UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended ~~June~~September 30, 2019



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

For the transition period from to

Commission File Number: 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)



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

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

(713) 328-1000

(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ 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 ☑ 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	☐	Non-accelerated Filer	☐

Smaller reporting company	☐	Emerging growth company	☐

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

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

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 2,~~October 31, 2019 was ~~92,552,930.~~92,610,357.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of ~~June~~September 30, 2019 and December 31, 2018	2
	Consolidated Statements of Income for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018	3
	Consolidated Statements of Shareholders’ Equity for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018	4
	Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	42
Part II. Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	4344
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4644
Item 3.	Defaults Upon Senior Securities	4644
Item 4.	Mine Safety Disclosures	4644
Item 5.	Other Information	4744
Item 6.	Exhibits	4745
Signatures		4846

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, 2019			December 31, 2018			September 30, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents		$2,282			$2,282			$2,280			$2,282
Accounts receivable, net	98,444			99,723			98,161			99,723
Derivative assets	13,621			39,904			31,125			39,904
Other current assets	9,472			8,460			7,298			8,460
Total current assets	123,819			150,369			138,864			150,369
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	2,587,341			2,333,470			2,648,601			2,333,470
Unproved properties, not being amortized	656,976			673,833			649,347			673,833
Other property and equipment, net	11,188			11,221			11,022			11,221
Total property and equipment, net	3,255,505			3,018,524			3,308,970			3,018,524
Deferred income taxes	177,723			—			172,632			—
Operating lease right-of-use assets	64,615			—			55,873			—
Other long-term assets	13,666			16,207			13,885			16,207
Total Assets		$3,635,328			$3,185,100			$3,690,224			$3,185,100

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$102,943			$98,811			$79,744			$98,811
Revenues and royalties payable	54,662			49,003			59,140			49,003
Accrued capital expenditures	74,005			60,004			33,757			60,004
Accrued interest	18,700			18,377			23,640			18,377
Derivative liabilities	64,751			55,205			56,233			55,205
Operating lease liabilities	34,049			—			30,301			—
Other current liabilities	51,430			40,609			48,912			40,609
Total current liabilities	400,540			322,009			331,727			322,009
Long-term debt	1,731,418			1,633,591			1,755,378			1,633,591
Asset retirement obligations	22,111			18,360			22,876			18,360
Operating lease liabilities	36,526			—			31,723			—
Deferred income taxes	8,218			8,017			8,845			8,017
Other long-term liabilities	20,101			47,797			13,946			47,797
Total liabilities	2,218,914			2,029,774			2,164,495			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, 2019 and December 31, 2018	176,056			174,422
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of September 30, 2019 and December 31, 2018							176,925			174,422
Shareholders’ equity
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
Common stock, $0.01 par value, 180,000,000 shares authorized; 92,610,669 issued and outstanding as of September 30, 2019 and 91,627,738 issued and outstanding as of December 31, 2018							926			916
Additional paid-in capital	2,132,131			2,131,535			2,132,276			2,131,535
Accumulated deficit	(892,699		)	(1,151,547		)	(784,398		)	(1,151,547		)
Total shareholders’ equity	1,240,358			980,904			1,348,804			980,904
Total Liabilities and Shareholders’ Equity		$3,635,328			$3,185,100			$3,690,224			$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,						Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
Revenues
Crude oil		$245,212			$229,798			$447,956			$424,717			$236,153			$254,525			$684,109			$679,242
Natural gas liquids	14,159			21,269			30,996			38,171			12,824			33,798			43,820			71,969
Natural gas	5,596			12,906			19,055			26,365			8,017			15,052			27,072			41,417
Total revenues	264,967			263,973			498,007			489,253			256,994			303,375			755,001			792,628

Costs and Expenses
Lease operating	44,514			35,151			86,545			74,424			45,213			41,022			131,758			115,446
Production and ad valorem taxes	17,793			16,127			32,687			28,675			14,549			17,104			47,236			45,779
Depreciation, depletion and amortization	80,766			72,430			156,088			136,897			82,195			80,108			238,283			217,005
General and administrative, net	17,301			18,265			42,033			45,557			13,467			12,811			55,500			58,368
(Gain) loss on derivatives, net	(20,449		)	67,714			62,835			97,310			(31,554		)	55,388			31,281			152,698
Interest expense, net	18,024			15,599			34,475			31,116			17,721			15,406			52,196			46,522
Loss on extinguishment of debt	—			—			—			8,676			—			—			—			8,676
Other (income) expense, net	(2,766		)	2,895			1,592			2,995			1,125			(690		)	2,717			2,305
Total costs and expenses	155,183			228,181			416,255			425,650			142,716			221,149			558,971			646,799

Income Before Income Taxes	109,784			35,792			81,752			63,603			114,278			82,226			196,030			145,829
Income tax (expense) benefit	(2,299		)	(483		)	177,096			(802		)	(5,977		)	(880		)	171,119			(1,682		)
Net Income		$107,485			$35,309			$258,848			$62,801			$108,301			$81,346			$367,149			$144,147
Dividends on preferred stock	(4,452		)	(4,474		)	(8,812		)	(9,337		)	(4,474		)	(4,457		)	(13,286		)	(13,794		)
Accretion on preferred stock	(833		)	(740		)	(1,634		)	(1,493		)	(869		)	(771		)	(2,503		)	(2,264		)
Loss on redemption of preferred stock	—			—			—			(7,133		)	—			—			—			(7,133		)
Net Income Attributable to Common Shareholders		$102,200			$30,095			$248,402			$44,838			$102,958			$76,118			$351,360			$120,956

Net Income Attributable to Common Shareholders Per Common Share
Basic		$1.10			$0.37			$2.70			$0.55			$1.11			$0.88			$3.81			$1.45
Diluted		$1.10			$0.36			$2.69			$0.54			$1.11			$0.85			$3.79			$1.42

Weighted Average Common Shares Outstanding
Basic	92,497			82,058			92,121			81,802			92,561			86,727			92,269			83,461
Diluted	92,700			83,853			92,479			83,240			92,762			89,039			92,625			85,221

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														Three Months Ended September 30, 2019 and 2018
	Common Stock			Additional Paid-in Capital				Accumulated Deficit				Total Shareholders’ Equity			Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount						Accumulated Deficit			Shares				Amount			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of March 31, 2019	92,503,562		$925	Additional Paid-in Capital			$2,130,989				($1,000,184	Total Shareholders’ Equity	)		$1,131,730
Balance as of June 30, 2019															92,552,930		$926		$2,132,131			($892,699	)		$1,240,358
Stock-based compensation expense	—	—		6,428				—				6,428			—	—		5,488			—			5,488
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	49,368	1		(1		)		—				—			57,739	—		—			—			—
Dividends on preferred stock	—	—		(4,452		)		—				(4,452		)	—	—		(4,474		)	—			(4,474		)
Accretion on preferred stock	—	—		(833		)		—				(833		)	—	—		(869		)	—			(869		)
Net income	—	—		—				107,485				107,485			—	—		—			108,301			108,301
Balance as of June 30, 2019	92,552,930		$926		$2,132,131				($892,699	)			$1,240,358
Balance as of September 30, 2019															92,610,669		$926		$2,132,276			($784,398	)		$1,348,804

Balance as of March 31, 2018	82,065,561		$821		$1,918,942				($1,528,482	)			$391,281
Balance as of June 30, 2018															82,107,544		$821		$1,918,820			($1,493,173	)		$426,468
Stock-based compensation expense	—	—		5,110				—				5,110			—	—		4,944			—			4,944
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	41,983	—		(18		)		—				(18		)	12,189	—		(45		)	—			(45		)
Sale of common stock, net of offering costs															9,500,000	95		213,762			—			213,857
Dividends on preferred stock	—	—		(4,474		)		—				(4,474		)	—	—		(4,457		)	—			(4,457		)
Accretion on preferred stock	—	—		(740		)		—				(740		)	—	—		(771		)	—			(771		)
Net income	—	—		—				35,309				35,309			—	—		—			81,346			81,346
Balance as of June 30, 2018	82,107,544		$821		$1,918,820				($1,493,173	)			$426,468
Balance as of September 30, 2018															91,619,733		$916		$2,132,253			($1,411,827	)		$721,342


	Six Months Ended June 30, 2019 and 2018														Nine Months Ended September 30, 2019 and 2018
	Common Stock			Additional Paid-in Capital				Accumulated Deficit				Total Shareholders’ Equity			Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount						Accumulated Deficit			Shares				Amount			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of December 31, 2018	91,627,738		$916	Additional Paid-in Capital			$2,131,535				($1,151,547	Total Shareholders’ Equity	)		$980,904	91,627,738		$916			$2,131,535			($1,151,547	)		$980,904
Stock-based compensation expense	—	—		11,052				—				11,052			—	—		16,540			—			16,540
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	925,192	10		(10		)		—				—			982,931	10		(10		)	—			—
Dividends on preferred stock	—	—		(8,812		)		—				(8,812		)	—	—		(13,286		)	—			(13,286		)
Accretion on preferred stock	—	—		(1,634		)		—				(1,634		)	—	—		(2,503		)	—			(2,503		)
Net income	—	—		—				258,848				258,848			—	—		—			367,149			367,149
Balance as of June 30, 2019	92,552,930		$926		$2,132,131				($892,699	)			$1,240,358
Balance as of September 30, 2019															92,610,669		$926		$2,132,276			($784,398	)		$1,348,804

Balance as of December 31, 2017	81,454,621		$815		$1,926,056				($1,555,974	)			$370,897		81,454,621		$815		$1,926,056			($1,555,974	)		$370,897
Stock-based compensation expense	—	—		10,757				—				10,757			—	—		15,701			—			15,701
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	652,923	6		(30		)		—				(24		)	665,112	6		(75		)	—			(69		)
Sale of common stock, net of offering costs															9,500,000	95		213,762			—			213,857
Dividends on preferred stock	—	—		(9,337		)		—				(9,337		)	—	—		(13,794		)	—			(13,794		)
Accretion on preferred stock	—	—		(1,493		)		—				(1,493		)	—	—		(2,264		)	—			(2,264		)
Loss on redemption of preferred stock	—	—		(7,133		)		—				(7,133		)	—	—		(7,133		)	—			(7,133		)
Net income	—	—		—				62,801				62,801			—	—		—			144,147			144,147
Balance as of June 30, 2018	82,107,544		$821		$1,918,820				($1,493,173	)			$426,468
Balance as of September 30, 2018															91,619,733		$916		$2,132,253			($1,411,827	)		$721,342

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,						Nine Months Ended September 30,
	2019			2018			2019			2018
Cash Flows From Operating Activities
Net income		$258,848			$62,801			$367,149			$144,147
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	156,088			136,897			238,283			217,005
Loss on derivatives, net	62,835			97,310			31,281			152,698
Cash paid for commodity derivative settlements, net	(7,160		)	(38,448		)	(8,939		)	(64,710		)
Loss on extinguishment of debt	—			8,676			—			8,676
Stock-based compensation expense, net	7,969			10,724			11,692			13,786
Deferred income tax (benefit) expense	(177,521		)	529			(171,803		)	1,063
Non-cash interest expense, net	1,271			1,262			1,950			1,878
Other, net	2,079			3,975			3,505			4,100
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(7,824		)	2,437			(7,432		)	(12,763		)
Accounts payable	(6,544		)	3,878			(752		)	10,863
Accrued liabilities	12,733			(12,883		)	16,310			(9,336		)
Other assets and liabilities, net	(978		)	(1,286		)	(3,197		)	(2,115		)
Net cash provided by operating activities	301,796			275,872			478,047			465,292
Cash Flows From Investing Activities
Capital expenditures	(362,478		)	(430,639		)	(557,304		)	(662,459		)
Acquisitions of oil and gas properties	8,222			—			8,222			(21,500		)
Proceeds from divestitures of oil and gas properties	6,034			345,789			6,351			377,693
Other, net	(38		)	(1,096		)	(284		)	(2,687		)
Net cash used in investing activities	(348,260		)	(85,946		)	(543,015		)	(308,953		)
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	898,890			1,126,856			1,280,780			2,415,208
Repayments of borrowings under credit agreement	(801,993		)	(933,156		)	(1,160,399		)	(2,396,671		)
Payments of credit facility amendment fees	(613		)	(627		)	(613		)	(627		)
Sale of common stock, net of offering costs							—			213,857
Payments of dividends on preferred stock	(8,812		)	(9,337		)	(13,286		)	(13,794		)
Cash paid for settlements of contingent consideration arrangements, net	(40,000		)	—			(40,000		)	—
Other, net	(1,008		)	(638		)	(1,516		)	(972		)
Net cash provided by (used in) financing activities	46,464			(197,367		)	64,966			(163,464		)
Net Decrease in Cash and Cash Equivalents	—			(7,441		)	(2		)	(7,125		)
Cash and Cash Equivalents, Beginning of Period	2,282			9,540			2,282			9,540
Cash and Cash Equivalents, End of Period		$2,282			$2,099			$2,280			$2,415

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

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. 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.

Proposed Merger of the Company with Callon

On July 14, 2019, the Company entered into an Agreement and Plan of Merger ~~(the~~(as amended, 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~~1 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 common shareholders of the Company and Callon (for which special shareholder meetings are scheduled for November 14, 2019) (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.

On October 4, 2019, Callon filed an amendment to the registration statement on Form S-4 originally filed on August 20, 2019, which includes a joint proxy statement of the Company and Callon. The registration statement was declared effective by the Securities and Exchange Commission (the “SEC”) on October 9, 2019. The Company and Callon commenced mailing the definitive joint proxy statement to each company’s respective shareholders on or about October 11, 2019.

The capitalized terms ~~which~~that 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~~S-4/A filed by Callon with the SEC on ~~July 15,~~October 4, 2019, our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, the definitive proxy statement filed by the Company with the SEC on October 9, 2019, and in this Quarterly Report on Form 10-Q, including “Part II. Other Information—Item 1A. Risk ~~Factors”.~~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”)~~SEC and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

Significant Accounting Policies

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

Recently Adopted Accounting Standards

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

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

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

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

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

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

As a result of adopting ASC 842, the Company recorded lease liabilities of approximately $75.2 million and associated ROU assets of approximately $69.1 million on its consolidated balance sheets. The difference between the lease liabilities and ROU assets is due to a rent holiday and lease build-out incentives that were recorded as deferred lease liabilities under legacy lease accounting guidance. The adoption of ASC 842 did not materially change the Company’s consolidated statements of income or consolidated statements of cash flows. See “Note 6. Leases” for further discussion.

Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued. ~~See “Note 16. Subsequent Events” for further discussion.~~

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 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~~September 30, 2019 and December 31, 2018, receivables from contracts with customers were ~~$76.9~~$83.1 million and $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 operations.

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.

4. Acquisitions and Divestitures of Oil and Gas Properties

2019 Acquisitions and Divestitures

~~The~~On July 14, 2019, the Company ~~did not have any material acquisitions or divestitures for~~entered into the ~~three and six months ended June 30, 2019.~~Merger Agreement with Callon. See “Note 1. Nature of Operations” for details of the proposed ~~Merger which was announced on July 15, 2019.~~Merger.

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 received $8.3 million as a post-closing adjustment on March 28, 2019, for an aggregate purchase price of $196.6 million.

The Devon Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table presents the ~~preliminary~~final 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 for the three and ~~six~~nine months ended ~~June~~September 30, 2019 as shown in the table below:


	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
	(In thousands)				(In thousands)
Total revenues		$4,342		$8,718		$3,676		$12,394

Net Income Attributable to Common Shareholders		$2,020		$4,716		$1,962		$6,678

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

Niobrara Divestiture. On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. The Company received $14.0 million as a deposit on November 20, 2017, $122.6 million upon closing on January 19, 2018, and paid $1.0 million as a post-closing adjustment on August 14, 2018, for aggregate net proceeds of $135.6 million. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. See “Note 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 with no gain or loss recognized.

5. Property and Equipment, Net

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


	June 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018
	(In thousands)						(In thousands)
Oil and gas properties, full cost method
Proved properties		$6,685,543			$6,278,321			$6,827,578			$6,278,321
Accumulated depreciation, depletion and amortization and impairments	(4,098,202		)	(3,944,851		)	(4,178,977		)	(3,944,851		)
Proved properties, net	2,587,341			2,333,470			2,648,601			2,333,470
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	580,369			608,830			567,294			608,830
Capitalized interest	76,607			65,003			82,053			65,003
Total unproved properties, not being amortized	656,976			673,833			649,347			673,833
Other property and equipment	30,580			29,191			31,129			29,191
Accumulated depreciation	(19,392		)	(17,970		)	(20,107		)	(17,970		)
Other property and equipment, net	11,188			11,221			11,022			11,221
Total property and equipment, net		$3,255,505			$3,018,524			$3,308,970			$3,018,524

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was ~~$13.28~~$12.55 and ~~$13.74~~$13.29 for the three months ended ~~June~~September 30, 2019 and 2018, respectively, and ~~$13.28~~$13.02 and ~~$13.73~~$13.57 for the ~~six~~nine months ended ~~June~~September 30, 2019 and 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 ~~$3.8~~$3.9 million and ~~$6.1~~$2.9 million for the three months ended ~~June~~September 30, 2019 and 2018, respectively, and ~~$12.9~~$16.8 million and ~~$12.7~~$15.6 million for the ~~six~~nine months ended ~~June~~September 30, 2019 and 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

$~~8.6~~8.2 million and ~~$8.7~~$8.5 million for the three months ended ~~June~~September 30, 2019 and 2018, respectively, and ~~$17.6~~$25.8 million and ~~$19.1~~$27.6 million for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, respectively.

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~~nine months ended ~~June~~September 30, 2019.


	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
	(In thousands)				(In thousands)
Components of Lease Costs
Finance lease costs
Amortization of right-of-use assets ⁽¹⁾		$410		$784		$410		$1,194
Interest on lease liabilities ⁽²⁾	131		276		110		386
Operating lease costs ⁽³⁾	8,700		22,780		9,406		32,186
Short-term lease costs ⁽⁴⁾	245		463		363		826
Variable lease costs ⁽⁵⁾	50		152		104		256
Total lease costs		$9,536		$24,455		$10,393		$34,848


(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~~nine months ended ~~June~~September 30, 2019, approximately ~~$6.1~~$6.5 million and $~~17.6~~24.1 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~~September 30, 2019.



	~~June~~September 30, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$~~64,615~~55,873

Current operating lease liabilities		$~~34,049~~30,301
Long-term operating lease liabilities	~~36,526~~31,723
Total operating lease liabilities		$~~70,575~~62,024

Financing leases:
Other property and equipment, at cost		$7,810
Accumulated depreciation	(~~5,170~~5,580		)
Other property and equipment, net		$~~2,640~~2,230

Current financing lease liabilities ⁽¹⁾		$~~1,918~~1,709
Long-term financing lease liabilities ⁽²⁾	~~1,034~~797
Total financing lease liabilities		$~~2,952~~2,506


(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~~nine months ended ~~June~~September 30, 2019.



	~~Six~~Nine Months Ended ~~June~~September 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~~7,782
Investing cash flows from operating leases		$~~22,896~~29,460
Operating cash flows from financing leases		$~~276~~386
Financing cash flows from financing leases		$~~879~~1,324

ROU assets obtained in exchange for lease liabilities
Operating leases		$~~9,404~~17,226
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~~September 30, 2019.



	~~June~~September 30, 2019
Weighted Average Remaining Lease Term (In years)
Operating leases	~~5.1~~4.7 years
Financing leases	~~2.3~~2.2 years

Weighted Average Discount Rate
Operating leases	8.0	%
Financing leases	~~12.9~~11.7	%

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


	Operating Leases			Financing Leases			Operating Leases			Financing Leases
	(In thousands)						(In thousands)
July - December 2019		$20,842			$1,113
October - December 2019								$11,076			$556
2020	27,856			1,475			27,595			1,475
2021	7,726			275			7,933			275
2022	3,697			234			3,750			234
2023	3,680			232			3,680			233
2024 and Thereafter	21,608			39			21,590			39
Total lease payments	85,409			3,368			75,624			2,812
Less: Imputed interest	(14,834		)	(416		)	(13,600		)	(306		)
Total lease liabilities		$70,575			$2,952			$62,024			$2,506

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

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
	(In thousands)												(In thousands)
Income before income taxes		$109,784			$35,792			$81,752			$63,603			$114,278			$82,226			$196,030			$145,829
Income tax expense at the U.S. federal statutory rate	(23,055		)	(7,517		)	(17,168		)	(13,357		)	(23,998		)	(17,267		)	(41,166		)	(30,624		)
State income tax expense, net of U.S. federal income tax benefit	(874		)	(487		)	(626		)	(806		)	(887		)	(881		)	(1,513		)	(1,687		)
Tax deficiencies related to stock-based compensation	(176		)	(16		)	(2,114		)	(2,542		)	(558		)	(10		)	(2,672		)	(2,552		)
(Recapture) release of valuation allowance	(1,423		)	—			177,723			—			(5,091		)	—			172,632			—
Decrease in valuation allowance due to current period activity	23,211			8,048			19,273			16,449			25,348			17,400			44,621			33,849
Other	18			(511		)	8			(546		)	(791		)	(122		)	(783		)	(668		)
Income tax (expense) benefit		($2,299	)		($483	)		$177,096			($802	)		($5,977	)		($880	)		$171,119			($1,682	)

Deferred Tax Asset Valuation Allowance

The deferred tax asset valuation allowance was ~~$45.9~~$25.6 million and $242.9 million as of ~~June~~September 30, 2019 and December 31, 2018, respectively. Throughout 2018, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016. AsAt the end of ~~March 31, 2019 and June 30,~~each of the first three quarters of 2019, the Company ishas been in a cumulative three-year pre-tax income ~~position. Based on this factor, as well as~~position, which, along with other positive evidence including projected future taxable income for the current and future years, supported the ~~Company concluded~~Company’s conclusion that it is more likely than not that the deferred tax assets would be ~~realized and~~realized. As such, the Company released $179.1 million of the valuation allowance during the first quarter of 2019. During the second ~~quarter~~and third quarters of 2019, the Company reduced the ~~prior~~first quarter of 2019 valuation allowance release by $1.4 million and $5.1 million, respectively, as a result of updating the Company’s forecasted taxable income for 2019 bringing the cumulative release of the valuation allowance to ~~$177.7~~$172.6 million. The ~~reduction~~reductions of the release of the valuation allowance in the second ~~quarter~~and third quarters of 2019 isare recognized as ~~a decrease~~decreases in deferred tax assets and ~~an increase~~increases in income tax expense, while the cumulative release of the valuation allowance for the ~~six~~nine months ended ~~June~~September 30, 2019 is recognized as an increase in deferred tax assets and an income tax benefit.

8. Long-Term Debt

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


	June 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018
	(In thousands)						(In thousands)
Senior Secured Revolving Credit Facility due 2022		$841,328			$744,431			$864,812			$744,431
6.25% Senior Notes due 2023	650,000			650,000			650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(6,180		)	(6,878		)	(5,822		)	(6,878		)
8.25% Senior Notes due 2025	250,000			250,000			250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(3,730		)	(3,962		)	(3,612		)	(3,962		)
Long-term debt		$1,731,418			$1,633,591			$1,755,378			$1,633,591

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of ~~June~~September 30, 2019, had a borrowing base of $1.35 billion, with an elected commitment amount of $1.25 billion, and borrowings outstanding of ~~$841.3~~$864.8 million at a weighted average interest rate of ~~4.14%~~3.69%. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

On March 27, 2019, the Company entered into the fourteenth amendment to its credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at $1.35 billion, with an elected commitment amount of $1.25 billion, until the next redetermination thereof, (ii) amend the definition of Current Ratio, and (iii) amend certain other definitions and provisions.

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

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



Ratio of Outstanding Borrowings to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	0.25%	1.25%	0.375%
Greater than or equal to 25% but less than 50%	0.50%	1.50%	0.375%
Greater than or equal to 50% but less than 75%	0.75%	1.75%	0.500%
Greater than or equal to 75% but less than 90%	1.00%	2.00%	0.500%
Greater than or equal to 90%	1.25%	2.25%	0.500%

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt issuance costs and is net of cash and cash equivalents, EBITDA is calculated based on the last four fiscal quarters after giving pro forma effect to EBITDA for material acquisitions and divestitures of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments and excludes the Contingent ExL Consideration, which is described in “Note 13. Derivative Instruments.” As of ~~June~~September 30, 2019, the ratio of Total Debt to EBITDA was ~~2.40~~2.54 to 1.00 and the Current Ratio was ~~1.73~~2.01 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.

Due to the proposed Merger, our regular redetermination scheduled for the fall of 2019 was postponed to occur on or about February 14, 2020.

Senior Notes

During the first quarter of 2018, the Company redeemed $320.0 million of the outstanding aggregate principal amount of its 7.50% Senior Notes at a price equal to 101.875% of par. The Company paid a total of $336.9 million upon the redemptions, which included redemption premiums of $6.0 million and accrued and unpaid interest of $10.9 million. The redemptions were funded primarily from the net proceeds received from the divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note 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 and the write-off of associated unamortized premiums and debt issuance costs of $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.

Subsidiary Guarantors

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

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, tax changes, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

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

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

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



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

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

The table below sets forth a reconciliation of changes in the carrying amount of Preferred Stock for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018.


	Six Months Ended June 30,					Nine Months Ended September 30,
	2019		2018			2019		2018
	(In thousands)					(In thousands)
Preferred Stock, beginning of period		$174,422		$214,262			$174,422		$214,262
Redemption of Preferred Stock	—		(42,897		)	—		(42,897		)
Accretion on Preferred Stock	1,634		1,493			2,503		2,264
Preferred Stock, end of period		$176,056		$172,858			$176,925		$173,629

Loss on Redemption of Preferred Stock

On or prior to August 10, 2018, the Company had the right to redeem up to 50,000 shares of Preferred Stock, in cash, at $1,000.00 per share, plus accrued and unpaid dividends in an amount not to exceed the sum of the cash proceeds of divestitures of oil and gas properties and related assets, the sale or issuance of the Company’s common stock and the sale of any of the Company’s wholly owned subsidiaries.

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

11. Stock-Based Compensation

See “Note 1. Nature of Operations” for discussion of the impact to the Company’s restricted stock awards and units, performance shares, and Cash SARs as a result of the proposed Merger.

At the Company’s annual meeting on May 16, 2019, the shareholders approved the proposal to amend and restate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “A&R 2017 Incentive Plan”),which included an increase to the number of shares available for issuance under the A&R 2017 Incentive Plan. As of ~~June~~September 30, 2019, there were ~~3,164,691~~3,189,979 shares of common stock available for grant under the A&R 2017 Incentive Plan assuming all future grants will be full value stock awards. The Company has not granted stock appreciation rights to be settled in shares of common stock and has no outstanding stock options. See “Note 11. Stock-Based Compensation” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for details of the Company’s equity-based incentive plans.

Restricted Stock Awards and Units

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


	Three Months Ended June 30,									Three Months Ended September 30,
	2019				2018					2019				2018
	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Restricted Stock Awards and Units			Weighted Average Grant Date Fair Value		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	3,335,893			$13.94	2,211,173			$19.02
Granted	115,936			$11.90	1,250		��		$15.43	—			$—	43,007			$27.17
Vested	(52,639	)		$25.20	(43,992	)			$25.76	(64,657	)		$14.76	(6,858	)		$26.17
Forfeited	(47,464	)		$12.05	(9,915	)			$18.04	(25,288	)		$13.08	(12,887	)		$17.94
Unvested, end of period	3,335,893			$13.94	2,211,173				$19.02	3,245,948			$13.93	2,234,435			$19.14


	Six Months Ended June 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		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	2,266,667			$19.28	1,482,655			$28.07
Granted	2,034,619			$11.06	1,348,415			$14.68	2,034,619			$11.06	1,391,422			$15.07
Vested	(904,973	)		$20.91	(608,904	)		$31.43	(969,630	)		$20.50	(615,762	)		$31.44
Forfeited	(60,420	)		$13.14	(10,993	)		$19.17	(85,708	)		$13.12	(23,880	)		$18.51
Unvested, end of period	3,335,893			$13.94	2,211,173			$19.02	3,245,948			$13.93	2,234,435			$19.14

~~Grant~~There was no grant activity for the three months ended ~~June~~September 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, 2020.2019. Grant activity for the ~~six~~nine months ended ~~June~~September 30, 2019 primarily consisted of restricted stock units to employees as part of the annual grant of long-term equity incentive awards that occurred in the first quarter of each of the years presented in the table above. These restricted stock units vest ratably over an approximate three-year period.

As a 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 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~~September 30, 2019 and 2018 was ~~$0.7~~$0.6 million and ~~$1.0~~$0.2 million, respectively, and ~~$10.5~~$11.1 million and ~~$9.9~~$10.0 million for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, respectively. As of ~~June~~September 30, 2019 and 2018, unrecognized compensation costs related to unvested restricted stock awards and units were ~~$38.3~~$32.9 million and ~~$30.5~~$26.8 million, respectively, to be recognized over a weighted average period of ~~2.2~~2.0 years.

Cash SARs

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


	Six Months Ended June 30,								Nine Months Ended September 30,
	2019				2018				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)	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		1,330,924		$21.35		714,238		$27.12
Granted	770,775		$10.98		616,686		$14.67		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	2,101,699		$17.55	4.6	1,330,924		$21.35	4.6
Vested, end of period	919,800		$24.34		543,018		$27.18		919,800		$24.34		543,018		$27.18
Vested and exercisable, end of period	—		$24.34	3.0	543,018		$27.18	3.0	—		$24.34	2.7	—		$27.18	2.8

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

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


	Six Months Ended June 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Expected term (in years)	6.1		6.0		6.1		6.0
Expected volatility	56.0	%	54.3	%	56.0	%	54.3	%
Risk-free interest rate	2.6	%	2.8	%	2.6	%	2.8	%
Dividend yield	—	%	—	%	—	%	—	%
Grant date fair value per Cash SAR	$6.00		$7.89		$6.00		$7.89

The aggregate intrinsic value of Cash SARs outstanding as of ~~June~~September 30, 2019 and 2018 was ~~zero~~0 and ~~$9.1~~$6.5 million, respectively, ~~and~~while the aggregate intrinsic value of Cash SARs vested and exercisable as of ~~June~~September 30, 2019 and 2018 was ~~zero and $0.5 million.~~0 for each period. As of ~~June~~September 30, 2019 and December 31, 2018, the liabilities for Cash SARs were ~~$2.1~~$2.0 million and $1.8 million, all of which was classified as “Other current liabilities,” in the respective consolidated balance sheets. As of ~~June~~September 30, 2019 and 2018, unrecognized compensation costs related to unvested Cash SARs were ~~$5.1~~$3.6 million and ~~$11.3~~$8.7 million, respectively, to be recognized over a weighted average period of ~~2.4~~2.2 years and ~~2.6~~2.4 years, respectively.

Performance Shares

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


	Six Months Ended June 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
	Target Performance Shares ⁽¹⁾		Weighted Average Grant Date Fair Value		Target Performance Shares ⁽¹⁾		Weighted Average Grant Date Fair Value		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	182,209			$27.01	144,955			$47.14
Granted	130,302			$14.20	93,771			$19.09	130,302			$14.20	93,771			$19.09
Vested at end of performance period	(31,244	)		$35.71	(49,458	)		$65.51	(31,244	)		$35.71	(49,458	)		$65.51
Did not vest at end of performance period	(10,407	)		$35.71	(7,059	)		$65.51	(10,407	)		$35.71	(7,059	)		$65.51
Forfeited	—			$—	—			$—	—			$—	—			$—
Unvested, end of period	270,860			$19.51	182,209			$27.01	270,860			$19.51	182,209			$27.01


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

Grant activity consisted of performance shares as part of the annual grant of long-term equity incentive awards to certain employees that occurred in the first quarter of 2019 and 2018. Each performance share represents the right to receive ~~one~~1 share of common stock, however, the number of performance shares that vest ranges from ~~zero~~0 to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three-year performance period, the last day of which is also the vesting date.

The following table presents the results of the Company’s final TSR ranking during the performance periods that ended during the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018:


	Six Months Ended June 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Target performance shares granted	41,651		56,517		41,651		56,517
Multiplier	75	%	88	%	75	%	88	%
Performance shares vested	31,244		49,458		31,244		49,458
Performance shares that did not vest	10,407		7,059		10,407		7,059
Aggregate fair value of performance shares vested (In millions)	$0.4		$0.8		$0.4		$0.8

For the ~~six~~nine months ended ~~June~~September 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, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance share for the grant activity during the ~~six~~nine months ended ~~June~~September 30, 2019:


	Six Months Ended June 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Number of simulations	500,000		500,000		500,000		500,000
Expected term (in years)	3.1		3.0		3.1		3.0
Expected volatility	58.2	%	61.5	%	58.2	%	61.5	%
Risk-free interest rate	2.5	%	2.4	%	2.5	%	2.4	%
Dividend yield	—	%	—	%	—	%	—	%
Grant date fair value per performance share	$14.20		$19.09		$14.20		$19.09

As of ~~June~~September 30, 2019 and 2018, unrecognized compensation costs related to unvested performance shares were ~~$3.1~~$2.6 million and ~~$2.9~~$2.5 million, respectively, to be recognized over a weighted average period of ~~2.1~~1.9 years and ~~2.2~~2.0 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 included in “General and administrative, net” in the consolidated statements of income. The Company recognized the following stock-based compensation expense, net for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
	(In thousands)												(In thousands)
Restricted stock awards and units		$5,358			$4,720			$10,181			$9,804			$5,047			$4,487			$15,228			$14,291
Cash SARs	(426		)	5,788			334			4,373			(130		)	(868		)	204			3,505
Performance shares	436			406			871			963			441			411			1,312			1,374
	5,368			10,914			11,386			15,140			5,358			4,030			16,744			19,170
Less: amounts capitalized to oil and gas properties	(1,514		)	(3,708		)	(3,417		)	(4,416		)	(1,635		)	(968		)	(5,052		)	(5,384		)
Total stock-based compensation expense, net		$3,854			$7,206			$7,969			$10,724			$3,723			$3,062			$11,692			$13,786

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,							Three Months Ended September 30,						Nine Months Ended September 30,
		2019			2018			2019			2018				2019			2018			2019			2018
		(In thousands, except per share amounts)													(In thousands, except per share amounts)
Net Income			$107,485			$35,309			$258,848			$62,801				$108,301			$81,346			$367,149			$144,147
Dividends on preferred stock		(4,452		)	(4,474		)	(8,812		)	(9,337		)		(4,474		)	(4,457		)	(13,286		)	(13,794		)
Accretion on preferred stock		(833		)	(740		)	(1,634		)	(1,493		)		(869		)	(771		)	(2,503		)	(2,264		)
Loss on redemption of preferred stock		—			—			—			(7,133		)		—			—			—			(7,133		)
Net Income Attributable to Common Shareholders			$102,200			$30,095			$248,402			$44,838				$102,958			$76,118			$351,360			$120,956

Basic weighted average common shares outstanding		92,497			82,058			92,121			81,802				92,561			86,727			92,269			83,461
Dilutive effect of restricted stock and performance shares		203			967			358			798				201			1,272			356			967
Dilutive effect of common stock warrants		—			828			—			640				—			1,040			—			793
Diluted weighted average common shares outstanding		92,700			83,853			92,479			83,240				92,762			89,039			92,625			85,221

Net Income Attributable to Common Shareholders Per Common Share	Net Income Attributable to Common Shareholders Per Common Share													Net Income Attributable to Common Shareholders Per Common Share
Basic			$1.10			$0.37			$2.70			$0.55				$1.11			$0.88			$3.81			$1.45
Diluted			$1.10			$0.36			$2.69			$0.54				$1.11			$0.85			$3.79			$1.42

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,		Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018	2019	2018	2019	2018
	(In thousands)				(In thousands)
Anti-dilutive restricted stock and performance shares	3,077	16	1,526	19	3,080	—	2,570	5
Anti-dilutive common stock warrants	2,750	—	2,750	—	2,750	—	2,750	—
Total weighted average anti-dilutive securities	5,827	16	4,276	19	5,830	—	5,320	5

13. Derivative Instruments

Commodity Derivative Instruments

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

While the use of commodity derivative instruments limits or partially reduces the downside risk of adverse commodity price

movements, such use also limits the upside from favorable commodity price movements. The Company does not enter into commodity derivative instruments for speculative purposes.

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

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

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

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

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

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

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

As of ~~June~~September 30, 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)			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	—			4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16		4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	3Q19	Basis Swaps	WTI Midland-WTI Cushing	9,100	—		—		—		—			($4.44	)	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)
Crude oil	3Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—			4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—			2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—
Crude oil	4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—			2020	Three-Way Collars	NYMEX WTI	22,000	—			$45.34		$55.34		$65.16	—
Crude oil	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)	2020	Basis Swaps	WTI Midland-WTI Cushing	10,658	—		—		—		—			($1.68	)
Crude oil	4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—			2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—

Crude oil	2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—			2021	Basis Swaps	WTI Midland-WTI Cushing	8,000	—		—		—		—			$0.18
Crude oil	2020	Three-Way Collars	NYMEX WTI	12,000	—			$45.63		$55.63		$66.04	—			2021	Sold Call Options	NYMEX WTI	8,220	—		—		—			$64.00	—
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)			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	)	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	42,500	—	—	—	—			($1.30	)
Natural gas	3Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—			4Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—

Natural gas	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	42,500	—	—	—	—			($1.30	)	2020	Basis Swaps	Waha-NYMEX Henry Hub	29,541	—	—	—	—			($0.77	)
Natural gas	4Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—			2020	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.50	—

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	—

The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods often resulting in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract.

Counterparties to the Company’s commodity derivative instruments who are also lenders under the Company’s credit agreement (“Lender Counterparty”) allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the Lender Counterparty with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties to the Company’s commodity derivative instruments who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”) can require commodity derivative instruments to be novated to a Lender Counterparty if the Company’s net liability position exceeds the Company’s unsecured credit limit with the Non-Lender Counterparty and therefore do not require the posting of cash collateral.

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

Contingent Consideration Arrangements

The purchase and sale agreements for the acquisition of properties in the Delaware Basin from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (the “ExL Acquisition”) in 2017 and divestitures of the Company’s assets in the Niobrara in 2018, and Marcellus and Utica in 2017, included contingent consideration arrangements that require the Company to pay or entitle the Company to receive specified amounts if commodity prices exceed specified thresholds, which are summarized in the tables below. 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” of the Notes to

Consolidated Financial Statements in the 2018 Annual Report for further discussion of these transactions. See “—Cash received (paid) for settlements of contingent consideration arrangements, net” below for discussion of the settlements that occurred during the first quarter of 2019.

Contingent ExL Consideration



	Year	Threshold ⁽¹⁾		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			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 specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).

(2)

Cash paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $2.3 million of the next contingent payment will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent payments, presented in cash flows from operating activities.

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 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

The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of ~~June~~September 30, 2019 and December 31, 2018 are summarized below:


	June 30, 2019									September 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		$21,704			($15,582	)		$6,122			$38,183			($15,341	)		$22,842
Contingent Niobrara Consideration	3,409			—			3,409			3,592			—			3,592
Contingent Marcellus Consideration	3			—			3
Contingent Utica Consideration	4,087			—			4,087			4,691			—			4,691
Derivative assets		$29,203			($15,582	)		$13,621			$46,466			($15,341	)		$31,125
Commodity derivative instruments	10,303			(8,243		)	2,060			14,158			(10,008		)	4,150
Contingent Niobrara Consideration	1,538			—			1,538			1,076			—			1,076
Contingent Marcellus Consideration	447			—			447			343			—			343
Contingent Utica Consideration	1,970			—			1,970			1,384			—			1,384
Other long-term assets		$14,258			($8,243	)		$6,015			$16,961			($10,008	)		$6,953

Commodity derivative instruments		($26,390	)		$8,024			($18,366	)		($17,385	)		$9,555			($7,830	)
Deferred premium obligations	(7,558		)	7,558			—			(5,786		)	5,786			—
Contingent ExL Consideration	(46,385		)	—			(46,385		)	(48,403		)	—			(48,403		)
Derivative liabilities-current		($80,333	)		$15,582			($64,751	)		($71,574	)		$15,341			($56,233	)
Commodity derivative instruments	(10,988		)	6,474			(4,514		)	(9,849		)	8,952			(897		)
Deferred premium obligations	(1,769		)	1,769			—			(1,056		)	1,056			—
Contingent ExL Consideration	(14,413		)	—			(14,413		)	(11,657		)	—			(11,657		)
Other long-term liabilities		($27,170	)		$8,243			($18,927	)		($22,562	)		$10,008			($12,554	)



	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	)

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

(Gain) loss on derivatives, net

The components of “(Gain) loss on derivatives, net” in the consolidated statements of income for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 are summarized below:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
	(In thousands)												(In thousands)
(Gain) loss on derivatives, net
Crude oil		($20,915	)		$53,437			$41,846			$82,948			($28,223	)		$43,664			$13,623			$126,612
NGL	—			6,564			(6		)	4,799			—			5,086			(6		)	9,885
Natural gas	(1,600		)	153			(3,670		)	(2,892		)	(2,961		)	(192		)	(6,631		)	(3,084		)
Contingent ExL Consideration	1,215			10,600			30,214			16,430			(738		)	9,990			29,476			26,420
Contingent Niobrara Consideration	265			(1,705		)	(2,912		)	(2,090		)	279			(1,705		)	(2,633		)	(3,795		)
Contingent Marcellus Consideration	438			205			919			675			107			215			1,026			890
Contingent Utica Consideration	148			(1,540		)	(3,556		)	(2,560		)	(18		)	(1,670		)	(3,574		)	(4,230		)
(Gain) loss on derivatives, net		($20,449	)		$67,714			$62,835			$97,310			($31,554	)		$55,388			$31,281			$152,698

Cash received (paid) for derivative settlements, net

There were no settlements of contingent consideration arrangements for the three months ended ~~June~~September 30, 2019. For the ~~six~~nine months ended ~~June~~September 30, 2019, the Company paid $50.0 million ~~from~~for the first annual settlement of the Contingent ExL Consideration and received $10.0 million ~~from~~for the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. The cash paid and received for those contingent consideration settlements are classified as cash flows from financing activities as each of the settlements were less than their respective acquisition or divestiture date fair values. For the three and ~~six~~nine months ended ~~June~~September 30, 2018, there were no settlements of contingent consideration arrangements.

The components of “Cash paid for derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” in the consolidated statements of cash flows for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 are summarized below:


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2019			2018			2019			2018				2019			2018			2019			2018
Cash Flows From Operating Activities		(In thousands)													(In thousands)
Cash received (paid) for commodity derivative settlements, net
Crude oil			($3,698	)		($21,210	)		($4,018	)		($33,333	)			$904			($21,261	)		($3,114	)		($54,594	)
NGL		—			(756		)	623			(1,188		)		—			(2,641		)	623			(3,829		)
Natural gas		1,925			488			1,625			540				66			245			1,691			785
Deferred premium obligations		(2,749		)	(2,605		)	(5,390		)	(4,467		)		(2,749		)	(2,605		)	(8,139		)	(7,072		)
Cash paid for commodity derivative settlements, net			($4,522	)		($24,083	)		($7,160	)		($38,448	)			($1,779	)		($26,262	)		($8,939	)		($64,710	)

Cash Flows From Financing Activities
Cash received (paid) for settlements of contingent consideration arrangements, net	Cash received (paid) for settlements of contingent consideration arrangements, net													Cash received (paid) for settlements of contingent consideration arrangements, net
Contingent ExL Consideration			$—			$—			($50,000	)		$—				$—			$—			($50,000	)		$—
Contingent Niobrara Consideration		—			—			5,000			—				—			—			5,000			—
Contingent Utica Consideration		—			—			5,000			—				—			—			5,000			—
Cash paid for settlements of contingent consideration arrangements, net			$—			$—			($40,000	)		$—				$—			$—			($40,000	)		$—

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 derivative instrument assets and liabilities measured at fair value on a recurring basis as of ~~June~~September 30, 2019 and December 31, 2018:

~~June~~September 30, 2019

Level 1

Level 2

Level 3

(In thousands)

Assets

Commodity derivative instruments

$—

$~~8,182~~26,992

$—

Contingent Niobrara Consideration

—

~~4,947~~4,668

—

Contingent Marcellus Consideration

—

~~450~~343

—

Contingent Utica Consideration

—

~~6,057~~6,075

—

Liabilities

Commodity derivative instruments

$—

($~~22,880~~8,727

)

$—

Contingent ExL Consideration

—

(~~60,798~~60,060

)

—



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

Liabilities
Commodity derivative instruments		$—		($15,438	)		$—
Contingent ExL Consideration	—		(80,584		)	—

The asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors.

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

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

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

See “Note 13. Derivative Instruments” for additional information regarding the contingent consideration arrangements.

The Company had no0 transfers into Level 1 and no0 transfers into or out of Level 2 for the ~~six~~nine months ended ~~June~~September 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 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

The fair value measurements of the Preferred Stock are measured as of the issuance date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the principal amounts of the Company’s senior notes and other long-term debt with the fair values measured using quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy. See “Note 8. Long-Term Debt” for additional discussion.


	June 30, 2019				December 31, 2018				September 30, 2019				December 31, 2018
	Principal Amount		Fair Value		Principal Amount		Fair Value		Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)								(In thousands)
6.25% Senior Notes due 2023		$650,000		$626,438		$650,000		$599,625		$650,000		$615,875		$650,000		$599,625
8.25% Senior Notes due 2025	250,000		244,063		250,000		244,375		250,000		244,375		250,000		244,375

15. Supplemental Cash Flow Information

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


	Six Months Ended June 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(In thousands)					(In thousands)
Operating activities:
Cash paid for interest, net of amounts capitalized		$34,475		$29,853			$52,196			$44,644
Cash paid for income taxes	590		—			590			—

Investing activities:
Increase (decrease) in capital expenditure payables and accruals		$28,428		$35,543			($34,624	)		$61,893

Supplemental non-cash investing activities:
Fair value of contingent consideration assets on date of divestiture		$—		($7,880	)		$—			($7,880	)
Stock-based compensation expense capitalized to oil and gas properties	3,417		4,416			5,052			5,384
Asset retirement obligations capitalized to oil and gas properties	3,324		691			3,495			1,127

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

16. Subsequent Events

~~On July 14,~~Commodity Derivative Instruments

In October 2019, the Company entered into the ~~Merger Agreement with Callon. See “Note 1. Nature of Operations” for further discussion.~~following commodity derivative instruments:



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	1Q20	Basis Swaps	Waha-NYMEX Henry Hub	12,000	—	—	—	—		($1.36	)
Natural gas	2Q20	Basis Swaps	Waha-NYMEX Henry Hub	14,000	—	—	—	—		($1.87	)

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

The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our 2018 Annual Report. The following discussion and analysis contains statements, including, but not limited to, statements related to our plans, strategies, objectives, and expectations. Please see “Forward-Looking Statements” for further details about these statements.

General Overview

Recent Developments

On July 14, 2019, we entered into an Agreement and Plan of Merger ~~(the~~(as amended, the “Merger Agreement”) with Callon Petroleum Company (“Callon”). Pursuant to the Merger Agreement, we will be merged with and into Callon, with Callon continuing as the surviving entity (the “Merger”). The closing of the Merger is expected to occur in the fourth quarter of 2019, subject to approvals from the common shareholders of Carrizo and Callon (for which special shareholder meetings are scheduled for November 14, 2019) and other ~~certain~~ conditions. Subject to the 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~~Third Quarter 2019 Highlights

Total production for the three months ended ~~June~~September 30, 2019 was ~~65,643~~69,971 Boe/d, an increase of ~~15%~~8% from the three months ended ~~June~~September 30, 2018, primarily due to production from new wells in the Eagle Ford and Delaware Basin, partially offset by normal production decline.

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


	Three Months Ended June 30, 2019				June 30, 2019				Three Months Ended September 30, 2019				September 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	11	9.9	30	27.2	23	21.2	580	519.6	11	8.8	15	14.9	16	12.7	611	549.8
Delaware Basin	6	4.7	3	3.0	10	8.5	92	79.7	7	5.7	7	5.9	10	8.0	102	88.9
Total	17	14.6	33	30.2	33	29.7	672	599.3	18	14.5	22	20.8	26	20.7	713	638.7

Drilling and completion expenditures for the ~~second~~third quarter of 2019 were ~~$131.1~~$119.0 million, of which approximately ~~66%~~59% were in the Eagle Ford with the balance in the Delaware Basin.

We recorded net income attributable to common shareholders for the three months ended ~~June~~September 30, 2019 of ~~$102.2~~$103.0 million, or ~~$1.10~~$1.11 per diluted share, as compared to net income attributable to common shareholders for the three months ended ~~June~~September 30, 2018 of ~~$30.1~~$76.1 million, or ~~$0.36~~$0.85 per diluted share. The increase in net income attributable to common shareholders was driven primarily by a gain on derivatives, net of approximately ~~$20.4~~$31.6 million during the ~~second~~third quarter of 2019 compared to a loss on derivatives, net of approximately ~~$67.7~~$55.4 million during the ~~second~~third quarter of ~~2018. Although~~2018, partially offset by an approximate $46.4 million decrease in total ~~production for~~revenues, primarily as a result of a 22% decrease in the ~~three months ended June 30, 2019 increased 15% from the three months ended June 30, 2018, the~~total average realized price for the three months ended ~~June~~September 30, 2019 ~~decreased 13% as~~ compared to the three months ended ~~June~~September 30, ~~2018 resulting in total revenue remaining relatively flat.~~2018. See “—Results of Operations” below for further details.

Results of Operations

Comparison of Results Between The Three Months Ended ~~June~~September 30, 2019 and 2018 And The ~~Six~~Nine Months Ended ~~June~~September 30, 2019 and 2018

Production volumes

The following table summarizes total production volumes and daily production volumes 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			Three Months Ended September 30,					Amount Change Between Periods			Percent Change Between Periods			Nine Months Ended September 30,				Amount Change Between Periods			Percent Change Between Periods
		2019	2018			2019				2018				2019				Percent Change Between Periods		2018				2019		Amount Change Between Periods			Percent Change Between Periods		2018					Amount Change Between Periods			Percent Change Between Periods
Total production volumes				Amount Change Between Periods
Crude oil (MBbls)		4,042	3,445	597			Percent Change Between Periods	17	%		7,707		6,517		Amount Change Between Periods		1,190			18	%	4,194			3,755			439			12	%	11,901		10,272			1,629			16	%
NGLs (MBbls)		949	853	96			11	%		1,840		1,593			247			16	%		1,068		1,055			13			1	%		2,909		2,648		261			10	%
Natural gas (MMcf)		5,897	5,372	525			10	%		12,015		10,182			1,833			18	%		7,050		6,815			235			3	%		19,065		16,996		2,069			12	%
Total barrels of oil equivalent (MBoe)		5,974	5,193	781			15	%		11,550		9,807			1,743			18	%		6,437		5,946			491			8	%		17,988		15,753		2,235			14	%

Daily production volumes by product
Crude oil (Bbls/d)		44,413	37,860	6,553			17	%		42,580		36,008			6,572			18	%		45,587		40,813			4,774			12	%		43,594		37,628		5,966			16	%
NGLs (Bbls/d)		10,429	9,379	1,050			11	%		10,168		8,800			1,368			16	%		11,612		11,469			143			1	%		10,654		9,699		955			10	%
Natural gas (Mcf/d)		64,805	59,029	5,776			10	%		66,382		56,252			10,130			18	%		76,630		74,072			2,558			3	%		69,836		62,258		7,578			12	%
Total barrels of oil equivalent (Boe/d)		65,643	57,077	8,566			15	%		63,812		54,183			9,629			18	%		69,971		64,627			5,344			8	%		65,887		57,703		8,184			14	%

Daily production volumes by region (Boe/d)	Daily production volumes by region (Boe/d)																			Daily production volumes by region (Boe/d)
Eagle Ford		41,370	37,039	4,331			12	%		40,456		36,335			4,121			11	%		42,946		39,024			3,922			10	%		41,295		37,241		4,054			11	%
Delaware Basin		24,273	19,783	4,490			23	%		23,356		17,522			5,834			33	%		27,025		25,577			1,448			6	%		24,592		20,236		4,356			22	%
Other		—	255	(255	)		(100	%)		—		326			(326	)		(100	%)		—		26			(26	)		(100	%)		—		226		(226	)		(100	%)
Total barrels of oil equivalent (Boe/d)		65,643	57,077	8,566			15	%		63,812		54,183			9,629			18	%		69,971		64,627			5,344			8	%		65,887		57,703		8,184			14	%

The increase in production volumes for the three and ~~six~~nine months ended ~~June~~September 30, 2019 compared to the three and ~~six~~nine months ended ~~June~~September 30, 2018 is primarily due to production from new wells in the Eagle Ford and Delaware Basin, partially offset by normal production decline.

Average realized prices and revenues

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


	Three Months Ended June 30,				Amount Change Between Periods				Percent Change Between Periods			Six Months Ended June 30,						Amount Change Between Periods				Percent Change Between Periods			Three Months Ended September 30,						Amount Change Between Periods				Percent Change Between Periods			Nine Months Ended September 30,						Amount Change Between Periods				Percent Change Between Periods
	2019		2018					2019				2018					2019					Percent Change Between Periods		2018					2019		Amount Change Between Periods				Percent Change Between Periods		2018							Amount Change Between Periods				Percent Change Between Periods
Average realized prices					Amount Change Between Periods
Crude oil ($ per Bbl)		$60.67		$66.70		($6.03	)		Percent Change Between Periods	(9	%)			$58.12			$65.17	Amount Change Between Periods			($7.05	)		(11	%)		$56.31			$67.78				($11.47	)		(17	%)		$57.48			$66.13				($8.65	)		(13	%)
NGLs ($ per Bbl)	14.92		24.93		(10.01		)		(40	%)		16.85			23.96			(7.11		)		(30	%)		12.01			32.04			(20.03		)		(63	%)		15.06			27.18			(12.12		)		(45	%)
Natural gas ($ per Mcf)	0.95		2.40		(1.45		)		(60	%)		1.59			2.59			(1.00		)		(39	%)		1.14			2.21			(1.07		)		(48	%)		1.42			2.44			(1.02		)		(42	%)
Total average realized price ($ per Boe)		$44.35		$50.83		($6.48	)		(13	%)			$43.12			$49.89			($6.77	)		(14	%)			$39.92			$51.02			($11.10	)		(22	%)			$41.97			$50.32			($8.35	)		(17	%)

Revenues (In thousands)
Crude oil		$245,212		$229,798		$15,414			7	%			$447,956			$424,717			$23,239			5	%			$236,153			$254,525			($18,372	)		(7	%)			$684,109			$679,242			$4,867			1	%
NGLs	14,159		21,269		(7,110		)		(33	%)		30,996			38,171			(7,175		)		(19	%)		12,824			33,798			(20,974		)		(62	%)		43,820			71,969			(28,149		)		(39	%)
Natural gas	5,596		12,906		(7,310		)		(57	%)		19,055			26,365			(7,310		)		(28	%)		8,017			15,052			(7,035		)		(47	%)		27,072			41,417			(14,345		)		(35	%)
Total revenues		$264,967		$263,973		$994			—	%			$498,007			$489,253			$8,754			2	%			$256,994			$303,375			($46,381	)		(15	%)			$755,001			$792,628			($37,627	)		(5	%)

The ~~increase~~decrease in revenues for the three and nine months ended ~~June~~September 30, 2019 compared to the same ~~period~~periods in 2018 is primarily due to ~~higher crude oil production, partially offset by~~ lower crude oil, NGL, and 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~~prices, partially offset by higher crude oil ~~production, partially offset by lower crude oil~~ and ~~NGL prices.~~natural gas production.

Lease operating expense

The following table summarizes lease operating 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
Lease operating expense
$44,514

$7.45

$35,151

$6.77

$86,545

$7.49

$74,424

$7.59



	Three Months Ended September 30,								Nine Months Ended September 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		$45,213		$7.02		$41,022		$6.90		$131,758		$7.32		$115,446		$7.33

The increase in lease operating expenses for the three and nine months ended ~~June~~September 30, 2019 compared to the ~~same period in~~three and nine months ended September 30, 2018 is primarily due to costs associated with increased ~~production.~~production and increased workover costs principally on wells acquired in the Devon Acquisition. 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~~three months ended ~~June~~September 30, 2019 compared to the ~~same period in~~three months ended September 30, 2018 is primarily due to the workover costs ~~associated with~~described above partially offset by increased crude oil production. ~~The decrease in lease~~Lease operating expense per Boe ~~is primarily due~~for the nine months ended September 30, 2019 remained relatively flat compared to ~~an increased proportion of production from wells drilled on properties acquired in~~ the ~~ExL Acquisition, which have lower operating costs per Boe than our other Delaware Basin and Eagle Ford properties.~~nine months ended September 30, 2018.

Production and ad valorem taxes

The following table summarizes production and ad valorem taxes for the 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 %



	Three Months Ended September 30,								Nine Months Ended September 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		$14,549	5.7	%		$17,104	5.6	%		$47,236	6.3	%		$45,779	5.8	%

The ~~increase~~decrease in production and ad valorem taxes ~~as well as~~for the three months ended September 30, 2019, compared to the same period in 2018 is primarily due to lower than expected ad valorem tax rates during the third quarter of 2019. The increase ofin production and ad valorem taxes as a percent of revenues is primarily due to lower total revenues as a result of a 22% decrease in the average realized price for the three ~~and six~~ months ended ~~June~~September 30, 2019 compared to the three ~~and six~~ months ended ~~June~~September 30, 2018.

The increase in production and ad valorem taxes for the nine months ended September 30, 2019 compared to the same period in 2018 is primarily due to increased ad valorem taxes as a result of new wells drilled in the Eagle Ford and Delaware ~~Basin~~Basin. The increase in production and ~~higher property tax valuations~~ad valorem taxes as a percent of revenues is primarily due to lower total revenues as a result of a 17% decrease in the ~~increase in crude oil prices during~~average realized price for the nine months ended September 30, 2019 compared to the nine months ended September 30, 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,								Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018				2019				2018				2019				2018
	(In thousands, except per Boe amounts)																(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe		Amount		Per Boe		Amount		Per Boe		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		$80,774		$12.55		$79,051		$13.29		$234,126		$13.02		$213,727		$13.57
Depreciation of other property and equipment	722		0.12		613		0.12		1,422		0.12		1,194		0.12		716		0.11		607		0.10		2,138		0.12		1,801		0.11
Amortization of other assets	198		0.04		140		0.03		418		0.03		374		0.04		197		0.03		102		0.02		615		0.03		476		0.03
Accretion of asset retirement obligations	494		0.08		331		0.06		896		0.08		653		0.07		508		0.08		348		0.06		1,404		0.08		1,001		0.06
DD&A		$80,766		$13.52		$72,430		$13.95		$156,088		$13.51		$136,897		$13.96		$82,195		$12.77		$80,108		$13.47		$238,283		$13.25		$217,005		$13.78

DD&A expense for the three and ~~six~~nine months ended ~~June~~September 30, 2019 increased ~~$8.3~~$2.1 million and ~~$19.2~~$21.3 million, respectively, compared to the three and ~~six~~nine months ended ~~June~~September 30, 2018. The increase in DD&A expense is attributable to increased production, partially offset by the decrease in the DD&A rate per Boe. The decrease in the DD&A rate per Boe is due primarily to an increased proportion of proved oil and gas reserves in the Delaware Basin which carry a lower DD&A rate per Boe as compared to our proved oil and gas reserves in the Eagle Ford, as well as decreased future development costs in the Eagle Ford and Delaware Basin subsequent to ~~June~~September 30, 2018.

General and administrative expense, net

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(In thousands)
General and administrative expense, net		$13,467		$12,811		$55,500		$58,368

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

The decrease in general and administrative expense, net for the ~~six~~nine months ended ~~June~~September 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~~smaller increase in the fair value of Cash SARs for the ~~six~~nine months ended ~~June~~September 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 our loss on derivatives, net for the periods indicated:


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018		2019			2018			2019			2018			2019			2018
	(In thousands)											(In thousands)
Crude oil derivative instruments		($20,915	)		$53,437		$41,846			$82,948			($28,223	)		$43,664			$13,623			$126,612
NGL derivative instruments	—			6,564		(6		)	4,799			—			5,086			(6		)	9,885
Natural gas derivative instruments	(1,600		)	153		(3,670		)	(2,892		)	(2,961		)	(192		)	(6,631		)	(3,084		)
Contingent consideration arrangements	2,066			7,560		24,665			12,455			(370		)	6,830			24,295			19,285
(Gain) loss on derivatives, net		($20,449	)		$67,714		$62,835			$97,310			($31,554	)		$55,388			$31,281			$152,698

The gain on derivatives, net for the three months ended ~~June~~September 30, 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 natural gas~~ prices from ~~April~~July 1, 2019 to ~~June~~September 30, 2019 on crude oil ~~and natural gas~~ derivative instruments outstanding at the beginning of the ~~second~~third quarter of 2019 as well as the execution of new crude oil derivative instruments during the third quarter of 2019.

The loss on derivatives, net for the three months ended ~~June~~September 30, 2018 was primarily due to the upward shift in the futures curve of forecasted crude oil and NGL prices from ~~April~~July 1, 2018 to ~~June~~September 30, 2018 on crude oil and NGL derivative instruments outstanding at the beginning of the ~~second~~third quarter of 2018 and on our Contingent ExL Consideration ~~partially offset by~~as well as the execution of new crude oil derivative instruments ~~executed~~ during the ~~second~~third quarter of 2018.

The loss on derivatives, net for the ~~six~~nine months ended ~~June~~September 30, 2019 was primarily due to the upward shift in the futures curve of forecasted crude oil prices from January 1, 2019 to ~~June~~September 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~~nine months ended ~~June~~September 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~~September 30, 2018 on crude oil and NGL derivative instruments outstanding at the beginning of 2018 and on our Contingent ExL Consideration ~~partially offset by~~as well as the execution of new crude oil derivative instruments ~~executed~~ during 2018, ~~and~~partially offset by the downward shift in the futures curve of forecasted natural gas prices from January 1, 2018 to ~~June~~September 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,						Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
	(In thousands)												(In thousands)
Interest expense on Senior Notes		$15,313			$17,767			$30,625			$39,253			$15,313			$17,750			$45,938			$57,003
Interest expense on revolving credit facility	10,159			5,490			19,213			8,649			9,536			5,092			28,749			13,741
Amortization of premiums and debt issuance costs	986			937			1,918			2,040			994			956			2,913			2,996
Other interest expense	138			133			284			270			119			124			402			394
Interest capitalized	(8,572		)	(8,728		)	(17,565		)	(19,096		)	(8,241		)	(8,516		)	(25,806		)	(27,612		)
Interest expense, net		$18,024			$15,599			$34,475			$31,116			$17,721			$15,406			$52,196			$46,522

The increase in interest expense, net for the three and ~~six~~nine months ended ~~June~~September 30, 2019 compared to the three and ~~six~~nine months ended ~~June~~September 30, 2018 is primarily due to increased borrowings and associated interest expense on our revolving credit facility as well as the decrease in capitalized interest as a result of a lower weighted average interest rate driven by the higher proportion of borrowings on our revolving credit facility, which carries a lower interest rate than the Senior Notes. 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 quarters of 2018.

Loss on extinguishment of debt

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

Income taxes and deferred tax assets valuation allowance

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 benefit. However, for the three months ended ~~June~~September 30, 2019, we recognized income tax expense of ~~$2.3~~$6.0 million, of which ~~$1.4~~$5.1 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~~nine months ended ~~June~~September 30, 2019, we have released ~~$177.7~~$172.6 million of the valuation allowance which is reflected in our consolidated statements of income as an income tax benefit.

For the three and ~~six~~nine months ended ~~June~~September 30, 2018, we recognized income tax expense of ~~$0.5~~$0.9 million and ~~$0.8~~$1.7 million, respectively. The income tax expense for each period was significantly lower than the statutory rate as a result of maintaining a full valuation allowance against our deferred tax assets based on our conclusion that it was more likely than not that the deferred tax assets would not be realized.

Dividends on preferred stock

For both the three months ended ~~June~~September 30, 2019 and 2018, we declared, and paid in cash, dividends of $4.5 million.

For the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, we declared, and paid in cash, dividends of ~~$8.8~~$13.3 million and ~~$9.3~~$13.8 million, respectively.

Loss on redemption of preferred stock

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

Liquidity and Capital Resources

See “Note 1. Nature of Operations” and “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 ~~Resources”.~~Resources.”

2019 DC&I Capital ~~Expenditures.~~Expenditures Plan and Funding Strategy. Our 2019 DC&I capital expenditure plan as approved by our board of directors remains unchanged at $525.0 million to $575.0 ~~million, but~~million. While we do not plan to provide or update guidance and long-

term outlook information regarding our ~~expectation~~results of operations during the pendency of the ~~amount~~merger, as mentioned above in “—General Overview—Recent Developments”, we continue to expect our 2019 DC&I capital expenditures to be ~~spent has been reduced to $500.0 million to $550.0 million as a result~~below the midpoint of ~~efficiencies that have been achieved to date.~~the approved range. We currently intend to finance the remainder of our 2019 DC&I capital expenditure plan primarily from the sources described below under “—Sources and Uses of

Cash.” Our capital program could vary depending upon various factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. The following is a summary of our capital expenditures for the three and ~~six~~nine months ended ~~June~~September 30, 2019:


	Three Months Ended				Six Months Ended		Three Months Ended						Nine Months Ended
	March 31, 2019		June 30, 2019		June 30, 2019		March 31, 2019		June 30, 2019		September 30, 2019		September 30, 2019
	(In thousands)						(In thousands)
DC&I
Eagle Ford		$134,275		$86,514		$220,789		$134,275		$86,514		$69,682		$290,471
Delaware Basin	80,390		44,567		124,957		80,390		44,567		49,354		174,311
Other	52		28		80		52		28		—		80
Total DC&I	214,717		131,109		345,826		214,717		131,109		119,036		464,862
Leasehold and seismic	9,107		3,606		12,713		9,107		3,606		4,041		16,754
Total capital expenditures ⁽¹⁾		$223,824		$134,715		$358,539		$223,824		$134,715		$123,077		$481,616


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

Sources and Uses of Cash. Our primary use of cash is related to our DC&I capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the three and ~~six~~nine months ended ~~June~~September 30, 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~~October 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~~$875.8 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.

Overview of Cash Flow Activities. Net cash provided by operating activities was ~~$301.8~~$478.0 million and ~~$275.9~~$465.3 million for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, respectively. The increase was driven primarily by ~~an increase in revenues as a result of higher crude oil and NGL production and prices and~~ a decrease in the net cash paid for derivative settlements, partially offset by ~~an increase~~a decrease in ~~operating expenses.~~revenues as a result of lower crude oil and NGL prices.

Net cash used in investing activities was ~~$348.3~~$543.0 million and ~~$85.9~~$309.0 million for the ~~six~~nine months ended ~~June~~September 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 Niobrara, partially offset by a decrease in cash paid for capital expenditures.

Net cash provided by financing activities was ~~$46.5~~$65.0 million for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to net cash used in financing activities for the ~~six~~nine months ended ~~June~~September 30, 2018 of ~~$197.4~~$163.5 million. The change was primarily due to payments for the redemptions of our 7.50% Senior Notes and Preferred Stock during the first quarter of 2018, ~~and decreased~~partially offset by increased borrowings, net of repayments under our revolving credit facility ~~during~~for the ~~first half of~~nine months ended September 30, 2019 ~~partially offset by~~as well as net cash ~~paid~~payments for settlements of contingent consideration arrangements in January 2019.

Liquidity/Cash Flow Outlook. Cash flows from operations are primarily driven by crude oil production, crude oil prices, and settlements of our crude oil derivatives. We currently believe that cash flows from operations and borrowings under our revolving credit facility will provide adequate financial flexibility and will be sufficient to fund our immediate cash flow requirements.

•

Revolving credit facility. The borrowing base under our revolving credit facility is affected by assumptions of the administrative agent with respect to, among other things, crude oil and, to a lesser extent, natural gas prices. Our borrowing base may decrease if our administrative agent reduces the crude oil and natural gas prices from those used to determine our existing borrowing base. Due to the 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.

•

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 for each contingent consideration arrangement.


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

As of ~~August 2,~~October 31, 2019, we had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:


Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)			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	—			4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16		4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	3Q19	Basis Swaps	WTI Midland-WTI Cushing	9,100	—		—		—		—			($4.44	)	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)
Crude oil	3Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—			4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—			2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—
Crude oil	4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—			2020	Three-Way Collars	NYMEX WTI	22,000	—			$45.34		$55.34		$65.16	—
Crude oil	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)	2020	Basis Swaps	WTI Midland-WTI Cushing	10,658	—		—		—		—			($1.68	)
Crude oil	4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—			2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—

Crude oil	2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—			2021	Basis Swaps	WTI Midland-WTI Cushing	8,000	—		—		—		—			$0.18
Crude oil	2020	Three-Way Collars	NYMEX WTI	12,000	—			$45.63		$55.63		$66.04	—			2021	Sold Call Options	NYMEX WTI	8,220	—		—		—			$64.00	—
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	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	36,005	—	—	—	—			($0.93	)
Natural gas	2020	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.50	—

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 2019 DC&I capital ~~expenditure plan,~~expenditures, we may need to reduce

our capital ~~expenditure plan~~expenditures or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our remaining 2019 DC&I capital ~~expenditure plan,~~expenditures, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties.

Contractual Obligations

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


	July - December 2019		2020		2021		2022		2023		2024 and Thereafter		Total		October - December 2019		2020		2021		2022		2023		2024 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$—		$841,328		$650,000		$250,000		$1,741,328		$—		$—		$—		$864,812		$650,000		$250,000		$1,764,812
Cash interest on senior notes ⁽²⁾	30,625		61,250		61,250		61,250		40,938		41,250		296,563		20,313		61,250		61,250		61,250		40,938		41,250		286,251
Cash interest and commitment fees on revolving credit facility ⁽³⁾	18,436		36,873		36,873		12,701		—		—		104,883		8,458		33,832		33,832		11,654		—		—		87,776
Operating leases - other ⁽⁴⁾	5,401		10,125		6,921		3,697		3,680		21,608		51,432		2,452		10,235		7,021		3,750		3,680		21,590		48,728
Operating leases - drilling rig contracts ⁽⁵⁾	15,441		17,731		805		—		—		—		33,977		8,624		17,360		912		—		—		—		26,896
Delivery commitments ⁽⁶⁾	1,911		2,807		2,487		30		7		19		7,261		958		2,807		2,487		30		7		19		6,308
Produced water disposal commitments ⁽⁷⁾	9,787		20,894		20,898		20,954		10,471		9,769		92,773		3,207		12,813		12,839		12,894		2,412		—		44,165
Asset retirement obligations and other ⁽⁸⁾	2,714		3,039		629		494		437		21,357		28,670		1,399		3,741		917		499		441		22,081		29,078
Total Contractual Obligations		$84,315		$152,719		$129,863		$940,454		$705,533		$344,003		$2,356,887		$45,411		$142,038		$119,258		$954,889		$697,478		$334,940		$2,294,014


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


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

(3)

Cash interest on our revolving credit facility was calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of ~~June~~September 30, 2019 of ~~4.14%~~3.69%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of ~~June~~September 30, 2019, at the applicable commitment fee rate of 0.500%.


(4)	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. Other joint owners in the properties operated by us generally pay for their working interest share of costs associated with the use of well equipment.


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


(6)	Delivery commitments represent 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.


(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.


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

Off Balance Sheet Arrangements

We currently have no off balance sheet arrangements.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, commitments and contingencies and preferred stock. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2018 Annual Report. See “Note 10. Preferred Stock and Common Stock Warrants”, “Note 13. Derivative Instruments” and “Note 14. Fair Value Measurements” for details of the Preferred Stock and contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our ~~June~~September 30, 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~~September 30, 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~~September 30, 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, 2019 Actual	$59.23	$1.81	$1,091
September 30, 2019 Actual					$55.90	$1.39	$758

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$65.36	$2.12	$1,662	$571	$61.67	$1.69	$1,290	$532
Crude Oil and Natural Gas -10%	$53.10	$1.50	$473	($618)	$50.23	$1.11	$110	($648)

Crude Oil Price Sensitivity
Crude Oil +10%	$65.36	$1.81	$1,608	$517	$61.67	$1.39	$1,235	$477
Crude Oil -10%	$53.10	$1.81	$542	($549)	$50.23	$1.39	$165	($593)

Natural Gas Price Sensitivity
Natural Gas +10%	$59.23	$2.12	$1,145	$54	$55.90	$1.69	$812	$54
Natural Gas -10%	$59.23	$1.50	$1,037	($54)	$55.90	$1.11	$704	($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~~$55.90 as of ~~June~~September 30, 2019, a decrease of approximately 2%6% when compared to the 12-Month Average Realized Price of crude oil as of ~~March 31,~~June 30, 2019 of ~~$60.54.~~$59.23. We currently estimate that the 12-Month Average Realized Price of crude oil as of ~~September 30,~~December 31, 2019 will be ~~$57.62,~~$55.78, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 1110 months and an estimate for the eleventh and twelfth ~~month~~months based on a quoted forward price. Utilizing this estimated 12-Month Average Realized Price, we estimate that the ~~third~~fourth 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~~September 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~~September 30, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. We assess the realizability of our deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. We consider all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, we evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

For the year ended December 31, 2018, we maintained a full valuation allowance against our deferred tax assets based on our conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016, which limited our ability to consider subjective positive evidence, such as its projections of

future taxable income. However, asat the end of ~~March 31, 2019 and continuing through June 30,~~each of the first three quarters of 2019, we are in a cumulative pre-tax income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and future years, we concluded that it is more likely than not that the deferred tax assets would be realized. As a result, we have released ~~$177.7~~$172.6 million of the federal valuation allowance through ~~June~~September 30, 2019, which was recognized as an income tax benefit.

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

As of ~~June~~September 30, 2019, we have estimated U.S. federal net operating loss carryforwards of $~~1.1 billion~~909.4 million that, if not utilized in earlier periods, will expire between 2026 and 2037. Our ability to utilize these U.S. loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold.

Due to the issuance of the Preferred Stock and the common stock offering associated with the ExL Acquisition in 2017, as well as the common stock offering in August 2018, our calculated ownership change percentage increased. However, as of ~~June~~September 30, 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. See ~~“Part II. Other Information—Item 1A. Risk~~“Risk Factors—Risks Relating to Callon after Completion of the Merger—The ~~Merger as well as other stock~~ transactions in connection with the merger could ~~lead to~~trigger a limitation on the utilization of ~~our~~the historic U.S. net operating loss carryforwards of Callon and Carrizo” in our definitive proxy statement filed with the SEC on October 9, 2019 for our special shareholder meeting to ~~reduce future taxable income.”~~be held on November 14, 2019.

Recently Adopted and Recently Issued Accounting Pronouncements

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

Forward-Looking Statements

This ~~quarterly report~~Quarterly Report on Form 10-Q contains statements concerning our intentions, expectations, projections, assessments of risks, estimations, beliefs, plans or predictions for the future, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among others, statements regarding:

our growth strategies;

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

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

our estimates, guidance and forecasts, including those regarding timing and levels of production;

changes in working capital requirements, reserves, and acreage;

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

anticipated trends in our business;

availability of pipeline connections and water disposal on economic terms;

effects of competition on us;

our future results of operations;

profitability of drilling locations;

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;

results of litigation;

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;

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

realization and other matters concerning deferred tax assets.

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “possible,” “scheduled,” “should,” “guidance” or other similar words. Such statements rely on assumptions and involve risks and uncertainties, many of which are beyond our control, including, but not limited to, 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 commodity prices, the need to replace reserves depleted by production, impairments of proved oil and gas properties, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base redeterminations and availability under our revolving credit facility, evaluations of us by lenders under our revolving credit facility, waivers or amendments under our revolving credit facility in connection with acquisitions, other actions by lenders and holders of our capital stock, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, failure to realize the anticipated benefits of an acquisition, market conditions and other factors affecting our ability to pay dividends on or redeem the Preferred Stock, integration and other acquisition risks, other factors affecting our ability to reach agreements or complete acquisitions or dispositions, actions by sellers and buyers, effects of purchase price adjustments, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes, delays, costs and difficulties relating to our joint ventures, actions by joint venture parties, results of exploration activities, the availability, market conditions and completion of land acquisitions and dispositions, costs of oilfield services, completion and connection of wells, and other factors detailed in this ~~quarterly report.~~Quarterly Report on Form 10-Q.

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

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under “Part I. Item 1A. Risk Factors” and other sections of our 2018 Annual Report and in our other filings with the SEC, including under “Risk Factors” and other sections of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, our definitive proxy statement filed with the SEC on October 9, 2019 for our special shareholder meeting to be held on November 14, 2019 and this ~~quarterly report.~~Quarterly Report on Form 10-Q. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2018 Annual Report. Except as disclosed below, there have been no material changes from the disclosure made in our 2018 Annual Report regarding our exposure to certain market risks.

Commodity Price Risk

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of crude oil, NGLs, and natural gas, which are affected by changes in market supply and demand and other factors. The markets for crude oil, NGLs, and natural gas have been volatile, especially over the last several years, and these markets will likely continue to be volatile in the future.

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


	Three Months Ended June 30, 2019								Three Months Ended September 30, 2019
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$245,212		$14,159		$5,596		$264,967		$236,153		$12,824		$8,017		$256,994

Impact of a 10% fluctuation in average realized prices		$24,521		$1,416		$560		$26,497		$23,616		$1,283		$804		$25,703


	Six Months Ended June 30, 2019								Nine Months Ended September 30, 2019
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$447,956		$30,996		$19,055		$498,007		$684,109		$43,820		$27,072		$755,001

Impact of a 10% fluctuation in average realized prices		$44,793		$3,099		$1,911		$49,803		$68,407		$4,381		$2,707		$75,495

We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not enter into commodity derivative instruments for speculative purposes. As of ~~June~~September 30, 2019, our commodity derivative instruments consisted of price swaps, three-way collars, sold call options, and basis swaps. See “Note 13. Derivative Instruments” for further discussion of our commodity derivative instruments as of ~~June~~September 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~~nine months ended ~~June~~September 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											Three Months Ended September 30, 2019
	Crude oil			NGLs		Natural gas			Total			Crude oil			NGLs		Natural gas			Total
	(In thousands)											(In thousands)
Cash received (paid) for commodity derivative settlements, net		($3,698	)		$—		$1,925			($1,773	)		$904			$—		$66			$970

Impact of a 10% increase in settlement prices		($6,989	)		$—		$581			($6,408	)		($4,429	)		$—		$590			($3,839	)
Impact of a 10% decrease in settlement prices		$3,572			$—		($581	)		$2,991			$6,938			$—		($590	)		$6,348


	Six Months Ended June 30, 2019												Nine Months Ended September 30, 2019
	Crude oil			NGLs			Natural gas			Total			Crude oil			NGLs			Natural gas			Total
	(In thousands)												(In thousands)
Cash received (paid) for commodity derivative settlements, net		($4,018	)		$623			$1,625			($1,770	)		($3,114	)		$623			$1,691			($800	)

Impact of a 10% increase in settlement prices		($9,565	)		($378	)		$219			($9,724	)		($13,993	)		($378	)		$809			($13,562	)
Impact of a 10% decrease in settlement prices		$12,426			$378			($281	)		$12,523			$19,364			$378			($872	)		$18,870

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~~September 30, 2019. The following table sets forth the cash received (paid) for settlements of contingent consideration arrangements, net for the ~~six~~nine months ended ~~June~~September 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									Nine Months Ended September 30, 2019
	Contingent ExL Consideration			Contingent Niobrara Consideration		Contingent Marcellus Consideration		Contingent Utica Consideration		Contingent ExL Consideration			Contingent Niobrara Consideration		Contingent Marcellus Consideration		Contingent Utica Consideration
	(In thousands)									(In thousands)
Cash received (paid) for settlements of contingent consideration arrangements, net		($50,000	)		$5,000		$—		$5,000		($50,000	)		$5,000		$—		$5,000

Impact of a 10% increase in settlement prices		$—			$—		$3,000		$—		$—			$—		$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 and natural gas price curves. The following table sets forth the average forward crude oil and natural gas price curves as of ~~June~~September 30, 2019 for each of the years in which we have commodity derivative instruments:


	2019	2020	2021	2019	2020	2021
Crude oil:
NYMEX WTI	$58.32	$56.23	$54.18	$54.62	$51.46	$50.04
LLS-WTI Cushing	$4.02	$3.70	$3.00
WTI Midland-WTI Cushing	$0.40	$0.70	$0.95	$0.57	$0.65	$0.67
Natural gas:
NYMEX Henry Hub	$2.38	$2.54	$2.58	$2.42	$2.42	$2.45
Waha-NYMEX Henry Hub	($0.96)	($1.11)	($0.42)	($0.95)	($1.32)	($0.81)

The following table sets forth the fair values as of ~~June~~September 30, 2019 of our commodity derivative instruments, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward crude oil and natural gas price curves that are shown above:


	Crude oil			NGLs		Natural gas			Total			Crude oil			NGLs		Natural gas			Total
	(In thousands)											(In thousands)
Fair value (liability) asset as of June 30, 2019		($5,416	)		$—		$45			($5,371	)
Fair value (liability) asset as of September 30, 2019													$22,168			$—		$2,940			$25,108

Impact of a 10% increase in forward commodity prices		($40,182	)		$—		$1,075			($39,107	)		($40,311	)		$—		$1,267			($39,044	)
Impact of a 10% decrease in forward commodity prices		$29,556			$—		($1,446	)		$28,110			$33,800			$—		($1,374	)		$32,426

The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors and risk adjusted discount rates. See “Note 14. Fair Value Measurements” for further discussion.

The following table sets forth the fair values of the contingent consideration arrangements as of ~~June~~September 30, 2019, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves that are shown above:


	Contingent ExL Consideration			Contingent Niobrara Consideration			Contingent Marcellus Consideration			Contingent Utica Consideration			Contingent ExL Consideration			Contingent Niobrara Consideration			Contingent Marcellus Consideration			Contingent Utica Consideration
	(In thousands)												(In thousands)
Potential (payment) receipt per year		($50,000	)		$5,000			$3,000			$5,000			($50,000	)		$5,000			$3,000			$5,000
Maximum remaining potential (payment) receipt		($75,000	)		$10,000			$6,000			$10,000			($75,000	)		$10,000			$6,000			$10,000

Fair value (liability) asset as of June 30, 2019		($60,798	)		$4,947			$450			$6,057
Fair value (liability) asset as of September 30, 2019														($60,060	)		$4,668			$343			$6,075
Impact of a 10% increase in forward commodity prices		($3,576	)		$1,428			$262			$1,096			($2,872	)		$1,424			$214			$691
Impact of a 10% decrease in forward commodity prices		$6,927			($1,831	)		($197	)		($1,649	)		$3,209			($1,929	)		($160	)		($1,003	)

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding borrowings on our revolving credit facility. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate 6.25% Senior Notes and 8.25% Senior Notes (the “Senior Notes”), but can impact their fair values. See “Note 14. Fair Value Measurements” for further discussion.

The following table sets forth the principal amount of our Senior Notes and the borrowings on our revolving credit facility outstanding as of ~~June~~September 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			Revolving Credit Facility			Senior Notes
	(In thousands except for percentages)						(In thousands except for percentages)
June 30, 2019
September 30, 2019
Amount outstanding		$841,328			$900,000			$864,812			$900,000
Weighted average interest rate	4.14		%	6.81		%	3.69		%	6.81		%

Three Months Ended June 30, 2019
Three Months Ended September 30, 2019
Impact of a 1% increase in interest rate		$2,335						$2,291
Impact of a 1% decrease in interest rate		($2,335	)					($2,291	)

Six Months Ended June 30, 2019
Nine Months Ended September 30, 2019
Impact of a 1% increase in interest rate		$4,418						$6,710
Impact of a 1% decrease in interest rate		($4,418	)					($6,710	)

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~~September 30, 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~~September 30, 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~~September 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,~~In August 2019, the plaintiff ~~notified the Company that it intends to file~~filed 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.

Litigation Related to the Merger

On August 28, 2019, a purported shareholder of the Company filed an individual complaint in the United States District Court for the Southern District of New York, captioned John Andre v. Carrizo Oil & Gas, Inc. et al., Case No. 1:19-cv-08064-VM (the “Andre Action”). On September 4, 2019, a purported shareholder of the Company filed an individual complaint in the United States District Court for the Southern District of New York, captioned Ertan Barucic v. Carrizo Oil & Gas, Inc. et al., Case No. 1:19-cv-08185-VM (the “Barucic Action”). Also on September 4, 2019, a purported shareholder of the Company filed a complaint in a putative class action in the United States District Court for the Southern District of New York, captioned James Umland v. Carrizo Oil & Gas, Inc. et al., Case No. 1:19-cv-08224-VM (the “Umland Action”). On September 10, 2019, a purported shareholder of the Company filed a complaint in a putative class action in the United States District Court for the Southern District of Texas, captioned Ertan Barucic v. Carrizo Oil & Gas, Inc. et al., Case No. 4:19-cv-03405 (the “Barucic Class Action”). Also on September 10, 2019, a purported shareholder of the Company filed an individual complaint in the United States District Court for the Southern District of New York, captioned Murray Budd v. Carrizo Oil &Gas, Inc. et al., Case No. 1:19-cv-08391-VM (the “Budd Action”). On September 13, 2019, a purported shareholder of the Company filed an individual complaint in the United States District Court

for the District of Delaware, captioned Mohammad Siddiqui v. Carrizo Oil & Gas, Inc. et al., Case No. 1:19-cv-01726-LPS (the “Siddiqui Action”).

On September 17, 2019, a purported shareholder of the Company filed an individual complaint in the United States District Court for the Southern District of New York, captioned Camille Sarrasin v. Carrizo Oil & Gas, Inc. et al., Case No. 1:19-cv-08633-VM (the “Sarrasin Action”). On September 18, 2019, a purported shareholder of the Company filed a complaint in a putative class action in the United States District Court for the Southern District of New York, captioned Carole Sawyer v. Carrizo Oil & Gas, Inc. et al., Case No. 1:19-cv-08677-VM (the “Sawyer Action”). On September 9, 2019, the Andre Action, the Barucic Action, the Umland Action, and the Budd Action were consolidated under the Andre Action, Case No. 1:19-cv-08064-VM. In addition, on September 20, 2019, the Andre Action, the Sarrasin Action, and the Sawyer Action were consolidated under the Andre Action, Case No. 1:19-cv-08064-VM (the “Consolidated Action”). The Barucic Class Action and the Consolidated Action allege that the preliminary joint proxy statement/prospectus, filed with the SEC on August 20, 2019, omits material information with respect to the Merger, rendering it false and misleading and thus that the Company and the directors of the Company violated Section 14(a) of the Exchange Act as well as Rule 14a-9 under the Exchange Act. The Barucic Class Action, the Siddiqui Action, and the Consolidated Action further allege that the directors of the Company violated Section 20(a) of the Exchange Act. The Barucic Class Action, the Siddiqui Action, and the Consolidated Action seek, among other things, to enjoin the transactions contemplated by the Merger Agreement unless the Company discloses the allegedly material information that was allegedly omitted from the preliminary joint proxy statement/prospectus, an award of damages, and an award of attorneys’ fees and expenses.

On August 28, 2019, a purported shareholder of the Company filed an individual complaint in the United States District Court for the District of Delaware, captioned Shiva Stein v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01599-LPS (the “Stein Action”). On September 3, 2019, a purported shareholder of the Company filed a complaint in a putative class action in the United States District Court for the District of Delaware, captioned Eric Sabatini v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01644-CFC (the “Sabatini Action”). On September 5, 2019, a purported shareholder of the Company filed a complaint in a putative class action in the United States District Court for the District of Delaware, captioned Manoj Fernandes v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01658-LPS (the “Fernandes Action”). The Stein Action, the Sabatini Action, and the Fernandes Action allege that the preliminary joint proxy statement/prospectus, filed with the SEC on August 20, 2019, omits material information with respect to the Merger, rendering it false and misleading and thus that the Company, Callon, and the directors of the Company violated Section 14(a) of the Exchange Act as well as Rule 14a-9 under the Exchange Act. The Stein Action, the Sabatini Action, and the Fernandes Action further allege that the directors of the Company and Callon violated Section 20(a) of the Exchange Act. The Stein Action, the Sabatini Action, and the Fernandes Action seek, among other things, to enjoin the transactions contemplated by the Merger Agreement unless the Company and Callon disclose the allegedly material information that was allegedly omitted from the preliminary joint proxy statement, an award of damages, and an award of attorneys’ fees and expenses.

The Company believes that the Consolidated Action, the Barucic Class Action, the Siddiqui Action, the Stein Action, the Sabatini Action, and the Fernandes Action are without merit and intends to vigorously defend them.

Item 1A. Risk Factors

~~Except as disclosed below, there~~There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our 2018 Annual ~~Report. However,~~Report, the ~~risk~~ factors ~~included~~discussed in “Part I.II. 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~~10-Q for the quarter ended June 30, 2019 and the risk factors ~~relate~~related 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 Agreementus and the Merger ~~by the holders of Callon’s common stock, (iii) obtaining the approval by the holders of~~in 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 registrationdefinitive proxy 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,~~October 9, 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 stockspecial shareholder meeting 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 receiveheld 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,November 14, 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
†2.1		Amendment No. 1 to Agreement and Plan of Merger, dated as of August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. ~~dated as of July 14, 2019~~ (incorporated herein by reference to ~~Exhibit 2.1 to~~Annex A of the Company’s ~~Current Report on Form 8-K~~definitive proxy statement filed on ~~July 15,~~October 9, 2019).
~~+*10.1~~		~~Form of Employee Restricted Stock Unit Agreement under the 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.INS	—	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
*101.SCH	—	Inline XBRL Taxonomy Extension Schema Document.
*101.CAL	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
*101.DEF	—	Inline XBRL Taxonomy Extension Definition Linkbase Document.
*101.LAB	—	Inline XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE	—	Inline 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,~~November 5, 2019	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	~~August 7,~~November 5, 2019	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

~~-48-~~-46-