25% Senior Notes due 2025	250,000		244,063		250,000		244,375

June 30, 2018 December 31, 2017
Carrying Amount Fair Value Carrying Amount Fair Value
(In thousands)
7.50% Senior Notes due 2020
$129,044

$130,325

$446,087

$459,518
6.25% Senior Notes due 2023 642,446
656,500
641,792
674,375
8.25% Senior Notes due 2025 245,817
266,250
245,605
274,375
Other long-term debt due 2028 —
—
4,425
4,445

~~12.~~ ~~Condensed Consolidating Financial Information~~

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

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(In thousands)~~

~~(Unaudited)~~

June 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Assets
Total current assets
$3,128,244

$120,425

$—

($3,116,164 )
$132,505
Total property and equipment, net 6,445
2,562,799
3,028
(3,847 ) 2,568,425
Investment in subsidiaries (743,363 ) —
—
743,363
—
Other assets 8,630
12,279
—
—
20,909
Total Assets
$2,399,956

$2,695,503

$3,028

($2,376,648 )
$2,721,839

Liabilities and Shareholders’ Equity
Current liabilities
$257,137

$3,362,551

$3,028

($3,119,185 )
$503,531
Long-term liabilities 1,526,788
76,315
—
15,879
1,618,982
Preferred stock 172,858
—
—
—
172,858
Total shareholders’ equity 443,173
(743,363 ) —
726,658
426,468
Total Liabilities and Shareholders’ Equity
$2,399,956

$2,695,503

$3,028

($2,376,648 )
$2,721,839

December 31, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Assets
Total current assets
$3,441,633

$105,533

$—

($3,424,288 )
$122,878
Total property and equipment, net 5,953
2,630,707
3,028
(3,878 ) 2,635,810
Investment in subsidiaries (999,793 ) —
—
999,793
—
Other assets 9,270
10,346
—
—
19,616
Total Assets
$2,457,063

$2,746,586

$3,028

($2,428,373 )
$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities
$165,701

$3,631,401

$3,028

($3,427,308 )
$372,822
Long-term liabilities 1,689,466
114,978
—
15,879
1,820,323
Preferred stock 214,262
—
—
—
214,262
Total shareholders’ equity 387,634
(999,793 ) —
983,056
370,897
Total Liabilities and Shareholders’ Equity
$2,457,063

$2,746,586

$3,028

($2,428,373 )
$2,778,304

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING STATEMENTS OF INCOME~~

~~(In thousands)~~

~~(Unaudited)~~

Three Months Ended June 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$19

$263,954

$—

$—

$263,973
Total costs and expenses 106,335
121,869
—
(23 ) 228,181
Income (loss) before income taxes (106,316 ) 142,085
—
23
35,792
Income tax expense —
(483 ) —
—
(483 )
Equity in income of subsidiaries 141,602
—
—
(141,602 ) —
Net income
$35,286

$141,602

$—

($141,579 )
$35,309
Dividends on preferred stock (4,474 ) —
—
—
(4,474 )
Accretion on preferred stock (740 ) —
—
—
(740 )
Loss on redemption of preferred stock —
—
—
—
—
Net income attributable to common shareholders
$30,072

$141,602

$—

($141,579 )
$30,095

Three Months Ended June 30, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$174

$166,309

$—

$—

$166,483
Total costs and expenses 7,731
102,415
—
31
110,177
Income (loss) before income taxes (7,557 ) 63,894
—
(31 ) 56,306
Income tax expense —
—
—
—
—
Equity in income of subsidiaries 63,894
—
—
(63,894 ) —
Net income
$56,337

$63,894

$—

($63,925 )
$56,306
Dividends on preferred stock —
—
—
—
—
Accretion on preferred stock —
—
—
—
—
Loss on redemption of preferred stock —
—
—
—
—
Net income attributable to common shareholders
$56,337

$63,894

$—

($63,925 )
$56,306

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING STATEMENTS OF INCOME~~

~~(In thousands)~~

~~(Unaudited)~~

Six Months Ended June 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$39

$489,214

$—

$—

$489,253
Total costs and expenses 193,700
231,982
—
(32 ) 425,650
Income (loss) before income taxes (193,661 ) 257,232
—
32
63,603
Income tax expense —
(802 ) —
—
(802 )
Equity in income of subsidiaries 256,430
—
—
(256,430 ) —
Net income
$62,769

$256,430

$—

($256,398 )
$62,801
Dividends on preferred stock (9,337 ) —
—
—
(9,337 )
Accretion on preferred stock (1,493 ) —
—
—
(1,493 )
Loss on redemption of preferred stock (7,133 ) —
—
—
(7,133 )
Net income attributable to common shareholders
$44,806

$256,430

$—

($256,398 )
$44,838

Six Months Ended June 30, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$256

$317,582

$—

$—

$317,838
Total costs and expenses 26,599
194,871
—
41
221,511
Income (loss) before income taxes (26,343 ) 122,711
—
(41 ) 96,327
Income tax expense —
—
—
—
—
Equity in income of subsidiaries 122,711
—
—
(122,711 ) —
Net income
$96,368

$122,711

$—

($122,752 )
$96,327
Dividends on preferred stock —
—
—
—
—
Accretion on preferred stock —
—
—
—
—
Loss on redemption of preferred stock —
—
—
—
—
Net income attributable to common shareholders
$96,368

$122,711

$—

($122,752 )
$96,327

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~(In thousands)~~

~~(Unaudited)~~

Six Months Ended June 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Net cash provided by (used in) operating activities
($158,309 )
$434,181

$—

$—

$275,872
Net cash provided by (used in) investing activities 348,235
(84,355 ) —
(349,826 ) (85,946 )
Net cash used in financing activities (197,367 ) (349,826 ) —
349,826
(197,367 )
Net decrease in cash and cash equivalents (7,441 ) —
—
—
(7,441 )
Cash and cash equivalents, beginning of period 9,540
—
—
—
9,540
Cash and cash equivalents, end of period
$2,099

$—

$—

$—

$2,099

Six Months Ended June 30, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Net cash provided by (used in) operating activities
($77,501 )
$256,656

$—

$—

$179,155
Net cash used in investing activities (109,780 ) (364,887 ) —
108,231
(366,436 )
Net cash provided by financing activities 185,315
108,231
—
(108,231 ) 185,315
Net decrease in cash and cash equivalents (1,966 ) —
—
—
(1,966 )
Cash and cash equivalents, beginning of period 4,194
—
—
—
4,194
Cash and cash equivalents, end of period
$2,228

$—

$—

$—

$2,228

~~13.~~15. Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2019		2018
	(In thousands)
Operating activities:
Cash paid for interest, net of amounts capitalized		$34,475		$29,853
Cash paid for income taxes	590		—

Investing activities:
Increase (decrease) in capital expenditure payables and accruals		$28,428		$35,543

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	3,417		4,416
Asset retirement obligations capitalized to oil and gas properties	3,324		691

Supplemental non-cash financing activities:
Non-cash loss on extinguishment of debt, net		$—		$2,666

Six Months Ended
June 30,
2018 2017
(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized
$29,853

$39,603

Non-cash investing activities:
Increase in capital expenditure payables and accruals
$35,543

$48,395
Contingent consideration arrangement related to divestitures of oil and gas properties (7,880 ) —

~~14.~~16. Subsequent Events

~~Divestiture of Non-Operated Delaware Basin Assets~~

InOn July 2018, the Company closed on the divestiture of certain non-operated assets in the Delaware Basin for estimated aggregate net proceeds of $31.4 million. The proceeds from this divestiture will be recognized as a reduction of proved oil and gas properties.

~~Hedging~~

~~In August 2018,~~14, 2019, the Company entered into the ~~following crude oil derivative positions at the weighted average contract prices summarized below:~~Merger Agreement with Callon. See “Note 1. Nature of Operations” for further discussion.

Period Type of Contract Index
Volumes
(Bbls/d)

Fixed Price
($/Bbl)
2019
Q1 Basis Swaps
Midland WTI-Cushing WTI ⁽¹⁾
2,500

($6.94 )
Q2 Basis Swaps
Midland WTI-Cushing WTI ⁽¹⁾
3,000
(6.94 )
Q3 Basis Swaps
Midland WTI-Cushing WTI ⁽¹⁾
3,500
(6.94 )
Q4 Basis Swaps
Midland WTI-Cushing WTI ⁽¹⁾
5,000
(4.00 )
2020
Q1 Basis Swaps
Midland WTI-Cushing WTI ⁽¹⁾
1,000
(1.90 )


~~(1)~~	~~The index price paid under these basis swaps is Midland WTI and the index price received is Cushing WTI less the fixed price differential.~~

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

The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our ~~2017~~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

~~Second Quarter 2018 Highlights~~Recent Developments

~~Total production for the~~ ~~three months ended June 30,2018~~ ~~was 57,077 Boe/d,~~On July 14, 2019, we entered into an ~~increase~~Agreement and Plan of ~~12% from the~~ ~~three months ended June 30,~~ ~~2017, primarily due~~Merger (the “Merger Agreement”) with Callon Petroleum Company (“Callon”). Pursuant to the ~~addition~~Merger Agreement, we will be merged with and into Callon, with Callon continuing as the surviving entity (the “Merger”). The closing of ~~production from~~ the ~~ExL Acquisition in the third quarter of 2017, partially offset by the divestitures in the Utica and Marcellus Shales~~Merger is expected to occur in the fourth quarter of ~~2017~~2019, subject to approvals from the common shareholders of Carrizo and Callon and other certain conditions. Subject to the ~~Niobrara Formation~~terms and conditions set forth in the Merger Agreement, upon closing of the Merger, each share of our common stock issued and outstanding immediately prior to the effective time of the Merger will automatically be converted into the right to receive 2.05 shares of Callon’s common stock. See “Note 1. Nature of Operations” and “Part II. Other Information—Item 1A. Risk Factors” for further discussion.

In light of the proposed Merger, we do not, in general, plan to provide or update guidance and long-term outlook information regarding our results of operations during the pendency of the merger. In addition, investors are cautioned not to rely on historical forward-looking statements regarding guidance and long-term outlook information, as they were as of the date provided and were subject to the specific risks and uncertainties that accompanied such statements.

Second Quarter 2019 Highlights

Total production for the three months ended June 30, 2019 was 65,643 Boe/d, an increase of 15% from the three months ended June 30, 2018, primarily due to production from new wells in the Eagle Ford ~~in the first quarter of 2018~~ and Delaware Basin, partially offset by normal production ~~declines.~~

decline.

Operated drilling and completion activity for the three months ended June 30, ~~2018~~2019, along with our drilled but uncompleted and producing wells as of June 30, ~~2018~~2019, are summarized in the table below.


	Three Months Ended June 30, 2018				June 30, 2018				Three Months Ended June 30, 2019				June 30, 2019
	Drilled		Completed		Drilled But Uncompleted		Producing		Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	19	17.7	18	15.6	15	14.0	485	434.9	11	9.9	30	27.2	23	21.2	580	519.6
Delaware Basin	9	7.8	12	9.3	10	8.6	46	37.6	6	4.7	3	3.0	10	8.5	92	79.7
Total	28	25.5	30	24.9	25	22.6	531	472.5	17	14.6	33	30.2	33	29.7	672	599.3

Drilling and completion expenditures for the second quarter of ~~2018~~2019 were ~~$218.0~~$131.1 million, of which ~~nearly 55% was~~approximately 66% were in the ~~Delaware Basin~~Eagle Ford with the balance in the ~~Eagle Ford.~~ Delaware Basin.

We ~~currently expect~~recorded net income attributable to ~~operate an average of six rigs, with four located in the Eagle Ford and two located in the Delaware Basin, and 2-3 completion crews~~common shareholders for the ~~remainder~~three months ended June 30, 2019 of ~~2018. Given the faster cycle times in the Eagle Ford,~~$102.2 million, or $1.10 per diluted share, as ~~well as the Company’s decision~~compared to maintain a six rig program for the remainder of the year, our current 2018 drilling, completion, and infrastructure capital expenditure plan has been increased from $750.0 million to $800.0 million to $800.0 million to $825.0 million. See “—Liquidity and Capital Resources—2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy” for additional details.

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

~~We recorded~~ net income attributable to common shareholders for the three months ended June 30, 2018 of $30.1 million, or $0.36 per diluted ~~share, as compared to~~share. The increase in net income attributable to common shareholders was driven primarily by a gain on derivatives, net of approximately $20.4 million during the second quarter of 2019 compared to a loss on derivatives, net of approximately $67.7 million during the second quarter of 2018. Although total production for the three months ended June 30, ~~2017 of $56.3 million, or $0.85 per diluted share. The reduction in net income attributable to common shareholders~~2019 increased 15% from the three months ended June 30, 2018, the average realized price for the ~~second quarter of 2018~~three months ended June 30, 2019 decreased 13% as compared to the ~~net income attributable to common shareholders for the second quarter of 2017 was driven primarily by a loss on derivatives, net of $67.7 million~~three months ended June 30, 2018 resulting in the second quarter of 2018 as compared to a gain on derivatives, net of $26.1 million in the second quarter of 2017 and an increase in our depreciation, depletion and amortization (“DD&A”) expense for the second quarter of 2018 due to the addition of proved oil and gas properties related to the ExL Acquisition and increased production, partially offset by higher production volumes and commodity prices in the second quarter of 2018 compared to the second quarter of 2017.total revenue remaining relatively flat. See “—Results of Operations” below for further details.

~~Recent Developments~~

~~In July 2018, we closed on the divestiture of certain non-operated assets in the Delaware Basin for estimated aggregate net proceeds of $31.4 million.~~

Results of Operations

Comparison of Results Between The Three Months Ended June 30,2019 and 2018~~, Compared to the~~ ~~Three~~And The Six Months Ended June 30, ~~2017~~2019 and 2018

Production volumes

The following table summarizes total production volumes and daily production volumes ~~average realized prices and revenues~~ for the periods indicated:



	Three Months Ended June 30,		Amount Change Between Periods		Percent Change Between Periods		Six Months Ended June 30,		Amount Change Between Periods		Percent Change Between Periods
	2019	2018	Amount Change Between Periods		Percent Change Between Periods		2019	2018	Amount Change Between Periods		Percent Change Between Periods
Total production volumes
Crude oil (MBbls)	4,042	3,445	597		17	%	7,707	6,517	1,190		18	%
NGLs (MBbls)	949	853	96		11	%	1,840	1,593	247		16	%
Natural gas (MMcf)	5,897	5,372	525		10	%	12,015	10,182	1,833		18	%
Total barrels of oil equivalent (MBoe)	5,974	5,193	781		15	%	11,550	9,807	1,743		18	%

Daily production volumes by product
Crude oil (Bbls/d)	44,413	37,860	6,553		17	%	42,580	36,008	6,572		18	%
NGLs (Bbls/d)	10,429	9,379	1,050		11	%	10,168	8,800	1,368		16	%
Natural gas (Mcf/d)	64,805	59,029	5,776		10	%	66,382	56,252	10,130		18	%
Total barrels of oil equivalent (Boe/d)	65,643	57,077	8,566		15	%	63,812	54,183	9,629		18	%

Daily production volumes by region (Boe/d)
Eagle Ford	41,370	37,039	4,331		12	%	40,456	36,335	4,121		11	%
Delaware Basin	24,273	19,783	4,490		23	%	23,356	17,522	5,834		33	%
Other	—	255	(255	)	(100	%)	—	326	(326	)	(100	%)
Total barrels of oil equivalent (Boe/d)	65,643	57,077	8,566		15	%	63,812	54,183	9,629		18	%

The increase in production volumes for the three and six months ended June 30,~~2018~~ 2019 compared to the three and ~~2017:~~

Three Months Ended
June 30, 2018 Period
Compared to 2017 Period
2018 2017 Increase (Decrease) % Increase (Decrease)
Total production volumes -
    Crude oil (MBbls) 3,445
3,060
385
13 %
    NGLs (MBbls) 853
453
400
88 %
    Natural gas (MMcf) 5,372
6,775
(1,403 ) (21 %)
Total barrels of oil equivalent (MBoe) 5,193

4,643
550
12 %

Daily production volumes by product -
    Crude oil (Bbls/d) 37,860
33,629
4,231
13 %
    NGLs (Bbls/d) 9,379
4,982
4,397
88 %
    Natural gas (Mcf/d) 59,029
74,451
(15,422 ) (21 %)
Total barrels of oil equivalent (Boe/d) 57,077
51,019
6,058
12 %

Daily production volumes by region (Boe/d) -
    Eagle Ford 37,039
38,055
(1,016 ) (3 %)
    Delaware Basin 19,783
2,151
17,632
820 %
    Other 255
10,813
(10,558 ) (98 %)
Total barrels of oil equivalent (Boe/d) 57,077
51,019
6,058
12 %

Average realized prices -
    Crude oil ($ per Bbl)
$66.70

$46.67

$20.03
43 %
    NGLs ($ per Bbl) 24.93
17.19
7.74
45 %
    Natural gas ($ per Mcf) 2.40
2.35
0.05
2 %
Total average realized price ($ per Boe)
$50.83

$35.86

$14.97
42 %

Revenues (In thousands) -
    Crude oil
$229,798

$142,806

$86,992
61 %
    NGLs 21,269
7,786
13,483
173 %
    Natural gas 12,906
15,891
(2,985 ) (19 %)
Total revenues
$263,973

$166,483

$97,490
59 %

~~Production volumes for the three~~six months ended June 30, 2018 ~~were 57,077 Boe/d, an increase of 12% from 51,019 Boe/d for the same period in 2017. The increase~~ is primarily due to production from new wells in the Eagle Ford and ~~the addition of production from the ExL Acquisition in the third quarter of 2017,~~Delaware Basin, partially offset by ~~the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in the first quarter of 2018 and~~ normal production ~~declines. Revenues~~decline.

Average realized prices and revenues

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



	Three Months Ended June 30,				Amount Change Between Periods			Percent Change Between Periods		Six Months Ended June 30,				Amount Change Between Periods			Percent Change Between Periods
	2019		2018		Amount Change Between Periods			Percent Change Between Periods		2019		2018		Amount Change Between Periods			Percent Change Between Periods
Average realized prices
Crude oil ($ per Bbl)		$60.67		$66.70		($6.03	)	(9	%)		$58.12		$65.17		($7.05	)	(11	%)
NGLs ($ per Bbl)	14.92		24.93		(10.01		)	(40	%)	16.85		23.96		(7.11		)	(30	%)
Natural gas ($ per Mcf)	0.95		2.40		(1.45		)	(60	%)	1.59		2.59		(1.00		)	(39	%)
Total average realized price ($ per Boe)		$44.35		$50.83		($6.48	)	(13	%)		$43.12		$49.89		($6.77	)	(14	%)

Revenues (In thousands)
Crude oil		$245,212		$229,798		$15,414		7	%		$447,956		$424,717		$23,239		5	%
NGLs	14,159		21,269		(7,110		)	(33	%)	30,996		38,171		(7,175		)	(19	%)
Natural gas	5,596		12,906		(7,310		)	(57	%)	19,055		26,365		(7,310		)	(28	%)
Total revenues		$264,967		$263,973		$994		—	%		$498,007		$489,253		$8,754		2	%

The increase in revenues for the three months ended June 30, ~~2018 increased 59% to $264.0 million~~2019 compared to ~~$166.5 million for~~ the same period in ~~2017~~2018 is primarily due to higher crude oil ~~prices~~production, partially offset by lower crude oil, NGL, and ~~increased~~natural gas prices.

The increase in revenues for the six months ended June 30, 2019 compared to the same period in 2018 is primarily due to higher crude oil production, partially offset by lower crude oil and NGL ~~production, primarily as a result of~~prices.

Lease operating expense

The following table summarizes lease operating expense for the ~~ExL Acquisition.~~periods indicated:

~~Lease~~



	Three Months Ended June 30,								Six Months Ended June 30,
	2019				2018				2019				2018
	(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe		Amount		Per Boe		Amount		Per Boe
Lease operating expense		$44,514		$7.45		$35,151		$6.77		$86,545		$7.49		$74,424		$7.59

The increase in lease operating expenses for the three months ended June 30, 2018 decreased to $35.2 million ($6.77 per Boe) from $36.0 million ($7.76 per Boe) for the same period in 2017. The decrease in lease operating expenses is primarily due to a reduction in workover costs for the three months ended June 30, 2018 when2019 compared to the same period in ~~2017.~~2018 is primarily due to costs associated with increased production. The increase in lease operating expense per Boe is primarily due to increased workover activity primarily in the Eagle Ford.

The increase in lease operating expenses for the six months ended June 30, 2019 compared to the same period in 2018 is primarily due to costs associated with increased production. The decrease in lease operating expense per Boe is primarily due to ~~the addition~~an increased proportion of production from wells drilled on properties acquired in the ExL Acquisition, ~~beginning in the third quarter of 2017,~~ which ~~has a~~have lower operating ~~cost~~costs per Boe than our other ~~crude oil properties, partially offset by an increased proportion of total~~Delaware Basin and Eagle Ford properties.

Production and ad valorem taxes

The following table summarizes production ~~from crude oil properties, which have a higher operating cost per Boe than natural gas properties, as a result of~~and ad valorem taxes for the ~~divestiture~~periods indicated:



	Three Months Ended June 30,								Six Months Ended June 30,
	2019				2018				2019				2018
	(In thousands, except % of revenues amounts)
	Amount		% of Revenues		Amount		% of Revenues		Amount		% of Revenues		Amount		% of Revenues
Production and ad valorem taxes		$17,793	6.7	%		$16,127	6.1	%		$32,687	6.6	%		$28,675	5.9	%

The increase in ~~the Marcellus Shale in the fourth quarter of 2017,~~production and ad valorem taxes, as well as ~~processing fees for certain~~the increase of ~~our natural gas~~production and ~~NGL processing contracts that are now presented in lease operating expenses~~ad valorem taxes as a ~~result~~percent of ~~the adoption of ASC 606.~~

~~Production taxes increased to $12.5 million (or 4.7% of revenues)~~revenues, for the three and six months ended June 30, 2019 compared to the three and six months ended June 30, 2018 ~~from $7.1 million (or 4.3% of revenues) for the same period in 2017~~is primarily due to increased ad valorem taxes as a result of the increase in crude oil and NGL revenues. The increase in production taxes as a percentage of revenues is primarily due to the divestiture of substantially all of our assets in the Marcellus Shale in the fourth quarter of 2017, as production in Marcellus was not subject to production taxes.

~~Ad valorem taxes increased to $3.6 million for the three months ended June 30, 2018 from $1.1 million for the same period in 2017. The increase in ad valorem taxes is due to~~ new wells drilled in the Eagle Ford and ~~new wells drilled or acquired in the~~ Delaware Basin ~~as well as an increase in our annual estimate of ad valorem taxes for 2018 due to~~and higher ~~expected~~ property tax valuations as a result of the increase in crude oil ~~prices.~~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 June 30,								Six Months Ended June 30,
	2019				2018				2019				2018
	(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe		Amount		Per Boe		Amount		Per Boe
DD&A of proved oil and gas properties		$79,352		$13.28		$71,346		$13.74		$153,352		$13.28		$134,676		$13.73
Depreciation of other property and equipment	722		0.12		613		0.12		1,422		0.12		1,194		0.12
Amortization of other assets	198		0.04		140		0.03		418		0.03		374		0.04
Accretion of asset retirement obligations	494		0.08		331		0.06		896		0.08		653		0.07
DD&A		$80,766		$13.52		$72,430		$13.95		$156,088		$13.51		$136,897		$13.96

DD&A expense for the ~~second quarter of 2018~~three and six months ended June 30, 2019 increased ~~$13.4~~$8.3 million and $19.2 million, respectively, compared to ~~$72.4 million ($13.95 per Boe) from~~ the ~~DD&A expense for the second quarter of 2017 of $59.1 million ($12.72 per Boe).~~three and six months ended June 30, 2018. The increase in DD&A expense is attributable to increased production, ~~and an increase~~partially offset by the decrease in the DD&A rate per Boe. The ~~increase~~decrease in the DD&A rate per Boe is due primarily to ~~increases in future development cost assumptions that occurred subsequent to the second quarter~~an increased proportion of ~~2017 as well as an increase to~~ proved oil and gas ~~properties related to the ExL Acquisition~~reserves in the ~~third quarter of 2017, partially offset by the reduction in~~Delaware Basin which carry a lower DD&A rate per Boe as compared to our proved oil and gas ~~properties as a result of the divestitures~~reserves in the ~~Utica and Marcellus Shales~~Eagle Ford, as well as decreased future development costs in the ~~fourth quarter of 2017 and the Niobrara Formation and~~ Eagle Ford ~~in the first quarter of~~and Delaware Basin subsequent to June 30, 2018. ~~The components of our DD&A expense were as follows:~~

Three Months Ended
June 30,
2018 2017
(In thousands)
DD&A of proved oil and gas properties
$71,346

$57,695
Depreciation of other property and equipment 613
612
Amortization of other assets 140
321
Accretion of asset retirement obligations 331
444
Total DD&A
$72,430

$59,072

General and administrative expense, net ~~increased to $18.3 million~~

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(In thousands)
General and administrative expense, net		$17,301		$18,265		$42,033		$45,557

The decrease in general and administrative expense, net for the three months ended June 30, ~~2018 from $11.6 million for the corresponding period in 2017. The increase~~2019 was primarily due ~~to an increase~~a decrease in stock-based compensation expense, net as a result of ~~an increase~~a decrease in the fair value of ~~stock appreciation rights~~Cash SARs for the three months ended June 30, ~~2018~~2019 as compared to ~~a decrease~~an increase in fair value for the same period in ~~2017.~~2018.

~~We recorded~~The decrease in general and administrative expense, net for the six months ended June 30, 2019 was primarily due to lower annual bonuses awarded in the first quarter of 2019 as compared to the first quarter of 2018 as well as a decrease in stock-based compensation expense, net as a result of a decrease in the fair value of Cash SARs for the six months ended June 30, 2019 as compared to an increase in fair value for the same period in 2018.

(Gain) loss on derivatives, net

The following table sets forth the components of ~~$67.7 million and a~~our loss on derivatives, net for the periods indicated:



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
	(In thousands)
Crude oil derivative instruments		($20,915	)		$53,437		$41,846			$82,948
NGL derivative instruments	—			6,564		(6		)	4,799
Natural gas derivative instruments	(1,600		)	153		(3,670		)	(2,892		)
Contingent consideration arrangements	2,066			7,560		24,665			12,455
(Gain) loss on derivatives, net		($20,449	)		$67,714		$62,835			$97,310

The gain on derivatives, net ~~of $26.1 million~~ for the three months ended June 30, ~~2018~~2019 was primarily due to new crude oil derivative instruments executed during the second quarter of 2019 as well as the downward shift in the futures curve of forecasted crude oil and ~~2017, respectively. The components~~natural gas prices from April 1, 2019 to June 30, 2019 on crude oil and natural gas derivative instruments outstanding at the beginning of ~~our (gain)~~the second quarter of 2019.

The loss on derivatives, ~~net were as follows:~~

Three Months Ended
June 30,
2018 2017
(In thousands)
Crude oil derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period
$59,602

($10,122 )
Gain due to new derivative positions executed during the period (6,165 ) (19,614 )
Loss due to deferred premium obligations incurred —
7,554
NGL derivative positions:
Loss due to upward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period 6,564
—
Natural gas derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period 153
(3,883 )
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period 7,560
—
(Gain) loss on derivatives, net
$67,714

($26,065 )

~~Interest expense,~~ net for the three months ended June 30, 2018 was ~~$15.6 million as~~primarily due to the upward shift in the futures curve of forecasted crude oil and NGL prices from April 1, 2018 to June 30, 2018 on crude oil and NGL derivative instruments outstanding at the beginning of the second quarter of 2018 and on our Contingent ExL Consideration, partially offset by new crude oil derivative instruments executed during the second quarter of 2018.

The loss on derivatives, net for the six months ended June 30, 2019 was primarily due to the upward shift in the futures curve of forecasted crude oil prices from January 1, 2019 to June 30, 2019 on crude oil derivative instruments outstanding at the beginning of 2019 and on our Contingent ExL Consideration, partially offset by new crude oil and natural gas derivative instruments executed during 2019.

The loss on derivatives, net for the six months ended June 30, 2018 was primarily due to the upward shift in the futures curve of forecasted crude oil and NGL prices from January 1, 2018 to June 30, 2018 on crude oil and NGL derivative instruments outstanding at the beginning of 2018 and on our Contingent ExL Consideration, partially offset by new crude oil derivative instruments executed during 2018 and the downward shift in the futures curve of forecasted natural gas prices from January 1, 2018 to June 30, 2018 on natural gas derivative instruments outstanding at the beginning of 2018.

Interest expense, net

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands)
Interest expense on Senior Notes		$15,313			$17,767			$30,625			$39,253
Interest expense on revolving credit facility	10,159			5,490			19,213			8,649
Amortization of premiums and debt issuance costs	986			937			1,918			2,040
Other interest expense	138			133			284			270
Interest capitalized	(8,572		)	(8,728		)	(17,565		)	(19,096		)
Interest expense, net		$18,024			$15,599			$34,475			$31,116

The increase in interest expense, net for the three and six months ended June 30, 2019 compared to ~~$21.1 million for~~ the ~~same period in 2017. The~~three and six months ended June 30, 2018 is primarily due to increased borrowings and associated interest expense on our revolving credit facility as well as the decrease ~~was due primarily to an increase~~ in capitalized interest as a result of a lower weighted average interest rate driven by the higher ~~average balances~~proportion of ~~unevaluated leasehold and seismic costs for~~borrowings on our revolving credit facility, which carries a lower interest rate than the ~~three months ended June 30, 2018 as compared to the three months ended June 30, 2017, primarily as a result of the ExL Acquisition in the third quarter of 2017, as well as~~Senior Notes. These increases were partially offset by reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the first and fourth ~~quarter of 2017 and first quarter~~quarters of 2018. ~~The decrease was partially offset by interest expense~~

Loss on ~~$250.0 million aggregate principal amount~~extinguishment of our 8.25% Senior Notes that were issued in the third quarter of 2017 and an increase in interest expense on our revolving credit facility as a result of increased borrowings for the three months ended June 30, 2018 as compared to the three months ended June 30, 2017. The components of our interest expense, net were as follows:

Three Months Ended
June 30,
2018 2017
(In thousands)
Interest expense on Senior Notes
$17,767

$21,455
Interest expense on revolving credit facility 5,490
2,261
Amortization of premiums and debt issuance costs 937
1,079
Other interest expense 133
298
Interest capitalized (8,728 ) (3,987 )
Interest expense, net
$15,599

$21,106

The effective income tax rates for the second quarter of 2018 and 2017 were 1.3% and 0.0%, respectively. The variance in the effective income tax rate results from current state and deferred income tax expense of $0.5 million recognized during the second quarter of 2018. The tax expense was driven by changes to our state apportionment for estimated state deferred tax liabilities as a result of the significant changes in our areas of operation that occurred in late 2017 and early 2018, whereby all remaining operations are located in Texas. The effective income tax rate was 0.0% during the second quarter of 2017 as a result of a full valuation allowance against our net deferred tax assets driven by impairments of proved oil and gas properties recognized in the third quarter of 2015 and continuing through the third quarter of 2016.

For the three months ended June 30, 2018, we declared and paid $4.5 million of cash dividends on our Preferred Stock, which reduced net income to compute net income attributable to common shareholders.

~~Results of Operations~~

~~Six Months Ended June 30, 2018, Compared to the Six Months Ended June 30, 2017~~

~~The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the six months ended June 30, 2018 and 2017:~~

Six Months Ended
June 30, 2018 Period
Compared to 2017 Period
2018 2017 Increase (Decrease) % Increase (Decrease)
Total production volumes -
    Crude oil (MBbls) 6,517
5,656
861
15 %
    NGLs (MBbls) 1,593
859
734
85 %
    Natural gas (MMcf) 10,182
13,803
(3,621 ) (26 %)
Total barrels of oil equivalent (MBoe) 9,807
8,816
991
11 %

Daily production volumes by product -
    Crude oil (Bbls/d) 36,008
31,250
4,758
15 %
    NGLs (Bbls/d) 8,800
4,746
4,054
85 %
    Natural gas (Mcf/d) 56,252
76,260
(20,008 ) (26 %)
Total barrels of oil equivalent (Boe/d) 54,183
48,706
5,477
11 %

Daily production volumes by region (Boe/d) -
    Eagle Ford 36,335
35,332
1,003
3 %
    Delaware Basin 17,522
2,284
15,238
667 %
    Other 326
11,090
(10,764 ) (97 %)
Total barrels of oil equivalent (Boe/d) 54,183
48,706
5,477
11 %

Average realized prices -
    Crude oil ($ per Bbl)
$65.17

$47.90

$17.27
36 %
    NGLs ($ per Bbl) 23.96
17.71
6.25
35 %
    Natural gas ($ per Mcf) 2.59
2.30
0.29
13 %
Total average realized price ($ per Boe)
$49.89

$36.05

$13.84
38 %

Revenues (In thousands) -
    Crude oil
$424,717

$270,898

$153,819
57 %
    NGLs 38,171
15,211
22,960
151 %
    Natural gas 26,365
31,729
(5,364 ) (17 %)
Total revenues
$489,253

$317,838

$171,415
54 %

Production volumes for the six months ended June 30, 2018 were 54,183 Boe/d, an increase of 11% from 48,706 Boe/d for the same period in 2017. The increase is primarily due to production from new wells in the Eagle Ford and the addition of production from the ExL Acquisition in the third quarter of 2017, partially offset by the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in the first quarter of 2018 and normal production declines. Revenues for the six months ended June 30, 2018 increased 54% to $489.3 million from $317.8 million for the same period in 2017 primarily due to higher crude oil prices and increased crude oil and NGL production, primarily as a result of the ExL Acquisition.

Lease operating expenses for the six months ended June 30, 2018 increased to $74.4 million ($7.59 per Boe) from $65.9 million ($7.47 per Boe) for the same period in 2017. The increase in lease operating expenses is primarily due to costs associated with new wells completed in the Eagle Ford and Delaware Basin since the second quarter of 2017, partially offset by the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in the first quarter of 2018. The increase in lease operating expense per Boe is primarily due to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties, as a result of the divestiture in the Marcellus Shale in the fourth quarter of 2017 as well as processing fees for certain of our natural gas and NGL processing contracts that are now presented in lease operating expenses as a result of the adoption of ASC 606.

Production taxes increased to $23.1 million (or 4.7% of revenues) for the six months ended June 30, 2018 from $13.4 million (or 4.2% of revenues) for the same period in 2017 primarily as a result of the increase in crude oil and NGL revenues. The increase in production taxes as a percentage of revenues is primarily due to the divestiture of substantially all of our assets in the Marcellus Shale in the fourth quarter of 2017, as production in Marcellus was not subject to production taxes.

Ad valorem taxes increased to $5.6 million for the six months ended June 30, 2018 from $4.0 million for the same period in 2017. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and new wells drilled or acquired in the Delaware Basin as well as an increase in our annual estimate of ad valorem taxes for 2018 due to higher expected property tax valuations as a result of the increase in crude oil prices.

DD&A expense for the six months ended June 30, 2018 increased $23.4 million to $136.9 million ($13.96 per Boe) from $113.5 million ($12.87 per Boe) for the same period in 2017. The increase in DD&A expense is attributable to increased production as well as an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is due primarily to increases in future development cost assumptions that occurred subsequent to the second quarter of 2017 as well as an increase to proved oil and gas properties related to the ExL Acquisition in the third quarter of 2017, partially offset by the reduction in proved oil and gas properties as a result of the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in the first quarter of 2018. The components of our DD&A expense were as follows:

Six Months Ended
June 30,
2018 2017
(In thousands)
DD&A of proved oil and gas properties
$134,676

$110,655
Depreciation of other property and equipment 1,194
1,258
Amortization of other assets 374
672
Accretion of asset retirement obligations 653
869
Total DD&A
$136,897

$113,454

General and administrative expense, net increased to $45.6 million for the six months ended June 30, 2018 from $33.3 million for the same period in 2017. The increase was primarily due to an increase in stock-based compensation expense, net as a result of an increase in the fair value of stock appreciation rights for the six months ended June 30, 2018 compared to a decrease in fair value for the six months ended June 30, 2017 as well as an increase in personnel costs and higher annual bonuses awarded in the first quarter of 2018 compared to the first quarter of 2017.

We recorded a loss on derivatives, net of $97.3 million and a gain on derivatives, net of $51.4 million for the six months ended June 30, 2018 and 2017, respectively. The components of our (gain) loss on derivatives, net were as follows:

Six Months Ended
June 30,
2018 2017
(In thousands)
Crude oil derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period
$89,802

($28,549 )
Gain due to new derivative positions executed during the period (6,854 ) (19,614 )
Loss due to deferred premium obligations incurred —
7,501
NGL derivative positions:
Loss due to upward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period 4,799
—
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period (2,641 ) (10,719 )
Gain due to new derivative positions executed during the period (251 ) —
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period 12,455
—
(Gain) loss on derivatives, net
$97,310

($51,381 )

Interest expense, net for the six months ended June 30, 2018 was $31.1 million as compared to $41.7 million for the same period in 2017. The decrease was due primarily to an increase in capitalized interest as a result of higher average balances of

unevaluated leasehold and seismic costs for the six months ended June 30, 2018 as compared to the six months ended June 30, 2017, primarily as a result of the ExL Acquisition in the third quarter of 2017, as well as reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the fourth quarter of 2017 and first quarter of 2018. The decrease was partially offset by interest expense on $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in the third quarter of 2017 and an increase in interest expense on our revolving credit facility as a result of increased borrowings for the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. The components of our interest expense, net were as follows:

Six Months Ended
June 30,
2018 2017
(In thousands)
Interest expense on Senior Notes
$39,253

$42,910
Interest expense on revolving credit facility 8,649
3,687
Amortization of debt issuance costs, premiums, and discounts 2,040
2,265
Other interest expense 270
583
Capitalized interest (19,096 ) (7,768 )
Interest expense, net
$31,116

$41,677
debt

As a result of our ~~redemption~~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, ~~for the six months ended June 30, 2018,~~ 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 ~~premium~~premiums and debt issuance costs.

~~The effective~~Income taxes and deferred tax assets valuation allowance

During the first quarter of 2019, we concluded that it was more likely than not that our deferred tax assets would be realized and released a portion of the valuation allowance which was reflected in our consolidated statements of income as an income tax ~~rate~~benefit. However, for the three months ended June 30, 2019, we recognized income tax expense of $2.3 million, of which $1.4 million was as a result of changes to the forecasted timing of release of the valuation allowance related to current period activity. For the six months ended June 30, ~~2018 and 2017 was 1.3% and 0.0% respectively. The variance~~2019, we have released $177.7 million of the valuation allowance which is reflected in ~~the effective~~our consolidated statements of income as an income tax ~~rate results from current state~~benefit.

For the three and ~~deferred income tax expense of $0.8 million recognized during the~~ six months ended June 30, ~~2018. This~~2018, we recognized income tax expense of $0.5 million and $0.8 million, respectively. The income tax expense for each period was ~~due to changes to our state apportionment for estimated state deferred tax liabilities~~significantly lower than the statutory rate as a result of the significant changes in our areas of operation that occurred in late 2017 and early 2018 as well as current period activity. The effective income tax rate was 0.0% during the six months ended June 30, 2017 as a result ofmaintaining a full valuation allowance against our ~~net~~ deferred tax assets ~~driven by impairments~~based on our conclusion that it was more likely than not that the deferred tax assets would not be realized.

Dividends on preferred stock

For both the three months ended June 30, 2019 and 2018, we declared, and paid in cash, dividends of ~~proved oil and gas properties recognized in the third quarter of 2015 and continuing through the third quarter of 2016.~~$4.5 million.

For the six months ended June 30, 2019 and 2018, we declared, and paid in cash, dividends of $8.8 million and $9.3 million, ~~of cash dividends~~respectively.

Loss on ~~our Preferred Stock, which reduced net income to compute net income attributable to common shareholders.~~

~~As a result of our~~ redemption of preferred stock

During the first quarter of 2018, we redeemed 50,000 shares of Preferred Stock, ~~at $1,000.00 per share, or~~representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million ~~we recorded a loss on~~ redemption of preferred stock of $7.1 million for the six months ended June 30, 2018, which reduced net income to compute net income attributable to common shareholders. The loss on redemption of preferred stock included $0.1 million of direct costs incurred as a result of the redemptionprice and ~~a non-cash charge of $7.0 million attributable to the difference between $50.0 million, which was the consideration transferred to the holders of the Preferred Stock excluding~~ accrued and unpaid dividends ~~and~~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 ~~which was 20% of the~~redemption date carrying value of the Preferred ~~Stock on the date of redemption.~~Stock.

Liquidity and Capital Resources

~~2018 Drilling, Completion,~~See “Note 1. Nature of Operations” and ~~Infrastructure~~“Part II. Other Information—Item 1A. Risk Factors” for discussion regarding the proposed merger of Carrizo with Callon. The Merger Agreement includes restrictions on our ability to take certain actions that, among other things, may affect the matters discussed below in “—Liquidity and Capital ~~Expenditure~~Resources”.

2019 DC&I Capital Expenditures. Plan and Funding Strategy. Our ~~2018 drilling, completion, and infrastructure~~2019 DC&I capital expenditure plan as approved by our board of directors remains unchanged at $525.0 million to $575.0 million, but our expectation of the amount to be spent has been ~~increased from $750.0~~reduced to $500.0 million to ~~$800.0~~$550.0 million as a result of efficiencies that have been achieved to ~~$800.0 million to $825.0 million.~~date. We currently intend to finance the remainder of our ~~2018 drilling, completion, and infrastructure~~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 and six months ended June 30, ~~2018~~2019:

Three Months Ended Six Months Ended
March 31, 2018 June 30, 2018 June 30, 2018
(In thousands)
Drilling, completion, and infrastructure
Eagle Ford
$135,677

$101,249

$236,926
Delaware Basin 73,892
116,743
190,635
All other regions 284
—
284
Total drilling, completion, and infrastructure 209,853
217,992
427,845
Leasehold and seismic 5,520
6,129
11,649
Total Capital Expenditures ⁽¹⁾

$215,373

$224,121

$439,494



	Three Months Ended				Six Months Ended
	March 31, 2019		June 30, 2019		June 30, 2019
	(In thousands)
DC&I
Eagle Ford		$134,275		$86,514		$220,789
Delaware Basin	80,390		44,567		124,957
Other	52		28		80
Total DC&I	214,717		131,109		345,826
Leasehold and seismic	9,107		3,606		12,713
Total capital expenditures ⁽¹⁾		$223,824		$134,715		$358,539


(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 ~~drilling, completion and infrastructure~~DC&I capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the three and six months ended June 30, ~~2018,~~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 July 31, 2019, our revolving credit facility had a borrowing base of $1.35 billion, with an elected commitment amount of $1.25 billion, with $871.4 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.


•	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.

~~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 August 1, 2018, our revolving credit facility had a borrowing base of $1.0 billion, with an elected commitment amount of $900.0 million, with $513.4 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. See “Note 6. Long-Term Debt” for further details of the recent twelfth amendment.

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

~~Divestitures.~~ We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for details of the divestitures that occurred in early 2018 and “Note 14. Subsequent Events” for details of the divestiture that occurred subsequent to June 30, 2018.

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

Overview of Cash Flow Activities.Net cash provided by operating activities was ~~$275.9~~$301.8 million and ~~$179.2~~$275.9 million for the six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively. The ~~change~~increase was driven primarily by an increase in revenues as a result of higher crude oil and NGL production and ~~commodity~~ prices ~~partially offset by an increase~~and a decrease in the net cash paid for derivative settlements, partially offset by an increase in operating ~~expenses and cash general and administrative expense and an increase in working capital requirements.~~expenses.

Net cash used in investing activities was $348.3 million and $85.9 million for the six months ended June 30, 2019 and 2018, respectively. The change was primarily due to the proceeds we received in the first quarter of 2018 related to the divestitures in Eagle Ford and ~~$366.4~~Niobrara, partially offset by a decrease in cash paid for capital expenditures.

Net cash provided by financing activities was $46.5 million for the six months ended June 30, ~~2017. The change was due primarily~~2019 compared to cash received from the divestitures in the Niobrara Formation and Eagle Ford in early 2018, as well as a decrease in cash payments for acquisitions of oil and gas properties, partially offset by an increase in capital expenditures in the Delaware Basin.

~~Net~~net cash used in ~~financing activities was $197.4 million for the six months ended June 30, 2018 and net cash provided by~~ financing activities for the six months ended June 30, ~~2017 was $185.3~~2018 of $197.4 million. The ~~increase in net cash used in financing activities~~change was primarily due to payments for the redemptions of ~~the~~our 7.50% Senior Notes and ~~the~~ Preferred Stock ~~as well as dividends~~during the first quarter of 2018 and decreased borrowings, net of repayments under our revolving credit facility during the first half of 2019, partially offset by net cash paid ~~on the Preferred Stock.~~for settlements of contingent consideration arrangements in January 2019.

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

~~Revolving credit facility.~~ The borrowing base under our revolving credit facility is affected by assumptions of the administrative agent with respect to, among other things, crude oil and, 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 “—Sources and Uses of Cash—Borrowings under revolving credit facility” and “—Financing Arrangements—Senior Secured Revolving Credit Facility” for further details of our revolving credit facility.

~~Contingent consideration 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 10. Derivative Instruments” for further details of each of these contingent consideration arrangements. See also “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for details of the sensitivities to commodity price of each contingent consideration arrangement.

~~Hedging.~~ We use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted production and thereby achieve a more predictable level of cash flows to support our capital expenditure program and fixed costs.

~~The following table sets forth a summary of our outstanding crude oil derivative positions at weighted average contract prices as of August 7, 2018:~~

Period Type of Contract Index
Volumes
(Bbls/d)

Fixed Price
($/Bbl)

Sub-Floor Price
($/Bbl)

Floor Price
($/Bbl)

Ceiling Price
($/Bbl)
2018
Q3-Q4 Price Swaps NYMEX WTI 6,000

$49.55

$—

$—

$—
Q3-Q4 Three-Way Collars NYMEX WTI 24,000
—
39.38
49.06
60.14
Q3-Q4 Basis Swaps
LLS-Cushing WTI ⁽¹⁾
18,000
5.11
—
—
—
Q3-Q4 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
6,000
(0.10 ) —
—
—
Q3-Q4 Net Sold Call Options NYMEX WTI 3,388
—
—
—
71.33
2019
Q1-Q4 Three-Way Collars NYMEX WTI 15,000
—
41.00
49.72
62.48
Q1 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
5,500
(5.24 ) —
—
—
Q2 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
6,000
(5.38 ) —
—
—
Q3 Basis Swaps
Midland WTI-Cushing WTI⁽²⁾
7,000
(5.56 ) —
—
—
Q4 Basis Swaps
Midland WTI-Cushing WTI ⁽²⁾
11,000
(3.84 ) —
—
—
Q1-Q4 Net Sold Call Options NYMEX WTI 3,875
—
—
—
73.66
2020
Q1 Basis Swaps
Midland WTI-Cushing WTI⁽²⁾
1,000
(1.90 ) —
—
—
Q1-Q4 Net Sold Call Options NYMEX WTI 4,575
—
—
—
75.98

~~(1)~~•

Revolving credit facility.The ~~index price paid~~borrowing base under ~~these basis swaps~~our revolving credit facility is ~~LLS~~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 ~~index price received is Cushing WTI plus~~crude oil and natural gas prices from those used to determine our existing borrowing base. Due to the ~~fixed price differential.~~proposed Merger, our regular redetermination scheduled for the fall of 2019 was postponed to occur on or about February 14, 2020. See “Note 8. Long-Term Debt” and “—Sources and Uses of Cash—Borrowings under revolving credit facility” for further details of our revolving credit facility.

~~(2)~~•

~~The index~~

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 13. 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 ~~paid under these basis swaps is Midland WTI~~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 ~~the index price received is Cushing WTI less the fixed price differential.~~achieve a more predictable level of cash flow.

~~The~~As of August 2, 2019, we had the following ~~table sets forth a summary of our~~ outstanding ~~NGL~~commodity derivative ~~positions~~instruments at weighted average contract ~~prices as of August 7, 2018:~~volumes and prices:

~~The following table sets forth a summary of our outstanding natural gas derivative positions at weighted average contract prices as of August 7, 2018:~~



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	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	3Q19	Basis Swaps	Waha-NYMEX Henry Hub	42,500	—	—	—	—			($1.49	)
Natural gas	3Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—

Natural gas	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	42,500	—	—	—	—			($1.30	)
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 ~~2018 drilling, completion, and infrastructure~~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 ~~2018 drilling, completion, and infrastructure~~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.

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of June 30, ~~2018~~2019 (in thousands):

July - December 2018 2019 2020 2021 2022 2023 and Thereafter Total
Long-term debt ⁽¹⁾

$—

$—

$130,000

$—

$485,000

$900,000

$1,515,000
Cash interest on senior notes ⁽²⁾
35,500
71,000
71,000
61,250
61,250
82,188
382,188
Cash interest and commitment fees on revolving credit facility ⁽³⁾
10,332
20,214
20,214
20,214
6,963
—
77,937
Capital leases 900
1,800
1,050
—
—
—
3,750
Operating leases 2,330
3,461
4,219
3,702
3,639
24,658
42,009
Drilling rig contracts ⁽⁴⁾
20,200
18,677
1,196
—
—
—
40,073
Delivery commitments ⁽⁵⁾
1,861
3,706
2,786
2,467
30
26
10,876
Produced water disposal commitments ⁽⁶⁾
5,283
18,599
18,698
18,708
18,764
17,453
97,505
Asset retirement obligations and other ⁽⁷⁾
1,833
2,972
657
376
239
15,745
21,822
Total Contractual Obligations ⁽⁸⁾

$78,239

$140,429

$249,820

$106,717

$575,885

$1,040,070

$2,191,160



	July - December 2019		2020		2021		2022		2023		2024 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$—		$841,328		$650,000		$250,000		$1,741,328
Cash interest on senior notes ⁽²⁾	30,625		61,250		61,250		61,250		40,938		41,250		296,563
Cash interest and commitment fees on revolving credit facility ⁽³⁾	18,436		36,873		36,873		12,701		—		—		104,883
Operating leases - other ⁽⁴⁾	5,401		10,125		6,921		3,697		3,680		21,608		51,432
Operating leases - drilling rig contracts ⁽⁵⁾	15,441		17,731		805		—		—		—		33,977
Delivery commitments ⁽⁶⁾	1,911		2,807		2,487		30		7		19		7,261
Produced water disposal commitments ⁽⁷⁾	9,787		20,894		20,898		20,954		10,471		9,769		92,773
Asset retirement obligations and other ⁽⁸⁾	2,714		3,039		629		494		437		21,357		28,670
Total Contractual Obligations		$84,315		$152,719		$129,863		$940,454		$705,533		$344,003		$2,356,887


(1)	Long-term debt consists of the principal amounts of the ~~7.50% Senior Notes due 2020, the~~ 6.25% Senior Notes due 2023, the 8.25% Senior Notes due 2025, and borrowings outstanding under our revolving credit facility which matures in ~~2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been redeemed or refinanced on or prior to such time).~~2022.


(2)	Cash interest on senior notes includes cash payments for interest on ~~the 7.50% Senior Notes due 2020,~~ 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 June 30, ~~2018~~2019 of ~~3.74%~~4.14%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of June 30, ~~2018,~~2019, at the applicable commitment fee rate of ~~0.50%~~0.500%.

(4)

~~Drilling rig contracts~~Other operating leases include undiscounted contractual amounts for office space and the use of well equipment, vehicles, and other office equipment. The amounts presented above represent gross contractual ~~obligations and accordingly, other~~obligations. Other joint owners in the properties operated by us ~~will~~ generally ~~be billed~~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.


~~(5)~~(6)	Delivery commitments represent gross contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.


~~(6)~~(7)	Produced water disposal commitments represent gross contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.


~~(7)~~(8)	Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of June 30, ~~2018~~2019. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.


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

~~Financing~~Off Balance Sheet Arrangements

~~Senior Secured Revolving Credit Facility~~

We currently have a senior secured revolving credit facility with a syndicate of banks that, as of June 30, 2018, had a borrowing base of $1.0 billion, with an elected commitment amount of $900.0 million, and $485.0 million of borrowings outstanding at a weighted average interest rate of 3.74%. The credit agreement governing our senior secured revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been redeemed or refinanced on or prior to such time) and any outstanding borrowings are due.

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

On May 4, 2018, we entered into the twelfth amendment to the credit agreement governing the revolving credit facility to, among other things, increase the borrowing base and elected commitment amount, reduce the margins applied to Eurodollar loans, and amend the covenant limiting payment of dividends and distributions on equity to increase our ability to make dividends and distributions on our equity interests. See “Note 6. Long-Term Debt” for further details.

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

~~7.50% Senior Notes~~

During the first quarter of 2018, we redeemed $320.0 million of the outstanding aggregate principal amount of our 7.50% Senior Notes at a price equal to 101.875% of par. Upon the redemptions, we paid $336.9 million, which included redemption premiums of $6.0 million as well as accrued but unpaid interest of $10.9 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemptions, we recorded a loss on extinguishment of debt of $8.7 million, which included the redemption premiums $6.0 million paid to redeem the notes and non-cash charges of $2.7 million attributable to the write-off of unamortized premium and debt issuance costs.

We have the right to redeem all or a portion of the remaining principal amount of the 7.50% Senior Notes at redemption prices of 101.875% until September 14, 2018 and 100% beginning September 15, 2018 and thereafter, in each case plus accrued and unpaid interest.

~~Redemption of Preferred Stock~~

In the first quarter of 2018, we redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock. Upon redemption, we paid $50.5 million, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends, with a portion of the proceeds from the divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the divestitures of oil and gas properties. As a result of the redemption, we recorded a loss on redemption of preferred stock of $7.1 million, which included $0.1 million of direct costs incurred as a result of the redemption and a non-cash charge of $7.0 million attributable to the difference between $50.0 million, which was the consideration transferred to the holders of the Preferred Stock excluding accrued and unpaid dividends, and $42.9 million, which was 20% of the carrying value of the Preferred Stock on the date of redemption.

~~Redemption of Other Long-Term Debt~~

During the second quarter of 2018, we redeemed the remaining $4.4 million outstanding principal amount of our 4.375% Convertible Senior Notes due 2028 at a price equal to 100% of par. Upon redemption, we paid $4.5 million, which included accrued and unpaid interest of $0.1 million from the last interest payment date up to, but not including, the redemption date.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 ~~2017~~2018 Annual Report. See “Note 8.10. Preferred ~~Stock”~~Stock and Common Stock Warrants”, “Note ~~10.~~13. Derivative Instruments” and “Note ~~11.~~14. Fair Value Measurements” for details of the ~~preferred stock~~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 June 30, ~~2018~~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 June 30, ~~2018~~2019 and, accordingly, does not consider drilling and completion activity, acquisitions or divestitures of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to June 30, ~~2018~~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	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)	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
June 30, 2018 Actual	$57.10	$2.71	$1,158
June 30, 2019 Actual					$59.23	$1.81	$1,091

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$62.87	$3.01	$1,654	$496	$65.36	$2.12	$1,662	$571
Crude Oil and Natural Gas -10%	$51.31	$2.40	$595	($563)	$53.10	$1.50	$473	($618)

Crude Oil Price Sensitivity
Crude Oil +10%	$62.87	$2.71	$1,613	$455	$65.36	$1.81	$1,608	$517
Crude Oil -10%	$51.31	$2.71	$647	($511)	$53.10	$1.81	$542	($549)

Natural Gas Price Sensitivity
Natural Gas +10%	$57.10	$3.01	$1,198	$40	$59.23	$2.12	$1,145	$54
Natural Gas -10%	$57.10	$2.40	$1,117	($41)	$59.23	$1.50	$1,037	($54)

The 12-Month Average Realized Price of crude oil, which is the commodity price that our cost center ceiling is most sensitive to, was $59.23 as of June 30, 2019, a decrease of approximately 2% when compared to the 12-Month Average Realized Price of crude oil as of March 31, 2019 of $60.54. We currently estimate that the 12-Month Average Realized Price of crude oil as of September 30, 2019 will be $57.62, 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 third 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 June 30, 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 June 30, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.

Income Taxes

~~Primarily as~~Income taxes are recognized based on earnings reported for tax return purposes in addition to a ~~result~~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 ~~beginning~~ in the ~~third quarter~~first three quarters of ~~2015~~2016, which limited our ability to consider subjective positive evidence, such as its projections of

future taxable income. However, as of March 31, 2019 and continuing through ~~the third quarter of 2016, we had a cumulative historical three year pre-tax loss and a net deferred tax asset position at~~ June 30, 2018. We have assessed the realizability of our deferred tax assets and, beginning in the third quarter of 2015 and continuing through the second quarter of 2018, have concluded that it was more likely than not our deferred tax assets will not be realized and a valuation allowance was required. Based on current estimates, we anticipate that during 2019, we ~~will no longer be~~are in a cumulative ~~historical three year~~ pre-tax ~~loss, at which time, based~~income position. Based on ~~analysis of available~~this factor, as well as other positive evidence ~~we may conclude~~including projected future taxable income for the current and future years, concluded that it is more likely than not ~~our~~that the deferred tax assets ~~will~~would be realized. ~~This conclusion could~~As a result, ~~in a portion or all~~we have released $177.7 million of the ~~remaining~~federal valuation allowance ~~to be~~through June 30, 2019, which was recognized ~~in earnings~~ as an income tax benefit. ~~See “Note 5. Income Taxes” for further details~~

We will continue to assess the timing and amount of ~~our~~additional releases of the valuation allowance based on available information each reporting period, such as our projections of ~~June 30, 2018.~~future taxable income, and currently anticipate that the remaining federal valuation allowance will be released by December 31, 2019.

As of June 30, ~~2018,~~2019, we have estimated U.S. federal net operating loss carryforwards of ~~$1.2 billion.~~$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 ~~offerings~~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,~~increased. However, as of June 30, ~~2018,~~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.

~~We classify interest and penalties associated with income taxes~~ See “Part II. Other Information—Item 1A. Risk Factors—The Merger as ~~interest expense. We follow~~well as other stock transactions could lead to a limitation on the ~~tax law ordering approach~~utilization of our loss carryforwards to ~~determine the sequence in which deferred tax assets and other tax attributes are utilized.~~

reduce future taxable income.”

Recently Adopted and Recently Issued Accounting Pronouncements

See “Note 2. Summary of Significant Accounting Policies” for discussion of the pronouncements we recently ~~adopted as well as the recently issued accounting pronouncements from the Financial Accounting Standards Board.~~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 ~~risk management activities and the impact on~~volatility for a portion of our ~~average realized prices;~~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;

the expected timetable for completing the proposed Merger;

the results, effects, benefits, and synergies of the proposed Merger;

future opportunities for the combined company;

future financial performance and condition;

guidance and any other statements regarding Callon’s or our future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance;

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;

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; ~~and~~

the impact of governmental regulation, taxes, market changes and world ~~events.~~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, failure to obtain the required votes of Callon’s or our shareholders to approve the Merger and related matters, whether any redemption of the Preferred Stock will be necessary or will occur prior to the closing of the Merger, the risk that a condition to closing of the proposed Merger may not be satisfied, that either party may terminate the merger agreement or that the closing of the proposed Merger might be delayed or not occur at all, potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the Merger, the diversion of management time on transaction-related issues, the ultimate timing, outcome and results of integrating the operations of Callon and Carrizo, the effects of the business combination of Callon and Carrizo, including the combined company’s future financial condition, results of operations, strategy and plans, the ability of the combined company to realize anticipated synergies in the time frame expected or at all, changes in capital markets and the ability of the combined company to finance operations in the manner expected, certain regulatory approvals of the Merger, the effects of commodity prices, and the risks of oil and gas activities, those relating to a worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in ~~oil and gas~~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 ~~determinations (including determinations by lenders)~~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 ~~the any~~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, ~~and impact fees,~~ delays, costs and difficulties relating to our joint ventures, actions by joint venture parties, results of exploration activities, the availability, market conditions and completion of land acquisitions and dispositions, costs of oilfield services, completion and connection of wells, and other factors detailed in this quarterly report.

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

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under “Part I. Item 1A. Risk Factors” and other sections of our ~~2017~~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 ~~2017~~2018 Annual Report. Except as disclosed below, there have been no material changes from the disclosure made in our ~~2017~~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.

The following tables set forth our crude oil, NGL, and natural gas revenues for the three and six months ended June 30, ~~2018~~2019 as well as the ~~impacts~~impact on the crude oil, NGL, and natural gas revenues assuming a 10% ~~fluctuation~~increase and decrease in our average realized crude oil, NGL, and natural gas prices, excluding the impact of derivative settlements:


	Three Months Ended June 30, 2018								Three Months Ended June 30, 2019
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$229,798		$21,269		$12,906		$263,973		$245,212		$14,159		$5,596		$264,967

Impact of a 10% fluctuation in average realized prices		$22,980		$2,127		$1,291		$26,398		$24,521		$1,416		$560		$26,497


	Six Months Ended June 30, 2018								Six Months Ended June 30, 2019
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$424,717		$38,171		$26,365		$489,253		$447,956		$30,996		$19,055		$498,007

Impact of a 10% fluctuation in average realized prices		$42,472		$3,817		$2,636		$48,925		$44,793		$3,099		$1,911		$49,803

We use commodity derivative instruments to ~~reduce our exposure to~~mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and ~~thereby~~ achieve a more predictable level of cash ~~flows to support our capital expenditure program and fixed costs.~~flow. We do not enter into commodity derivative instruments for speculative ~~or trading~~ purposes. As of June 30, ~~2018,~~2019, our commodity derivative instruments consisted of price swaps, three-way collars, ~~basis swaps, and purchased and~~ sold call ~~options.~~options, and basis swaps. See “Note ~~10.~~13. Derivative Instruments” for further discussion of our commodity derivative instruments as of June 30, 2019.

The following tables set forth the cash received (paid) for commodity derivative settlements, net, excluding deferred premium obligations, for the three and six months ended June 30, 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 June 30, 2019
	Crude oil			NGLs		Natural gas			Total
	(In thousands)
Cash received (paid) for commodity derivative settlements, net		($3,698	)		$—		$1,925			($1,773	)

Impact of a 10% increase in settlement prices		($6,989	)		$—		$581			($6,408	)
Impact of a 10% decrease in settlement prices		$3,572			$—		($581	)		$2,991



	Six Months Ended June 30, 2019
	Crude oil			NGLs			Natural gas			Total
	(In thousands)
Cash received (paid) for commodity derivative settlements, net		($4,018	)		$623			$1,625			($1,770	)

Impact of a 10% increase in settlement prices		($9,565	)		($378	)		$219			($9,724	)
Impact of a 10% decrease in settlement prices		$12,426			$378			($281	)		$12,523

In January 2019, we paid the first annual settlement of the Contingent ExL Consideration and received the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 were exceeded. See “Note 13. Derivative Instruments” for further details on the cash received (paid) for settlements of contingent consideration arrangements, net.

There were no settlements of contingent consideration arrangements for the three months ended June 30, 2019. The following table sets forth the cash received (paid) for settlements of contingent consideration arrangements, net for the six months ended June 30, 2019 as well as the impact that would have occurred on the cash received (paid) for settlements of contingent consideration arrangements, net assuming a 10% increase and decrease in the respective settlement prices:



	Six Months Ended June 30, 2019
	Contingent ExL Consideration			Contingent Niobrara Consideration		Contingent Marcellus Consideration		Contingent Utica Consideration
	(In thousands)
Cash received (paid) for settlements of contingent consideration arrangements, net		($50,000	)		$5,000		$—		$5,000

Impact of a 10% increase in settlement prices		$—			$—		$3,000		$—
Impact of a 10% decrease in settlement prices		$—			$—		$—		$—

The primary drivers of our commodity derivative instrument fair values are the underlying forward crude oil ~~NGL~~ and natural gas ~~derivative positions~~price curves. The following table sets forth the average forward crude oil and natural gas price curves as of June 30, ~~2018 and “Note 14. Subsequent Events”~~2019 for ~~further details~~each of ~~our crude oil derivative positions entered into subsequent to June 30, 2018.~~

~~The fair value of our~~the years in which we have commodity derivative ~~contracts are largely determined by estimates of the forward curves of the relevant price indices.~~ instruments:



	2019	2020	2021
Crude oil:
NYMEX WTI	$58.32	$56.23	$54.18
LLS-WTI Cushing	$4.02	$3.70	$3.00
WTI Midland-WTI Cushing	$0.40	$0.70	$0.95
Natural gas:
NYMEX Henry Hub	$2.38	$2.54	$2.58
Waha-NYMEX Henry Hub	($0.96)	($1.11)	($0.42)

The following table sets forth the fair values as of June 30, ~~2018,~~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 ~~respective~~underlying forward ~~curves:~~crude oil and natural gas price curves that are shown above:

Crude oil NGLs Natural gas Total
(In thousands)
Fair value liability as of June 30, 2018
($106,405 )
($4,934 )
($1,780 )
($113,119 )

Fair value with a 10% increase in the forward curve
($183,728 )
($7,980 )
($5,144 )
($196,852 )
Increase in fair value liability (77,323 ) (3,046 ) (3,364 ) (83,733 )

Fair value with a 10% decrease in the forward curve
($44,572 )
($1,942 )
$386

($46,128 )
Decrease in fair value liability 61,833
2,992
2,166
66,991



	Crude oil			NGLs		Natural gas			Total
	(In thousands)
Fair value (liability) asset as of June 30, 2019		($5,416	)		$—		$45			($5,371	)

Impact of a 10% increase in forward commodity prices		($40,182	)		$—		$1,075			($39,107	)
Impact of a 10% decrease in forward commodity prices		$29,556			$—		($1,446	)		$28,110

We determined that the contingent consideration arrangements are not clearly and closely related to the purchase and sale agreement for the applicable acquisition or divestiture, and therefore bifurcated these embedded features and reflected the associated assets and liabilities at fair value in the consolidated financial statements. The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as ~~future commodity prices,~~forward oil and gas price curves, volatility factors ~~for the future commodity prices~~ and a risk adjusted discount ~~rate.~~rates. See “Note ~~10. Derivative Instruments” and “Note 11.~~14. Fair Value Measurements” for further ~~details.~~discussion.

The following table sets forth the fair values of the contingent consideration arrangements as of June 30, ~~2018~~2019, as well as the impact on the fair values assuming a 10% increase and decrease in the ~~respective future commodity prices:~~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 potential (payment) receipt
($125,000 )
$15,000

$7,500

$15,000

Fair value as of June 30, 2018
($102,055 )
$9,970

$1,530

$10,545
10% increase in commodity price (107,210 ) 10,960
2,580
11,465
10% decrease in commodity price (94,155 ) 8,735
920
9,340



	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 June 30, 2019		($60,798	)		$4,947			$450			$6,057
Impact of a 10% increase in forward commodity prices		($3,576	)		$1,428			$262			$1,096
Impact of a 10% decrease in forward commodity prices		$6,927			($1,831	)		($197	)		($1,649	)

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 ~~7.50% Senior Notes,~~ 6.25% Senior Notes and 8.25% Senior Notes (the “Senior Notes”), but can impact their fair values. As of June 30, 2018, we had approximately $1.5 billion of long-term debt outstanding, net of unamortized premiums and debt issuance costs. Of this amount, approximately $1.0 billion was fixed-rate debt, net of unamortized premiums and debt issuance costs, with a weighted average interest rate of 7.10%. See “Note ~~11.~~14. Fair Value Measurements” for further ~~details on~~discussion.

The following table sets forth the ~~fair value~~principal amount of our ~~7.50% Senior Notes, 6.25%~~ Senior Notes and ~~8.25% Senior Notes.~~the borrowings on our revolving credit facility outstanding as of June 30, 2019, as well as the associated weighted average interest rates, and the impact on our interest expense of a 1% increase or decrease in the interest rate on outstanding borrowings on our revolving credit facility:



	Revolving Credit Facility			Senior Notes
	(In thousands except for percentages)
June 30, 2019
Amount outstanding		$841,328			$900,000
Weighted average interest rate	4.14		%	6.81		%

Three Months Ended June 30, 2019
Impact of a 1% increase in interest rate		$2,335
Impact of a 1% decrease in interest rate		($2,335	)

Six Months Ended June 30, 2019
Impact of a 1% increase in interest rate		$4,418
Impact of a 1% decrease in interest rate		($4,418	)

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 June 30, ~~2018~~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 June 30, ~~2018~~2019 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

The following disclosure updates the legal proceeding set forth under the heading “Barrow-Shaver Litigation” in the 2018 Annual Report to reflect developments during the quarter ended June 30, 2019 and should be read together with the corresponding disclosure in the 2018 Annual Report.

On September 24, 2014 an unfavorable jury verdict was delivered against the Company in a case entitled Barrow-Shaver Resources Company v. Carrizo Oil & Gas, Inc. in the amount of $27.7 million. On January 5, 2015, the court entered a judgment awarding the verdict amount plus $2.9 million in attorneys’ fees plus pre-judgment interest. On January 31, 2017, the Twelfth Court of Appeals at Tyler, Texas reversed the trial court decision and rendered judgment in favor of the Company, declaring that the plaintiff take nothing on any of its claims. The plaintiff petitioned the Texas Supreme Court for review, which was granted. Oral arguments before the Texas Supreme Court were held on December 4, 2018 and, on June 28, 2019, a majority decision was handed down affirming the Twelfth Court of Appeals ruling in favor of the Company. On July 8, 2019, the plaintiff notified the Company that it intends to file a motion for rehearing before the Texas Supreme Court. The payment of damages per the original judgment was superseded by posting a bond in the amount of $25.0 million, which will remain outstanding pending resolution of the appeals process (which could take an extended period of time) or agreement of the parties.

The case was filed September 19, 2012 in the 7th Judicial District Court of Smith County, Texas and arises from an agreement between the plaintiff and the Company whereby the plaintiff could earn an assignment of certain of the Company’s leasehold interests in Archer and Baylor counties, Texas for each commercially productive oil and gas well drilled by the plaintiff on acreage covered by the agreement. The agreement contained a provision that the plaintiff had to obtain the Company’s written consent to any assignment of rights provided by such agreement. The plaintiff subsequently entered into a purchase and sale agreement with a third-party purchaser allowing the third-party purchaser to purchase rights in approximately 62,000 leasehold acres, including the rights under the agreement with the Company, for approximately $27.7 million. The plaintiff requested the Company’s consent to make the assignment to the third-party purchaser and the Company refused. The plaintiff alleged that, as a result of the Company’s refusal, the third-party purchaser terminated such purchase and sale agreement. The plaintiff sought damages for breach of contract, tortious interference with existing contract and other grounds in an amount not to exceed $35.0 million plus exemplary damages and attorneys’ fees. As mentioned previously, the Twelfth Court of Appeals at Tyler, Texas found in favor of the Company on all grounds and this ruling was upheld by the Texas Supreme Court.

Item 1A. Risk Factors

~~There~~Except as disclosed below, there were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our ~~2017~~2018 Annual Report. However, the risk factors included in “Part I. Item 1A. Risk Factors” in our 2018 Annual Report should be read in conjunction with the additional risk factors set forth below in this Quarterly Report on Form 10-Q.

The following risk factors relate to the proposed Merger with Callon.

The transactions contemplated by the Merger Agreement are subject to conditions, including certain conditions that may not be satisfied or completed on a timely basis or at all. Failure to complete the transactions contemplated by the Merger Agreement, including the Merger, could have material and adverse effects on us.

Completion of the Merger is subject to a number of conditions, including, among other things, (i) obtaining the approval by holders of Callon’s common stock of the issuance of Callon’s common stock in the Merger and of certain amendments to Callon’s certificate of incorporation to increase the authorized number of shares of Callon’s common stock, (ii) the adoption of the Merger Agreement and the Merger by the holders of Callon’s common stock, (iii) obtaining the approval by the holders of our common stock of the Merger Agreement, (iv) either (a) obtaining the approval of the holders of the Preferred Stock of the Merger Agreement or (b) the

Preferred Deposit having been deposited and the Preferred Redemption having occurred, (v) the absence of any law or order prohibiting the consummation of the Merger, (vi) the effectiveness of the registration statement on Form S-4 pursuant to which the shares of Callon’s common stock issuable in the Merger are registered with the SEC, (vii) the authorization for listing of the shares of Callon’s common stock issuable in the Merger on the New York Stock Exchange, (ix) the expiration or termination of the applicable waiting periods under the HSR Act, which was terminated effective August 6, 2019, and (x) delivery of opinions of counsel to us and to Callon to the effect that the Merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely matter and therefore make the completion and timing of the completion of the Merger uncertain. In addition, the governmental authorities from which the regulatory approvals are required may impose conditions on the completion of the Merger or require changes to the terms of the Merger or Merger Agreement.

If the transactions contemplated by the Merger Agreement are not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the Merger, we will be subject to a number of risks, including the following: we will be required to pay our costs relating to the Merger, such as legal, accounting, financial advisory and printing fees, whether or not the Merger is completed; time and resources committed by our management to matters relating to the Merger could otherwise have been devoted to pursuing other beneficial opportunities; the market price of our common stock could be impacted to the extent that the current market price reflects a market assumption that the Merger will be completed; and if the Merger Agreement is terminated and our Board of Directors seeks another business combination, our shareholders cannot be certain that we will be able to find a party willing to enter into a transaction as attractive to us as the Merger.

In addition, the Merger Agreement contains certain termination rights for both Callon and us, which if exercised, will also result in the transactions contemplated by the Merger Agreement not being consummated. If the Merger Agreement is terminated under certain circumstances, we could be required to pay Callon a termination fee of $47.4 million. In other circumstances, upon termination of the Merger Agreement, we could be required to pay Callon up to $7.5 million for costs, fees and expenses incurred by Callon in connection with the Merger. See our Current Report on Form 8-K filed with the SEC on July 15, 2019 for a more detailed discussion of the conditions to the completion of the Merger and termination rights under the Merger Agreement.

We will be subject to business uncertainties while the Merger is pending, which could adversely affect our business.

It is possible that certain persons with whom we have a business relationship may delay certain business decisions relating to us in connection with the pendency of the Merger or they might decide to seek to terminate, change or renegotiate their relationships with us as a result of the Merger, which could negatively affect our revenues, earnings and cash flows, as well as the market price of our common stock, regardless of whether the Merger is completed. Also, our ability to attract, retain and motivate employees may be impaired until the Merger is completed and for a period of time thereafter as current and prospective employees may experience uncertainty about their roles within the combined company following the Merger.

In addition, under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the Merger, which may adversely affect our ability to execute certain of our business strategies, including the ability in certain cases to modify or enter into certain contracts, acquire or dispose of assets, hire or terminate certain employees or take other specified actions regarding employees and compensation, or incur or pre-pay certain indebtedness, incur encumbrances, make capital expenditures, issue shares or settle claims. Such limitations could negatively affect our business and operations prior to the completion of the Merger.

Our shareholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over the policies of the combined company than they now have on the policies of Carrizo.

Our shareholders currently have the right to vote in the election of our Board of Directors and on other matters affecting Carrizo. Immediately after the merger is completed, it is expected that our current shareholders will own approximately 46% of the combined company’s common stock outstanding and current Callon shareholders will own approximately 54% of the combined company’s common stock outstanding.

As a result, our current shareholders will have less influence on the management and policies of Callon than they now have on the management and policies of Carrizo.

The market price of shares of Callon common stock may decline in the future as a result of the sale of shares of Callon common stock held by Carrizo shareholders or Callon’s shareholders.

Following their receipt of shares of Callon common stock as consideration in the Merger, our shareholders may seek to sell the shares of Callon common stock delivered to them, and the Merger Agreement contains no restriction on the ability of our shareholders to sell such shares of Callon common stock following completion of the Merger. Other shareholders of Callon may also seek to sell shares of Callon common stock held by them following, or in anticipation of, completion of the Merger. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of Callon common stock to be issued in the Merger, may affect the market for, and the market price of, Callon common stock in an adverse manner.

The exchange ratio is fixed and will not be adjusted in the event of any change in either our or Callon’s stock price.

At the effective time of the Merger, each share of our common stock outstanding immediately prior to the effective time will be converted into the right to receive 2.05 shares of Callon common stock. This exchange ratio will not be adjusted for changes in the market price of either our common stock or Callon’s common stock between the date of signing the Merger Agreement and completion of the Merger. Changes in the price of Callon’s common stock prior to the Merger will affect the value of Callon’s common stock that our shareholders will receive on the date of such Merger.

The prices of Callon’s common stock and our common stock at the closing of the Merger may vary from their prices on the date the Merger Agreement was executed and on the date of each special meeting in connection with the Merger. As a result, the value represented by the exchange ratio may also vary, and you will not know or be able to calculate with certainty the market value of the merger consideration you will receive upon completion of the Merger with Callon.

The Merger Agreement limits our ability to pursue alternatives to the merger with Callon.

The Merger Agreement entered into with Callon contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our shareholders than the merger with Callon or may result in a potential competing acquirer of Carrizo proposing to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to proposals that could reasonably be expected to lead to Company Superior Proposals (as defined in the Merger Agreement), entering into discussions with any third party regarding any alternative business combination or offer for an alternative business combination. Under differing specified circumstances, the Company could be required to pay Callon a termination fee of $47.4 million or to reimburse Callon up to $7.5 million in expenses for termination of the Merger Agreement including in connection with matters that may relate to an alternative business combination. These and other provisions of the Merger Agreement could discourage a potential third party that might have an interest in acquiring all or a significant portion of Carrizo or pursuing an alternative transaction with us from considering or proposing such a transaction.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.

Whether or not the Merger is completed, the announcement and pendency of the Merger could disrupt the businesses of the Company. We are dependent on the experience and industry knowledge of our senior management and other key employees to execute our business plans. Current and prospective employees of the Company may experience uncertainty about their roles within the combined company following the Merger, which may have an adverse effect on our current ability to attract or retain key management and other key personnel regardless of whether the Merger is completed.

Even if the Merger is completed, the integration of Carrizo by the combined company may not be as successful as anticipated.

The success of the Merger will depend, in part, on Callon’s ability to realize the anticipated benefits and cost savings from combining our and Callon’s businesses, and there can be no assurance that the combined company will be able to successfully integrate us or otherwise realize the expected benefits of the Merger. Difficulties in integrating us into the combined company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among other factors:

the inability to successfully integrate our businesses into the combined company in a manner that permits Callon to achieve the full revenue and cost savings anticipated from the Merger;

complexities associated with managing the larger, more complex, integrated business;

not realizing anticipated operating synergies;

integrating personnel from the two companies and the loss of key employees;

potential unknown liabilities and unforeseen expenses, delays or certain regulatory approvals associated with the Merger;

integrating relationships with customers, vendors and business partners;

performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the Merger and integrating our operations into the combined company; and

the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

Completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party.

The completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party. If we and Callon are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under

the agreements, potentially terminating the agreements or seeking monetary damages which will adversely affect Callon following the Merger. Even if we and Callon are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements.

A future issuance, sale or exchange of our stock or warrants, such as the Merger, could trigger a limitation on the utilization of our net operating loss carryforwards.

Our ability to utilize U.S. net operating loss carryforwards to reduce future taxable income is subject to various limitations under the Code. The utilization of such carryforwards may be limited under Section 382 of the Code upon the occurrence of ownership changes resulting from issuances of our stock or the sale or exchange of our stock by certain shareholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of our stock during any three-year period. For this purpose, “stock” includes certain preferred stock and common stock warrants (including the Preferred Stock and Warrants issued to finance in part, the ExL Acquisition). In the event of such 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 loss 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. We do not believe we have a Section 382 limitation on the ability to utilize our U.S. loss carryforwards as of June 30, 2019. However, future issuances, sales or exchanges of our stock (including, potentially, relatively small transactions and transactions beyond our control) and transactions prior to the expected time of the Merger could, taken together with prior transactions with respect to our stock, trigger an ownership change under Section 382 of the Code and therefore a limitation on our ability to utilize our U.S. loss carryforwards whether or not the Merger takes place. We believe that the Merger, if consummated, will result in an ownership change based on information currently available. Any such limitation could cause some U.S. loss carryforwards incurred prior to January 1, 2018, which are subject to a limited carryforward period, to expire before we or Callon would be able to utilize them to reduce taxable income in future periods. This could possibly subject us or, following the merger, Callon to income taxes either would not otherwise be subject to and a write down of our tax assets. Any limitation associated with an ownership change under Section 382 of the Code for U.S. loss carryforwards incurred subsequent to January 1, 2018, which are not subject to a limited carryforward period, could possibly result in us or, following the merger, Callon becoming a cash tax payer sooner than we otherwise would absent the limitation.

We and Callon are expected to incur significant transaction fees and costs in connection with the Merger, which may be in excess of those anticipated by Callon and us.

We have incurred, and are expected to continue to incur, a number of non-recurring costs associated with negotiating and completing the Merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the transaction is completed. A substantial majority of our non-recurring expenses will consist of transaction costs related to the Merger and include, among others, fees paid to financial, legal, accounting and other advisers, and filing fees. We and Callon will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in connection with the Merger. The costs described above and any unanticipated costs and expenses, many of which will be borne by us even if the Merger is not completed, and if the Merger is completed, could have an adverse effect on Callon’s financial condition and operating results following the completion of the transaction.

We may be a target of securities class action and derivative lawsuits, which could result in substantial costs and may delay or prevent the Merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into business combination agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, that injunction may delay or prevent the Merger from being completed, which may adversely affect our business, financial position and results of operations.

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
†~~3.1~~2.1		~~Amended~~Agreement and ~~Restated Bylaws~~Plan of Merger by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc.~~, adopted May 23, 2018~~ dated as of July 14, 2019 (incorporated herein by reference to Exhibit ~~3.1~~2.1 to the Company’s Current Report on Form 8-K filed on ~~May 29, 2018 (File No. 000-29187-87))~~July 15, 2019).
†+*10.1		Form of ~~Indemnification~~Employee Restricted Stock Unit Agreement ~~for Directors and Executive Officers of~~under the ~~Company, adopted May 23, 2018 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 29, 2018 (File No. 000-29187-87)).~~2017 Incentive Plan.
*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~~101.INS	—	XBRL Instance Document - the instance document does not appear in the Interactive Data ~~Files~~File because its XBRL tags are embedded within the Inline XBRL document.
*101.SCH	—	XBRL Taxonomy Extension Schema Document.
*101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase Document.
*101.DEF	—	XBRL Taxonomy Extension Definition Linkbase Document.
*101.LAB	—	XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase Document.
*104		Cover Page Interactive Data File (formatted in Inline XBRL and contained in Exhibit 101).


†	Incorporated by reference as indicated.


*	Filed herewith.


+	Management contract or compensatory plan or arrangement.

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:	August 7, ~~2018~~2019	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	August 7, ~~2018~~2019	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

-48-



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues
Crude oil		$229,798			$142,806			$424,717			$270,898
Natural gas liquids	21,269			7,786			38,171			15,211
Natural gas	12,906			15,891			26,365			31,729
Total revenues	263,973			166,483			489,253			317,838

Costs and Expenses
Lease operating	35,151			36,048			74,424			65,893
Production taxes	12,487			7,143			23,062			13,351
Ad valorem taxes	3,640			1,073			5,613			4,040
Depreciation, depletion and amortization	72,430			59,072			136,897			113,454
General and administrative, net	18,265			11,596			45,557			33,299
(Gain) loss on derivatives, net	67,714			(26,065		)	97,310			(51,381		)
Interest expense, net	15,599			21,106			31,116			41,677
Loss on extinguishment of debt	—			—			8,676			—
Other expense, net	2,895			204			2,995			1,178
Total costs and expenses	228,181			110,177			425,650			221,511

Income Before Income Taxes	35,792			56,306			63,603			96,327
Income tax expense	(483		)	—			(802		)	—
Net Income		$35,309			$56,306			$62,801			$96,327
Dividends on preferred stock	(4,474		)	—			(9,337		)	—
Accretion on preferred stock	(740		)	—			(1,493		)	—
Loss on redemption of preferred stock	—			—			(7,133		)	—
Net Income Attributable to Common Shareholders		$30,095			$56,306			$44,838			$96,327

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.37			$0.86			$0.55			$1.47
Diluted		$0.36			$0.85			$0.54			$1.46

Weighted Average Common Shares Outstanding
Basic	82,058			65,767			81,802			65,479
Diluted	83,853			65,908			83,240			65,866



	Three Months Ended June 30, 2018
	Under ASC 606		Under ASC 605		Increase		% Increase
	(In thousands)
Revenues
Crude oil		$229,798		$229,658		$140	0.1	%
Natural gas liquids	21,269		20,139		1,130		5.6	%
Natural gas	12,906		12,272		634		5.2	%
Total revenues	263,973		262,069		1,904		0.7	%

Costs and Expenses
Lease operating	35,151		33,247		1,904		5.7	%

Income Before Income Taxes		$35,792		$35,792		$—	—	%



	SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)
Outstanding, beginning of period	714,238		$27.12
Granted	616,686		$14.67
Exercised	—		$—					$—
Forfeited	—		$—
Expired	—		$—
Outstanding, end of period	1,330,924		$21.35	4.8		$9.1
Vested, end of period	543,018		$27.18
Vested and exercisable, end of period	543,018		$27.18	3.04		$0.5



	Target Performance Shares ⁽¹⁾		Weighted Average Grant Date Fair Value
Unvested performance shares, beginning of period	144,955			$47.14
Granted	93,771			$19.09
Vested at end of performance period	(49,458	)		$65.51
Did not vest at end of performance period	(7,059	)		$65.51
Forfeited	—			$—
Unvested performance shares, end of period	182,209			$27.01



			Contingent Receipt (Payment) - Annual			Contingent Receipt (Payment) - Aggregate Limit
Contingent Consideration Arrangements	Years	Threshold ⁽¹⁾	(In thousands)
Contingent ExL Consideration	2018	$50.00		($50,000	)
	2019	50.00	(50,000		)
	2020	50.00	(50,000		)
	2021	50.00	(50,000		)		($125,000	)

Contingent Niobrara Consideration	2018	$55.00		$5,000
	2019	55.00	5,000
	2020	60.00	5,000			—

Contingent Marcellus Consideration	2018	$3.13		$3,000
	2019	3.18	3,000
	2020	3.30	3,000				$7,500

Contingent Utica Consideration	2018	$50.00		$5,000
	2019	53.00	5,000
	2020	56.00	5,000			—



	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—
Derivative assets		$4,869			($4,869	)		$—
Commodity derivative instruments	9,505			(9,505		)	—
Contingent Niobrara Consideration	—			—			—
Contingent Marcellus Consideration	2,205			—			2,205
Contingent Utica Consideration	7,985			—			7,985
Other assets		$19,695			($9,505	)		$10,190

Commodity derivative instruments		($52,671	)		($4,450	)		($57,121	)
Deferred premium obligations	(9,319		)	9,319			—
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(24,609		)	(2,098		)	(26,707		)
Deferred premium obligations	(11,603		)	11,603			—
Contingent ExL Consideration	(85,625		)	—			(85,625		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)



	Contingent Consideration Arrangements
	Assets		Liability
For the Six Months Ended June 30, 2018	(In thousands)
Beginning of period		$10,190		($85,625	)
Recognition of divestiture date fair value	7,880		—
Gain (loss) on changes in fair value, net⁽¹⁾	3,975		(16,430		)
Transfers into (out of) Level 3	—		—
End of period		$22,045		($102,055	)



	June 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$129,044		$130,325		$446,087		$459,518
6.25% Senior Notes due 2023	642,446		656,500		641,792		674,375
8.25% Senior Notes due 2025	245,817		266,250		245,605		274,375
Other long-term debt due 2028	—		—		4,425		4,445



	June 30, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,128,244			$120,425			$—		($3,116,164	)		$132,505
Total property and equipment, net	6,445			2,562,799			3,028		(3,847		)	2,568,425
Investment in subsidiaries	(743,363		)	—			—		743,363			—
Other assets	8,630			12,279			—		—			20,909
Total Assets		$2,399,956			$2,695,503			$3,028		($2,376,648	)		$2,721,839

Liabilities and Shareholders’ Equity
Current liabilities		$257,137			$3,362,551			$3,028		($3,119,185	)		$503,531
Long-term liabilities	1,526,788			76,315			—		15,879			1,618,982
Preferred stock	172,858			—			—		—			172,858
Total shareholders’ equity	443,173			(743,363		)	—		726,658			426,468
Total Liabilities and Shareholders’ Equity		$2,399,956			$2,695,503			$3,028		($2,376,648	)		$2,721,839



	Three Months Ended June 30, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$174			$166,309		$—		$—			$166,483
Total costs and expenses	7,731			102,415		—		31			110,177
Income (loss) before income taxes	(7,557		)	63,894		—		(31		)	56,306
Income tax expense	—			—		—		—			—
Equity in income of subsidiaries	63,894			—		—		(63,894		)	—
Net income		$56,337			$63,894		$—		($63,925	)		$56,306
Dividends on preferred stock	—			—		—		—			—
Accretion on preferred stock	—			—		—		—			—
Loss on redemption of preferred stock	—			—		—		—			—
Net income attributable to common shareholders		$56,337			$63,894		$—		($63,925	)		$56,306



	Six Months Ended June 30, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$256			$317,582		$—		$—			$317,838
Total costs and expenses	26,599			194,871		—		41			221,511
Income (loss) before income taxes	(26,343		)	122,711		—		(41		)	96,327
Income tax expense	—			—		—		—			—
Equity in income of subsidiaries	122,711			—		—		(122,711		)	—
Net income		$96,368			$122,711		$—		($122,752	)		$96,327
Dividends on preferred stock	—			—		—		—			—
Accretion on preferred stock	—			—		—		—			—
Loss on redemption of preferred stock	—			—		—		—			—
Net income attributable to common shareholders		$96,368			$122,711		$—		($122,752	)		$96,327



	Three Months Ended June 30,				2018 Period Compared to 2017 Period
	2018		2017		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,445		3,060		385			13	%
NGLs (MBbls)	853		453		400			88	%
Natural gas (MMcf)	5,372		6,775		(1,403		)	(21	%)
Total barrels of oil equivalent (MBoe)	5,193		4,643		550			12	%

Daily production volumes by product -
Crude oil (Bbls/d)	37,860		33,629		4,231			13	%
NGLs (Bbls/d)	9,379		4,982		4,397			88	%
Natural gas (Mcf/d)	59,029		74,451		(15,422		)	(21	%)
Total barrels of oil equivalent (Boe/d)	57,077		51,019		6,058			12	%

Daily production volumes by region (Boe/d) -
Eagle Ford	37,039		38,055		(1,016		)	(3	%)
Delaware Basin	19,783		2,151		17,632			820	%
Other	255		10,813		(10,558		)	(98	%)
Total barrels of oil equivalent (Boe/d)	57,077		51,019		6,058			12	%

Average realized prices -
Crude oil ($ per Bbl)		$66.70		$46.67		$20.03		43	%
NGLs ($ per Bbl)	24.93		17.19		7.74			45	%
Natural gas ($ per Mcf)	2.40		2.35		0.05			2	%
Total average realized price ($ per Boe)		$50.83		$35.86		$14.97		42	%

Revenues (In thousands) -
Crude oil		$229,798		$142,806		$86,992		61	%
NGLs	21,269		7,786		13,483			173	%
Natural gas	12,906		15,891		(2,985		)	(19	%)
Total revenues		$263,973		$166,483		$97,490		59	%



	Three Months Ended				Six Months Ended
	March 31, 2018		June 30, 2018		June 30, 2018
	(In thousands)
Drilling, completion, and infrastructure
Eagle Ford		$135,677		$101,249		$236,926
Delaware Basin	73,892		116,743		190,635
All other regions	284		—		284
Total drilling, completion, and infrastructure	209,853		217,992		427,845
Leasehold and seismic	5,520		6,129		11,649
Total Capital Expenditures ⁽¹⁾		$215,373		$224,121		$439,494



	July - December 2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$130,000		$—		$485,000		$900,000		$1,515,000
Cash interest on senior notes ⁽²⁾	35,500		71,000		71,000		61,250		61,250		82,188		382,188
Cash interest and commitment fees on revolving credit facility ⁽³⁾	10,332		20,214		20,214		20,214		6,963		—		77,937
Capital leases	900		1,800		1,050		—		—		—		3,750
Operating leases	2,330		3,461		4,219		3,702		3,639		24,658		42,009
Drilling rig contracts ⁽⁴⁾	20,200		18,677		1,196		—		—		—		40,073
Delivery commitments ⁽⁵⁾	1,861		3,706		2,786		2,467		30		26		10,876
Produced water disposal commitments ⁽⁶⁾	5,283		18,599		18,698		18,708		18,764		17,453		97,505
Asset retirement obligations and other ⁽⁷⁾	1,833		2,972		657		376		239		15,745		21,822
Total Contractual Obligations ⁽⁸⁾		$78,239		$140,429		$249,820		$106,717		$575,885		$1,040,070		$2,191,160