UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended ~~June~~September 30, 2018



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

For the transition period from to

Commission File Number: 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)



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

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

(713) 328-1000

(Registrant’s telephone number)

____________________________________________________________

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

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

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



Large accelerated filer	þ	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	¨

		Emerging growth company	¨

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of ~~August 1,~~November 2, 2018 was ~~82,114,492.~~91,625,532.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of ~~June~~September 30, 2018 and December 31, 2017	2
	Consolidated Statements of Income for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017	3
	Consolidated Statement of Shareholders’ Equity for the ~~six~~nine months ended ~~June~~September 30, 2018	4
	Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3133
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4547
Item 4.	Controls and Procedures	4648
Part II. Other Information
Item 1.	Legal Proceedings	4749
Item 1A.	Risk Factors	4749
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4749
Item 3.	Defaults Upon Senior Securities	4749
Item 4.	Mine Safety Disclosures	4749
Item 5.	Other Information	4749
Item 6.	Exhibits	4750
Signatures		4851

Part I. Financial Information

Item 1. Consolidated Financial Statements (Unaudited)

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)


	June 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Assets
Current assets
Cash and cash equivalents		$2,099			$9,540			$2,415			$9,540
Accounts receivable, net	111,100			107,441			128,780			107,441
Derivative assets	10,928			—			10,258			—
Other current assets	8,378			5,897			9,636			5,897
Total current assets	132,505			122,878			151,089			122,878
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,959,951			1,965,347			2,124,767			1,965,347
Unproved properties, not being amortized	597,892			660,287			579,275			660,287
Other property and equipment, net	10,582			10,176			10,885			10,176
Total property and equipment, net	2,568,425			2,635,810			2,714,927			2,635,810
Deposit for pending acquisition of oil and gas properties							21,500			—
Other assets	20,909			19,616			23,482			19,616
Total Assets		$2,721,839			$2,778,304			$2,910,998			$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$113,651			$74,558			$147,670			$74,558
Revenues and royalties payable	53,280			52,154			52,975			52,154
Accrued capital expenditures	117,934			119,452			117,556			119,452
Accrued interest	21,126			28,362			23,748			28,362
Derivative liabilities	145,520			57,121			162,895			57,121
Other current liabilities	52,020			41,175			50,918			41,175
Total current liabilities	503,531			372,822			555,762			372,822
Long-term debt	1,502,307			1,629,209			1,327,689			1,629,209
Asset retirement obligations	16,305			23,497			17,071			23,497
Derivative liabilities	87,933			112,332			102,103			112,332
Deferred income taxes	4,164			3,635			4,699			3,635
Other liabilities	8,273			51,650			8,703			51,650
Total liabilities	2,122,513			2,193,145			2,016,027			2,193,145
Commitments and contingencies
Preferred stock
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of June 30, 2018 and 250,000 issued and outstanding as of December 31, 2017	172,858			214,262
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of September 30, 2018 and 250,000 issued and outstanding as of December 31, 2017							173,629			214,262
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 82,107,544 issued and outstanding as of June 30, 2018 and 81,454,621 issued and outstanding as of December 31, 2017	821			815
Common stock, $0.01 par value, 180,000,000 shares authorized; 91,619,733 issued and outstanding as of September 30, 2018 and 81,454,621 issued and outstanding as of December 31, 2017							916			815
Additional paid-in capital	1,918,820			1,926,056			2,132,253			1,926,056
Accumulated deficit	(1,493,173		)	(1,555,974		)	(1,411,827		)	(1,555,974		)
Total shareholders’ equity	426,468			370,897			721,342			370,897
Total Liabilities and Shareholders’ Equity		$2,721,839			$2,778,304			$2,910,998			$2,778,304

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,
	2018			2017			2018			2017			2018			2017			2018			2017
Revenues
Crude oil		$229,798			$142,806			$424,717			$270,898			$254,525			$152,101			$679,242			$422,999
Natural gas liquids	21,269			7,786			38,171			15,211			33,798			12,467			71,969			27,678
Natural gas	12,906			15,891			26,365			31,729			15,052			16,711			41,417			48,440
Total revenues	263,973			166,483			489,253			317,838			303,375			181,279			792,628			499,117

Costs and Expenses
Lease operating	35,151			36,048			74,424			65,893			41,022			34,874			115,446			100,767
Production taxes	12,487			7,143			23,062			13,351			14,516			7,741			37,578			21,092
Ad valorem taxes	3,640			1,073			5,613			4,040			2,588			1,736			8,201			5,776
Depreciation, depletion and amortization	72,430			59,072			136,897			113,454			80,108			67,564			217,005			181,018
General and administrative, net	18,265			11,596			45,557			33,299			12,811			16,029			58,368			49,328
(Gain) loss on derivatives, net	67,714			(26,065		)	97,310			(51,381		)	55,388			24,377			152,698			(27,004		)
Interest expense, net	15,599			21,106			31,116			41,677			15,406			20,673			46,522			62,350
Loss on extinguishment of debt	—			—			8,676			—			—			—			8,676			—
Other expense, net	2,895			204			2,995			1,178
Other (income) expense, net													(690		)	462			2,305			1,640
Total costs and expenses	228,181			110,177			425,650			221,511			221,149			173,456			646,799			394,967

Income Before Income Taxes	35,792			56,306			63,603			96,327			82,226			7,823			145,829			104,150
Income tax expense	(483		)	—			(802		)	—			(880		)	—			(1,682		)	—
Net Income		$35,309			$56,306			$62,801			$96,327			$81,346			$7,823			$144,147			$104,150
Dividends on preferred stock	(4,474		)	—			(9,337		)	—			(4,457		)	(2,249		)	(13,794		)	(2,249		)
Accretion on preferred stock	(740		)	—			(1,493		)	—			(771		)	—			(2,264		)	—
Loss on redemption of preferred stock	—			—			(7,133		)	—			—			—			(7,133		)	—
Net Income Attributable to Common Shareholders		$30,095			$56,306			$44,838			$96,327			$76,118			$5,574			$120,956			$101,901

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.37			$0.86			$0.55			$1.47			$0.88			$0.07			$1.45			$1.44
Diluted		$0.36			$0.85			$0.54			$1.46			$0.85			$0.07			$1.42			$1.43

Weighted Average Common Shares Outstanding
Basic	82,058			65,767			81,802			65,479			86,727			81,053			83,461			70,728
Diluted	83,853			65,908			83,240			65,866			89,039			81,138			85,221			71,147

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)


	Common Stock			Additional Paid-in Capital				Accumulated Deficit				Total Shareholders’ Equity			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, 2017	81,454,621		$815	Additional Paid-in Capital			$1,926,056				($1,555,974	Total Shareholders’ Equity	)		$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		)
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares, net of forfeitures															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,
	2018			2017			2018			2017
Cash Flows From Operating Activities
Net income		$62,801			$96,327			$144,147			$104,150
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	136,897			113,454			217,005			181,018
(Gain) loss on derivatives, net	97,310			(51,381		)	152,698			(27,004		)
Cash (paid) received for derivative settlements, net	(38,448		)	1,258
Cash received (paid) for derivative settlements, net							(64,710		)	7,714
Loss on extinguishment of debt	8,676			—			8,676			—
Stock-based compensation expense, net	10,724			3,596			13,786			8,462
Deferred income taxes	529			—			1,063			—
Non-cash interest expense, net	1,262			2,074			1,878			2,961
Other, net	3,975			2,767			4,100			4,249
Changes in components of working capital and other assets and liabilities-
Accounts receivable	2,437			(8,094		)	(12,763		)	(25,885		)
Accounts payable	3,878			14,486			10,863			14,748
Accrued liabilities	(12,883		)	5,650			(9,336		)	11,970
Other assets and liabilities, net	(1,286		)	(982		)	(2,115		)	(1,786		)
Net cash provided by operating activities	275,872			179,155			465,292			280,597
Cash Flows From Investing Activities
Capital expenditures	(430,639		)	(290,625		)	(662,459		)	(433,561		)
Acquisitions of oil and gas properties	—			(16,533		)	—			(692,006		)
Deposit for acquisition of oil and gas properties	—			(75,000		)
Proceeds from divestitures of oil and gas properties, net	345,789			18,201
Deposit (paid for pending acquisition) received for pending divestiture of oil and gas properties							(21,500		)	6,200
Proceeds from divestitures of oil and gas properties							377,693			18,212
Other, net	(1,096		)	(2,479		)	(2,687		)	(3,804		)
Net cash used in investing activities	(85,946		)	(366,436		)	(308,953		)	(1,104,959		)
Cash Flows From Financing Activities
Redemptions of senior notes	(330,435		)	—
Issuance of senior notes							—			250,000
Redemptions of senior notes and other long-term debt							(330,435		)	—
Redemption of preferred stock	(50,030		)	—			(50,030		)	—
Borrowings under credit agreement	1,126,856			919,097			2,415,208			1,311,875
Repayments of borrowings under credit agreement	(933,156		)	(723,797		)	(2,396,671		)	(1,183,275		)
Payments of debt issuance costs	(627		)	(4,368		)
Payment of commitment fee for issuance of preferred stock	—			(5,000		)
Payments of debt issuance costs and credit facility amendment fees							(627		)	(8,964		)
Sale of common stock, net of offering costs							213,857			222,378
Sale of preferred stock, net of issuance costs							—			236,404
Payments of dividends on preferred stock	(9,337		)	—			(13,794		)	(2,249		)
Other, net	(638		)	(617		)	(972		)	(909		)
Net cash provided by (used in) financing activities	(197,367		)	185,315			(163,464		)	825,260
Net Decrease in Cash and Cash Equivalents	(7,441		)	(1,966		)
Net Increase (Decrease) in Cash and Cash Equivalents							(7,125		)	898
Cash and Cash Equivalents, Beginning of Period	9,540			4,194			9,540			4,194
Cash and Cash Equivalents, End of Period		$2,099			$2,228			$2,415			$5,092

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

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Operations

Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and natural gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

Consolidated Financial Statements

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

2. Summary of Significant Accounting Policies

~~Revenue Recognition~~Recently Adopted Accounting Standards

~~Impact of ASC 606 Adoption~~Revenue From Contracts with Customers. Effective January 1, 2018, the Company adopted ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASC 606”) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information for the three and ~~six~~nine months ended ~~June~~September 30, 2017 has not been recast and continues to be reported under the accounting standards in effect for that period. Additionally, adoption of ASC 606 did not impact net income attributable to common shareholders and the Company does not expect that it will do so in future periods.

The tables below ~~summarizes~~summarize the impact of adoption for the three and ~~six~~nine months ended ~~June~~September 30, 2018:


	Three Months Ended June 30, 2018								Three Months Ended September 30, 2018
	Under ASC 606		Under ASC 605		Increase		% Increase		Under ASC 606		Under ASC 605		Increase		% Increase
	(In thousands)								(In thousands)
Revenues
Crude oil		$229,798		$229,658		$140	0.1	%		$254,525		$254,382		$143	0.1	%
Natural gas liquids	21,269		20,139		1,130		5.6	%	33,798		32,018		1,780		5.6	%
Natural gas	12,906		12,272		634		5.2	%	15,052		14,280		772		5.4	%
Total revenues	263,973		262,069		1,904		0.7	%	303,375		300,680		2,695		0.9	%

Costs and Expenses
Lease operating	35,151		33,247		1,904		5.7	%	41,022		38,327		2,695		7.0	%

Income Before Income Taxes		$35,792		$35,792		$—	—	%		$82,226		$82,226		$—	—	%


	Six Months Ended June 30, 2018								Nine Months Ended September 30, 2018
	Under ASC 606		Under ASC 605		Increase		% Increase		Under ASC 606		Under ASC 605		Increase		% Increase
	(In thousands)								(In thousands)
Revenues
Crude oil		$424,717		$424,452		$265	0.1	%		$679,242		$678,834		$408	0.1	%
Natural gas liquids	38,171		36,235		1,936		5.3	%	71,969		68,253		3,716		5.4	%
Natural gas	26,365		25,159		1,206		4.8	%	41,417		39,439		1,978		5.0	%
Total revenues	489,253		485,846		3,407		0.7	%	792,628		786,526		6,102		0.8	%

Costs and Expenses
Lease operating	74,424		71,017		3,407		4.8	%	115,446		109,344		6,102		5.6	%

Income Before Income Taxes		$63,603		$63,603		$—	—	%		$145,829		$145,829		$—	—	%

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

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

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

Recently Issued Accounting Pronouncements

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

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

Revenue Recognition

The Company’s revenues are comprised solely of revenues from customers and include the sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on ~~our~~its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of ~~June~~September 30, 2018 and December 31, 2017, receivables from contracts with customers were ~~$87.1~~$100.2 million and $85.6 million, respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of income.

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

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

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

~~Recently Adopted Accounting Pronouncements~~

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

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

~~Recently Issued Accounting Pronouncements~~

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

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

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

Net Income Attributable to Common Shareholders Per Common Share

~~Supplemental~~The following table summarizes the calculation of net income attributable to common shareholders per common ~~share information is provided below:~~share:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017		2018			2017			2018			2017
	(In thousands, except per share amounts)								(In thousands, except per share amounts)
Net Income										$81,346			$7,823			$144,147			$104,150
Dividends on preferred stock									(4,457		)	(2,249		)	(13,794		)	(2,249		)
Accretion on preferred stock									(771		)	—			(2,264		)	—
Loss on redemption of preferred stock									—			—			(7,133		)	—
Net Income Attributable to Common Shareholders		$30,095		$56,306		$44,838		$96,327		$76,118			$5,574			$120,956			$101,901

Basic weighted average common shares outstanding	82,058		65,767		81,802		65,479		86,727			81,053			83,461			70,728
Effect of dilutive instruments	1,795		141		1,438		387
Dilutive effect of restricted stock and performance shares									1,272			85			967			253
Dilutive effect of common stock warrants									1,040			—			793			166
Diluted weighted average common shares outstanding	83,853		65,908		83,240		65,866		89,039			81,138			85,221			71,147

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.37		$0.86		$0.55		$1.47		$0.88			$0.07			$1.45			$1.44
Diluted		$0.36		$0.85		$0.54		$1.46		$0.85			$0.07			$1.42			$1.43

The table below presents the a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2018 and 2017:

Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(In thousands)
Basic weighted average common shares outstanding 82,058
65,767
81,802
65,479
Dilutive unvested restricted stock awards and units 833
141
640
387
Dilutive unvested performance shares 134
—
158
—
Dilutive exercisable common stock warrants 828
—
640
—
Diluted weighted average common shares outstanding 83,853
65,908
83,240
65,866

~~The table below presents a summary of the common shares outstanding that were excluded from 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 ~~three and six months ended June 30, 2018 and 2017, as their inclusion would be anti-dilutive:~~periods presented:

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
	(In thousands)
Anti-dilutive restricted stock and performance shares	—	730	5	120
Anti-dilutive common stock warrants	—	152	—	—
Total weighted average anti-dilutive securities	—	882	5	120

3. Acquisitions and Divestitures of Oil and Gas Properties

2018 Acquisitions and Divestitures

~~ExL~~Devon Acquisition.On August ~~10, 2017,~~13, 2018, the Company ~~closed on the acquisition~~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 ~~located~~ in the Delaware Basin in Reeves and Ward ~~Counties,~~counties, Texas (the ~~“ExL~~“Devon Properties”) ~~from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”)~~ for aggregate cash consideration of $679.8 million (the “ExL Acquisition”). See “Note 10. Derivative Instruments” for information regarding the contingent consideration arrangement associated with the ExL Acquisition.

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

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

$96,239

Net income attributable to common shareholders
$42,048

$76,851

~~Divestitures~~

~~Eagle Ford.~~ ~~On January 31, 2018, the Company sold a portion of its assets in the Eagle Ford Shale to EP Energy E&P Company, L.P. The Company received aggregate net proceeds of $245.7 million, which represents~~ an agreed upon price of ~~$245.0~~$215.0 million, ~~plus~~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 and $183.4 million upon initial closing on October 17, 2018, which ~~were~~included purchase price adjustments primarily related to the net cash flows from the effective date to the closing ~~date.~~date, for an estimated aggregate purchase price of $204.9 million. The final purchase price remains subject to post-closing adjustments.

Under one of the Company’s existing joint operating agreements covering acreage in the vicinity of the Devon Properties, the other party to the joint operating agreement has a right to purchase a 20% interest in certain of the acres within the Devon Properties acquired by the Company at a price based on the Company’s cost to acquire the Devon Properties. This right is exercisable for a 30-day period after the Company delivers a specified notice following the closing of the Devon Acquisition and, if not exercised, will expire in the fourth quarter of 2018. To the extent that the other party exercises its right to make such purchase, the Company’s interests in the Devon Properties will be reduced and the proceeds received will be recognized as a reduction of proved oil and gas properties.

The Company funded the Devon Acquisition with net proceeds from the common stock offering completed on August 17, 2018, which, pending the closing of the Devon Acquisition, were used to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 9. Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering.

The Devon Acquisition will be accounted for as a business combination. The Company has not completed its initial allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated acquisition date fair values. The Company will disclose the allocation of the purchase price as well as other related disclosures in its Annual Report on Form 10-K for the year ended December 31, 2018.

~~Niobrara.~~Delaware Basin Divestiture.On ~~January 19,~~July 11, 2018, the Company ~~sold~~closed on the divestiture of certain non-operated assets in the Delaware Basin for an agreed upon price of $30.0 million, with an effective date of May 1, 2018, subject to customary purchase price adjustments. The Company received $31.4 million upon closing on July 11, 2018 and paid $0.5 million upon post-closing on October 22, 2018, for aggregate net proceeds of $30.9 million.

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 upon post-closing 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. Estimated~~Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. The Company received $14.0 million as a deposit on November 20, 2017, $122.6 million upon closing on January 19, 2018, and paid $1.0 million upon post-closing on August 14, 2018, for aggregate net proceeds ~~are $134.7 million, subject~~of $135.6 million. As part of this divestiture, the Company agreed to ~~post-closing adjustments.~~a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for ~~information regarding the contingent consideration arrangement associated with this divestiture.~~further details.

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

2017 Acquisitions and Divestitures

~~Marcellus.~~ExL Acquisition. On June 28, 2017, the Company entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward counties, Texas for an agreed upon price of $648.0 million, with an effective date of May 1, 2017, subject to customary purchase price adjustments (the “ExL Acquisition”). The Company paid $75.0 million as a deposit on June 28, 2017, $601.0 million upon closing on August 10, 2017, and $3.8 million upon post-closing on December 8, 2017 for aggregate cash consideration of $679.8 million, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. As part of the ExL Acquisition, the Company agreed to a contingent consideration arrangement (the “Contingent ExL Consideration”), which was determined to be an embedded derivative. As a result, the liability is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. 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 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. The fair value of the Contingent ExL Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included forward oil and gas price curves, volatility factors, and a risk adjusted discount rate. See “Note 11. Fair Value Measurements” for further details.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.



	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	294,754
Unproved properties	443,194
Total oil and gas properties		$737,948
Total assets acquired		$738,054

Liabilities
Revenues and royalties payable		$5,785
Asset retirement obligations	153
Contingent ExL Consideration	52,300
Total liabilities assumed		$58,238
Net Assets Acquired		$679,816

The results of operations for the ExL Acquisition have been included in the Company’s consolidated statements of income since the August 10, 2017 closing date, including total revenues and net income attributable to common shareholders for the three and nine months ended September 30, 2018 and 2017 as shown in the table below:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(In thousands)
Total revenues		$71,525		$14,016		$167,764		$14,016

Net Income Attributable to Common Shareholders		$57,466		$11,393		$134,317		$11,393

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three and nine months ended September 30, 2017, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition.



	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	(In thousands, except per share amounts)
Total revenues		$189,499		$534,607
Net Income Attributable to Common Shareholders		$14,654		$115,053

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.18		$1.63
Diluted		$0.18		$1.62

Marcellus Divestiture. On October 5, 2017, the Company entered into a purchase and sale agreement with BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an agreed upon price of $84.0 million. The Company received $6.3 million into escrow as a deposit on October 5, 2017 and $67.6 million upon closing on November 21, 2017, for aggregate net proceeds of $73.9 million. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Marcellus Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the

fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

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

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

Utica Divestiture. On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale for an agreed upon price of $62.0 million. The Company received $6.2 million as a deposit on August 31, 2017, $54.4 million upon closing on November 15, 2017, and $2.5 million upon post-closing on December 28, 2017, for aggregate net proceeds of $63.1 million. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Utica Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

Delaware Basin Divestiture. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for aggregate net proceeds of $15.3 million.

The aggregate net proceeds for each of the 2017 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized.

2016 Acquisitions and Divestitures

Sanchez Acquisition. On October 24, 2016, the Company entered into a purchase and sale agreement with Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation to acquire oil and gas properties located in the Eagle Ford Shale for an agreed upon price of $181.0 million, with an effective date of June 1, 2016, subject to customary purchase price adjustments. The Company paid $10.0 million as a deposit on October 24, 2016, $143.5 million upon initial closing on December 14, 2016, and $7.0 million and $9.8 million on January 9, 2017 and April 13, 2017, respectively, for leases that were not conveyed to the Company at the time of initial closing, for aggregate cash consideration of $170.3 million, which included purchase price adjustments primarily related to the net cash flows from the effect date to the closing date.

The Company did not have any material divestitures in 2016.

4. Property and Equipment, Net

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


	June 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
	(In thousands)						(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,744,434			$5,615,153			$5,988,301			$5,615,153
Accumulated depreciation, depletion and amortization and impairments	(3,784,483		)	(3,649,806		)	(3,863,534		)	(3,649,806		)
Proved properties, net	1,959,951			1,965,347			2,124,767			1,965,347
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	539,836			612,589			516,537			612,589
Capitalized interest	58,056			47,698			62,738			47,698
Total unproved properties, not being amortized	597,892			660,287			579,275			660,287
Other property and equipment	27,223			25,625			28,134			25,625
Accumulated depreciation	(16,641		)	(15,449		)	(17,249		)	(15,449		)
Other property and equipment, net	10,582			10,176			10,885			10,176
Total property and equipment, net		$2,568,425			$2,635,810			$2,714,927			$2,635,810

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was ~~$13.74~~$13.29 and ~~$12.43~~$13.04 for the three months ended ~~June~~September 30, 2018 and 2017, respectively, and ~~$13.73~~$13.57 and ~~$12.55~~$12.73 for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively.

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling ~~$6.1~~$2.9 million and ~~$1.9~~$3.3 million for the three months

ended ~~June~~September 30, 2018 and 2017, respectively, and ~~$12.7~~$15.6 million and ~~$7.3~~$10.6 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling ~~$8.7 million and $4.0~~$8.5 million for the three months ended ~~June~~September 30, 2018 and 2017 ~~respectively,~~ and ~~$19.1~~$27.6 million and ~~$7.8~~$16.2 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively.

5. Income Taxes

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense or benefit to interim periods. The rates are the ratio of estimated annual income tax expense or benefit to estimated annual income or loss before income taxes by taxing jurisdiction, ~~except for discrete items, which are~~excluding significant unusual or infrequent items, ~~for~~the tax effects of statutory rate changes, certain changes in the assessment of the realizability of deferred tax assets, and excess tax benefits or deficiencies related to the vesting of stock-based compensation awards, which ~~income taxes~~ are ~~computed and recorded~~recognized as discrete items in the interim period in which the discrete item occurs. The estimated annual effective income tax rates are applied to the year-to-date income or loss before income taxes by taxing jurisdiction to determine the income tax expense or benefit allocated to the interim period. The Company updates its estimated annual effective income tax rates on a quarterly basis considering the geographic mix of the estimated annual income or loss attributable to the tax jurisdictions in which the Company operates.they occur.

The Company’s income tax expense differs from the income tax expense 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, 2018 and 35% for the three and ~~six~~nine months ended ~~June~~September 30, 2017, to income before income taxes as follows:

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

$56,306

$63,603

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

($802 )
$—

Significant changes in the Company’s operations, including the ExL Acquisition in the Delaware Basin in the third quarter of 2017 and divestitures of substantially all of the Company’s assets in the Utica and Marcellus in the fourth quarter of 2017 and the Niobrara in the first quarter of 2018, resulted in changes to the Company’s state apportionment for estimated state deferred tax liabilities. As a result of these changes, the Company recorded current and deferred state income tax expense of $0.5 million and $0.8 million for the three and six months ended June 30, 2018, respectively.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In thousands)
Income before income taxes		$82,226			$7,823			$145,829			$104,150
Income tax expense at the U.S. federal statutory rate	(17,267		)	(2,738		)	(30,624		)	(36,452		)
State income tax expense, net of U.S. federal income tax benefit	(881		)	(247		)	(1,687		)	(1,974		)
Tax deficiencies related to stock-based compensation	(10		)	(273		)	(2,552		)	(3,029		)
Decrease in valuation allowance due to current period activity	17,400			3,253			33,849			41,570
Other	(122		)	5			(668		)	(115		)
Income tax expense		($880	)		$—			($1,682	)		$—

Tax Cuts and Jobs Act

On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the U.S. federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. Due to the uncertainty regarding the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 which allowed the Company to provide a provisional estimate of the impacts of the Act in earnings for the year ended December 31, 2017 and also provided a one-year measurement period in which the Company would record additional impacts from the enactment of the Act as they are identified. ~~As of June 30,~~In August 2018, the Internal Revenue Service issued Notice 2018-68, Guidance on the Application of Section 162(m) (“Notice 2018-68”), which provides initial guidance on the application of Section 162(m), as amended. Notice 2018-68 provided guidance regarding the group of covered employees subject to Section 162(m)’s deduction limit under the Act and the scope of transition relief available under the Act. The Company is currently evaluating the impact of Notice 2018-68, but as of September 30, 2018, has not made any changes to the provisional estimate recorded in earnings for the year ended December 31, 2017. While the Company has made a reasonable estimate of the effects on its existing deferred tax balances, it has not completed its accounting for the tax effects of the enactment of the Act and will continue to monitor provisions with discrete rate impacts ~~such as the limitation on executive compensation for subsequent events~~ and additional guidance provided within the one year measurement period.

Deferred Tax ~~Assets~~Asset Valuation Allowance

Primarily as a result of the impairments of proved oil and gas properties recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016, the Company had a cumulative historical three year pre-tax loss and a netThe deferred tax asset ~~position at June~~valuation allowance was $299.1 million and $333.0 million as of September 30, ~~2018. The~~2018 and December 31, 2017, respectively. Decreases in the valuation allowance for the three months and nine months ended September 30, 2018 and 2017 were based primarily on the pre-tax income recorded during those periods.

Throughout 2017 and the first nine months of 2018, the Company ~~then assessed the realizability of~~maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and ~~beginning in the third quarter of 2015 and continuing through the second quarter of 2018, the Company concluded~~negative), that it was more likely than not that

the deferred tax assets ~~will~~would not be ~~realized and that~~realized. The Company intends to maintain a full valuation allowance ~~was required to reduce the net~~against its deferred tax assets until there is sufficient evidence to ~~zero. As~~support the reversal of ~~June 30, 2018 and December 31, 2017, the~~such valuation ~~allowance was $316.5 million and $333.0 million, respectively. See~~

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

6. Long-Term Debt

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


	June 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
	(In thousands)						(In thousands)
Senior Secured Revolving Credit Facility due 2022		$485,000			$291,300			$309,837			$291,300
7.50% Senior Notes due 2020	130,000			450,000			130,000			450,000
Unamortized premium for 7.50% Senior Notes	139			579			124			579
Unamortized debt issuance costs for 7.50% Senior Notes	(1,095		)	(4,492		)	(980		)	(4,492		)
6.25% Senior Notes due 2023	650,000			650,000			650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(7,554		)	(8,208		)	(7,219		)	(8,208		)
8.25% Senior Notes due 2025	250,000			250,000			250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(4,183		)	(4,395		)	(4,073		)	(4,395		)
Other long-term debt due 2028	—			4,425			—			4,425
Long-term debt		$1,502,307			$1,629,209			$1,327,689			$1,629,209

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of ~~June~~September 30, 2018,, had a borrowing base of $1.0 billion, with an elected commitment amount of $900.0 million, and borrowings outstanding of ~~$485.0~~$309.8 million at a weighted average interest rate of ~~3.74%~~3.87%. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”) have not been redeemed or refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. See “Note 14. Subsequent Events” for details regarding the maturity date of the credit agreement upon redemption of the remaining $130.0 million outstanding aggregate principal amount of its 7.50% Senior Notes. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

On January 31, 2018, as a result of the ~~divestiture in the~~ Eagle Ford ~~Shale discussed above,~~divestiture, the Company’s borrowing base under the senior secured revolving credit facility was reduced from $900.0 million to $830.0 million, however, the elected commitment amount remained unchanged at $800.0 million. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for details of the Eagle Ford divestiture.

On May 4, 2018, the Company entered into the twelfth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $1.0 billion, with an elected commitment amount of $900.0 million, until the next redetermination thereof, (ii) reduce the applicable ~~margin~~margins for Eurodollar loans from ~~2.0%-3.0%~~2.00%-3.00% to ~~1.5%-2.5%~~1.50%-2.50% and base rate loans from 1.00%-2.00% to 0.50%-1.50%, each depending on level of facility usage, (iii) amend the covenant limiting payment of dividends and distributions on equity to increase the Company’s ability to make dividends and distributions on its equity interests and (iv) amend certain other provisions, in each case as set forth therein.

On October 29, 2018, the Company entered into the thirteenth amendment to its credit agreement governing the revolving credit facility. See “Note 14. Subsequent Events” for further details of the thirteenth amendment.

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

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



Ratio of Outstanding Borrowings to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	0.50%	1.50%	0.375%
Greater than or equal to 25% but less than 50%	0.75%	1.75%	0.375%
Greater than or equal to 50% but less than 75%	1.00%	2.00%	0.500%
Greater than or equal to 75% but less than 90%	1.25%	2.25%	0.500%
Greater than or equal to 90%	1.50%	2.50%	0.500%

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA will be 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. As of ~~June~~September 30, 2018, the ratio of Total Debt to EBITDA was ~~2.53~~1.95 to 1.00 and the Current Ratio was ~~1.49~~1.84 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings.

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

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

Redemptions of 7.50% Senior Notes

During the first quarter of 2018, the Company redeemed $320.0 million of the outstanding aggregate principal amount of its 7.50% Senior Notes at a price equal to 101.875% of par. Upon the redemptions, the Company paid $336.9 million, which included redemption premiums of $6.0 million ~~as well as~~and accrued and unpaid interest of $10.9 ~~million~~million. The redemptions were funded primarily from the ~~last interest payment date up to, but not including,~~net proceeds received from the ~~redemption date.~~divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of these divestitures. As a result of the redemptions, the Company recorded a loss on extinguishment of debt of $8.7 million, which included the redemption premiums of $6.0 million ~~paid to redeem the notes~~ and ~~non-cash charges of $2.7 million attributable to~~ the write-off of associated unamortized ~~premium~~premiums and debt issuance ~~costs.~~costs of $2.7 million.

See “Note 14. Subsequent Events” for details of the notice of conditional redemption for the remaining $130.0 million outstanding aggregate principal amount of its 7.50% Senior Notes.

Redemption of Other Long-Term Debt

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.

Issuance of 8.25% Senior Notes

On July 14, 2017, the Company closed a public offering of $250.0 million ~~from~~aggregate principal amount of 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The Company used the ~~last interest payment date up~~proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to ~~but not including,~~fund a portion of the ~~redemption date.~~ExL Acquisition and for general corporate purposes. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.

7. Commitments and Contingencies

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

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

8. Preferred Stock and Common Stock Warrants

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

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



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

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

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

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



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

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

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

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

Upon the occurrence of certain changes of control.

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

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

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

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

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

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

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



	~~June 30, 2018~~Carrying Amount of Preferred Stock
	(In thousands)
~~Preferred Stock, beginning of period~~December 31, 2017		$214,262
Redemption of ~~preferred stock~~Preferred Stock	(42,897		)
Accretion on Preferred Stock	~~1,493~~2,264
~~Preferred Stock, end of period~~September 30, 2018		$~~172,858~~173,629

~~Preferred Stock Dividends, Accretion, and~~ Loss on Redemption of Preferred Stock

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

~~For the three months ended June 30,~~ 2018, the Company ~~declared and paid $4.5 million~~redeemed 50,000 shares of ~~cash dividends to the holders of record~~Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, ~~on June 15, 2018. For the six months ended June 30, 2018, the Company declared and paid $9.3~~for $50.5 million, ~~of cash dividends to the holders~~consisting of the ~~Preferred Stock on June 15, 2018 and March 15, 2018.~~

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

As a result of the redemption described above, the Company recorded a loss on redemption of preferred stock of $7.1 million, which included $0.1 million of direct costs incurred as a result of the redemption and a non-cash charge of $7.0 million attributable to the difference between $50.0 million ~~which was the consideration transferred to the holders of the Preferred Stock excluding~~redemption price and $0.5 million accrued and unpaid ~~dividends, and~~dividends. 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 ~~which was 20% of the~~redemption date carrying value of the Preferred ~~Stock on the date of redemption.~~Stock.

9. Shareholders’ Equity and Stock-Based Compensation

~~Equity-Based Incentive Awards Plans~~Sales of Common Stock

On August 17, 2018, the Company completed a public offering of 9.5 million shares of its common stock at a price per share of $22.55. The Company used the proceeds of $213.9 million, net of offering costs, to fund the Devon Acquisition and for general corporate purposes. Pending the closing of the Devon Acquisition, the Company used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the Devon Acquisition.

On July 3, 2017, the Company completed a public offering of 15.6 million shares of its common stock at a price per share of $14.28. The Company used the proceeds of $222.4 million, net of offering costs, to fund a portion of the ExL Acquisition and for general corporate purposes. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.

Stock-Based Compensation

The Company grants equity-based incentive awards under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”) and the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The 2017 Incentive Plan replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”) and, from the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan. However, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. Under the 2017 Incentive Plan, the Company ~~can~~may grant restricted stock awards and units, stock appreciation rights that can be settled in cash or shares of common stock, ~~or cash at the option of the Company,~~ performance shares, and stock options ~~and cash awards~~ to employees, independent contractors, and non-employee directors. Under the Cash SAR Plan, the Company ~~can~~may grant stock appreciation rights that may only be settled in cash ~~(“Cash SARs”)~~ to employees and independent contractors.

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

1.35 shares against the Maximum Share Limit. Each stock option and stock appreciation right to be settled in shares of common stock ~~(“Stock SAR”)~~ granted under the 2017 Incentive Plan counts as 1.00 share against the Maximum Share Limit. ~~Each~~Stock appreciation rights to be settled in cash granted under the 2017 Incentive Plan and stock appreciation ~~right~~rights granted under the Cash SAR Plan (collectively, “Cash SARs”) do not count against the Maximum Share Limit. Restricted stock awards and units, performance shares, and Cash SARs activity during the nine months ended September 30, 2018 is presented below. The Company has not granted stock appreciation rights to be settled in shares of common stock or cash (“Incentive SAR”) granted under the 2017 Incentive Plan counts as 1.00 share against the Maximum Share Limit up to the date the Company, if it so chooses, affirmatively elects to settle theand has no outstanding stock appreciation right in cash. Each stock appreciation right to be settled in cash (“Incentive Cash SAR”) granted under the 2017 Incentive Plan or Cash SAR does not count against the Maximum Share Limit.options. As of ~~June~~September 30, 2018, there were ~~326,774~~296,654 shares of common ~~shares remaining~~stock available for grant under the 2017 Incentive Plan.

Restricted Stock Awards and Units

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

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


	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
Unvested restricted stock awards and units, beginning of period	1,482,655			$28.07	1,482,655			$28.07
Granted	1,348,415			$14.68	1,391,422			$15.07
Vested	(608,904	)		$31.43	(615,762	)		$31.44
Forfeited	(10,993	)		$19.17	(23,880	)		$18.51
Unvested restricted stock awards and units, end of period	2,211,173			$19.02	2,234,435			$19.14

During the ~~six~~nine months ended ~~June~~September 30, 2018, the Company granted ~~1,348,415~~1,391,422 restricted stock awards and units primarily consisting of 1,343,412 restricted stock units to employees and independent contractors as part of its annual grant of long-term equity incentive awards during the first quarter of 2018. These restricted stock units had a grant date fair value of $19.7 million and ~~will~~ vest ratably over aan approximate three-year period.

~~Stock Appreciation Rights (“SARs”)~~ During the third quarter of 2018, the Company granted 33,536 restricted stock units to its non-employee directors, which had a grant date fair value of $0.9 million and will vest on the earlier of the date of the 2019 Annual Meeting of Shareholders and June 30, 2019.

As of ~~June~~September 30, 2018, all outstanding SARs are either Cash SARs or Incentive Cash SARs and will be settled in cash. The liability for SARs as of June 30, 2018 was $8.7 million, all of which was classified as “Other current liabilities,” in the consolidated balance sheets. As of December 31, 2017, the liability for SARs was $4.4 million, all of which was classified as “Other liabilities” in the consolidated balance sheets. Unrecognizedunrecognized compensation costs related to unvested ~~SARs was $11.3~~restricted stock awards and units were $26.8 million ~~as of June 30, 2018,~~ and will be recognized over a weighted average period of ~~2.6~~2.0 years.

Cash SARs

The table below summarizes the Cash SAR activity for ~~SARs for~~ the ~~six~~nine months ended ~~June~~September 30, 2018:


	SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)		Cash SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)
Outstanding, beginning of period	714,238		$27.12						714,238		$27.12
Granted	616,686		$14.67						616,686		$14.67
Exercised	—		$—					$—	—		$—					$—
Forfeited	—		$—						—		$—
Expired	—		$—						—		$—
Outstanding, end of period	1,330,924		$21.35	4.8		$9.1			1,330,924		$21.35	4.6		$6.5
Vested, end of period	543,018		$27.18						543,018		$27.18
Vested and exercisable, end of period	543,018		$27.18	3.04		$0.5			—		$27.18	2.8		$—

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

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



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

~~Performance Shares~~

The liability for Cash SARs as of September 30, 2018 was $7.9 million, all of which was classified as “Other current liabilities,” in the consolidated balance sheets. As of ~~June 30, 2018, unrecognized~~December 31, 2017, the liability for Cash SARs was $4.4 million, all of which was classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested ~~performance shares was $2.9~~Cash SARs were $8.7 million as of September 30, 2018, and will be recognized over a weighted average period of ~~2.2~~2.4 years.

Performance Shares

The table below summarizes performance share activity for the ~~six~~nine months ended ~~June~~September 30, 2018:



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


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

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

~~Also during~~During the ~~six months ended June 30,~~first quarter of 2018, ~~the Company vested 49,458 performance shares that were granted in 2015. As~~as a result of the Company’s final TSR ranking during the performance period, a multiplier of 88% was applied to the 56,517 target performance shares that were granted in 2015, resulting in the vesting of 49,458 shares and 7,059 ~~performance~~ shares that did not vest.

The grant date fair value of the performance shares, calculated using a Monte Carlo simulation, was $1.8 million. The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the ~~six~~nine months ended ~~June~~September 30, 2018:



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

As of September 30, 2018, unrecognized compensation costs related to unvested performance shares were $2.5 million and will be recognized over a weighted average period of 2.0 years.

Stock-Based Compensation Expense, Net

Stock-based compensation expense associated with restricted stock awards and units, Cash SARs and performance shares, net of amounts capitalized, is ~~reflected as~~included in “General and administrative, ~~expense,~~ net” in the consolidated statements of income.

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2018			2017			2018			2017
	(In thousands)												(In thousands)
Restricted stock awards and units		$4,720			$5,024			$9,804			$10,873			$4,487			$5,311			$14,291			$16,184
SARs	5,788			(3,783		)	4,373			(7,469		)
Cash SARs													(868		)	429			3,505			(7,040		)
Performance shares	406			574			963			1,280			411			581			1,374			1,861
	10,914			1,815			15,140			4,684			4,030			6,321			19,170			11,005
Less: amounts capitalized to oil and gas properties	(3,708		)	(233		)	(4,416		)	(1,088		)	(968		)	(1,455		)	(5,384		)	(2,543		)
Total stock-based compensation expense, net		$7,206			$1,582			$10,724			$3,596			$3,062			$4,866			$13,786			$8,462

10. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to ~~reduce its exposure to~~mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and ~~thereby~~ achieve a more predictable level of cash ~~flows to support~~flow. Since the Company derives a significant portion of its revenues from sales of crude oil, crude oil price volatility represents the Company’s ~~capital expenditure program and fixed costs.~~

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

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

Price ~~Swaps:~~ swaps~~The Company receives~~ are settled based on differences between a fixed price and the settlement price of a referenced index. If the settlement price of the referenced index is below the fixed price, the Company receives the difference from the counterparty. If the referenced settlement price is above the fixed price, the Company pays ~~an index price~~the difference to the ~~counterparty over specified periods for contracted volumes.~~counterparty.

~~Three-Way Collars:~~ Three-way collars~~A three-way collar is a combination~~ consist of ~~options including~~ a purchased put option ~~(fixed floor~~(floor price), a sold call option ~~(fixed ceiling~~(ceiling price) and a sold put option ~~(fixed sub-floor~~(sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the published index price is and are settled based on differences between the ~~fixed~~floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and ~~the fixed~~ sub-floor ~~price or is above the fixed ceiling price, the Company receives the fixed floor price or pays the index price, respectively.~~price. If the settlement price of the referenced index ~~price~~ is below the ~~fixed~~ sub-floor price, the Company receives the difference between the floor price and sub-floor price from the counterparty. If the settlement price of the referenced index is between the floor price ~~plus~~and sub-floor price, the Company receives the difference between the ~~fixed~~ floor price and the ~~fixed sub-floor price.~~settlement price of the referenced index from the counterparty. If the settlement price of the referenced index ~~price~~ is between the ~~fixed~~ floor price and ~~fixed~~ ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty.

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

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

The referenced index of the Company’s price swaps, three-way collars and sold call options is U.S. New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) for crude oil, NYMEX Henry Hub for natural gas and OPIS Mont Belvieu Non-TET (“OPIS”) for NGL products, as applicable. The prices received by the Company for the sale of its production generally vary from these referenced index prices due to adjustments for delivery location (basis) and other factors. The referenced indexes of the Company’s basis swaps, which are used to mitigate location price risk for a portion of its production, are Argus WTI Cushing (“WTI Cushing”) and the applicable index price of the Company’s crude oil sales contracts is Argus WTI Midland (“WTI Midland”) for its Delaware Basin crude oil production and Argus Light Louisiana Sweet (“LLS”) for its Eagle Ford crude oil production.

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

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

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

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

~~Premiums: In order to increase the fixed price on a portion of the Company’s existing sold call options, the Company incurred premiums on its purchased call options. Additionally, in order to obtain a~~ higher floor price and/or higher ceiling ~~price, the Company incurred premiums on certain of its three-way collars.~~price. Payment of these premiums are deferred until the applicable contracts settle on a monthly basis ~~throughout~~over the term of the contract or, in some cases, during the final 12 months of the contract and are referred to as deferred premium obligations.

~~The following table sets forth a summary~~As of ~~the Company’s outstanding crude oil derivative positions as of June~~September 30, 2018, the Company had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:

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

$49.55

$—

$—

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



Commodity	Period	Type of Contract	Index	Volumes (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	4Q18	Price Swaps	NYMEX WTI	6,000		$49.55	—		—		—		—
Crude oil	4Q18	Three-Way Collars	NYMEX WTI	24,000	—			$39.38		$49.06		$60.14	—
Crude oil	4Q18	Basis Swaps	LLS-WTI Cushing	18,000	—		—		—		—			$5.11
Crude oil	4Q18	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			($0.10	)
Crude oil	4Q18	Sold Call Options	NYMEX WTI	3,388	—		—		—			$71.33	—

Crude oil	2019	Three-Way Collars	NYMEX WTI	21,000	—			$40.71		$49.80		$67.80	—
Crude oil	2019	Basis Swaps	LLS-WTI Cushing	3,000	—		—		—		—			$4.57
Crude oil	2019	Basis Swaps	WTI Midland-WTI Cushing	7,389	—		—		—		—			($4.82	)
Crude oil	2019	Sold Call Options	NYMEX WTI	3,875	—		—		—			$73.66	—

Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	13,000	—		—		—		—			($1.27	)
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—

Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			$0.03


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


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

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



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)
NGLs	4Q18	Price Swaps	OPIS-Ethane	2,200		$12.01	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Propane	1,500		$34.23	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Butane	200		$38.85	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Isobutane	600		$38.98	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Natural Gasoline	600		$55.23	—	—	—	—

Period Type of Contract Index
Volumes
(Bbls/d)

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

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

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

Period Type of Contract Index
Volumes
(MMBtu/d)

Fixed Price
($/MMBtu)

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

$3.01

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



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	4Q18	Price Swaps	NYMEX Henry Hub	25,000		$3.01	—	—	—		—
Natural gas	4Q18	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.25	—

Natural gas	2019	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.25	—

Natural gas	2020	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.50	—

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

Counterparties to the Company’s commodity derivative instruments who are also lenders under the Company’s credit agreement (“Lender Counterparty”) allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the Lender Counterparty with the collateral securing the credit

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

Because each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with seventeen counterparties to minimize its credit exposure to any individual counterparty.

Contingent Consideration Arrangements

~~In connection with~~The purchase and sale agreements of the ExL Acquisition and ~~in each of the~~ divestitures of the Company’s assets in the Niobrara, ~~in the first quarter of 2018 and the~~ Marcellus and Utica, ~~in the fourth quarter of 2017, the Company agreed to~~included contingent consideration arrangements that ~~could allow~~entitle the Company to receive or ~~be required~~require the Company to pay ~~certain~~specified amounts if commodity prices ~~are above specific~~exceed specified thresholds, which are summarized in the table below. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” ~~included in this Quarterly Report on Form 10-Q as well as “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” included in the 2017 Annual Report~~ for details of ~~the ExL Acquisition~~these acquisitions and ~~each of the divestitures discussed above.~~divestitures.


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

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

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

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

(1)

The price used to determine whether the ~~specific~~specified threshold for each year has been met ~~is the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration~~ for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration ~~and~~is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration. The price used to determine whether the specified threshold for each year has been met for the Marcellus Contingent Consideration is the average monthly settlement price ~~of a~~per MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc. ~~for the Contingent Marcellus Consideration.~~

Derivative Assets and Liabilities

~~All commodity~~Commodity derivative instruments and contingent consideration arrangements are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. As of September 30, 2018, the Company had $9.8 million classified as current derivative assets and $49.2 million classified as current derivative liabilities, representing the first cash receipts and payments, expected to occur in January 2019, from settlement of contingent consideration assets and liabilities. The deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity derivative instrument ~~fair value~~ asset or liability fair values pursuant to the netting ~~arrangements~~provisions of the ISDAs described above. Each of the contingent consideration arrangements discussed above were determined to be embedded derivatives and are recorded in the consolidated balance sheets as either an asset or liability measured at fair value at the acquisition or divestiture date, as well as each subsequent balance sheet date.

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


	June 30, 2018									September 30, 2018
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)									(In thousands)
Commodity derivative instruments		$32,422			($31,259	)		$1,163			$19,408			($18,985	)		$423
Contingent Niobrara Consideration	4,820			—			4,820			4,920			—			4,920
Contingent Marcellus Consideration	130			—			130
Contingent Utica Consideration	4,815			—			4,815			4,915			—			4,915
Derivative assets		$42,187			($31,259	)		$10,928			$29,243			($18,985	)		$10,258
Commodity derivative instruments	13,418			(13,418		)	—			12,028			(12,028		)	—
Contingent Niobrara Consideration	5,150			—			5,150			6,755			—			6,755
Contingent Marcellus Consideration	1,400			—			1,400			1,315			—			1,315
Contingent Utica Consideration	5,730			—			5,730			7,300			—			7,300
Other assets		$25,698			($13,418	)		$12,280			$27,398			($12,028	)		$15,370

Commodity derivative instruments		($118,953	)		$21,813			($97,140	)		($123,611	)		$9,876			($113,735	)
Deferred premium obligations	(9,446		)	9,446			—			(9,109		)	9,109			—
Contingent ExL Consideration	(48,380		)	—			(48,380		)	(49,160		)	—			(49,160		)
Derivative liabilities-current		($176,779	)		$31,259			($145,520	)		($181,880	)		$18,985			($162,895	)
Commodity derivative instruments	(40,006		)	5,748			(34,258		)	(45,532		)	6,314			(39,218		)
Deferred premium obligations	(7,670		)	7,670			—			(5,714		)	5,714			—
Contingent ExL Consideration	(53,675		)	—			(53,675		)	(62,885		)	—			(62,885		)
Derivative liabilities-non current		($101,351	)		$13,418			($87,933	)		($114,131	)		$12,028			($102,103	)


	December 31, 2017									December 31, 2017
	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		$4,869			($4,869	)		$—			$4,869			($4,869	)		$—
Derivative assets		$4,869			($4,869	)		$—			$4,869			($4,869	)		$—
Commodity derivative instruments	9,505			(9,505		)	—			9,505			(9,505		)	—
Contingent Niobrara Consideration	—			—			—
Contingent Marcellus Consideration	2,205			—			2,205			2,205			—			2,205
Contingent Utica Consideration	7,985			—			7,985			7,985			—			7,985
Other assets		$19,695			($9,505	)		$10,190			$19,695			($9,505	)		$10,190

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

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

(Gain) Loss on Derivatives, Net

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of the Company’s commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the changes occur. ~~All deferred~~Deferred premium obligations associated with the Company’s commodity

derivative instruments are recognized inas “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the deferred premium obligations are incurred. The ~~effects of commodity derivative instruments, deferred premium obligations and contingent consideration arrangements~~net (gain) loss on derivatives in the consolidated statements of income for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 are summarized below:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2018			2017			2018			2017
	(In thousands)												(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil derivatives		$53,437			($29,736	)		$82,948			($48,163	)
NGL derivatives	6,564			—			4,799			—
Natural gas derivatives	153			(3,883		)	(2,892		)	(10,719		)
Crude oil														$43,664			$8,409			$126,612			($39,754	)
NGL													5,086			—			9,885			—
Natural gas													(192		)	(2,183		)	(3,084		)	(12,902		)
Deferred premium obligations	—			7,554			—			7,501			—			10,151			—			17,652
Contingent ExL Consideration	10,600			—			16,430			—			9,990			8,000			26,420			8,000
Contingent Niobrara Consideration	(1,705		)	—			(2,090		)	—			(1,705		)	—			(3,795		)	—
Contingent Marcellus Consideration	205			—			675			—			215			—			890			—
Contingent Utica Consideration	(1,540		)	—			(2,560		)	—			(1,670		)	—			(4,230		)	—
(Gain) Loss on Derivatives, Net		$67,714			($26,065	)		$97,310			($51,381	)		$55,388			$24,377			$152,698			($27,004	)

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements of commodity ~~derivatives,~~derivative instruments, including deferred premium obligations, and ~~settlements of~~ contingent consideration arrangements result in cash ~~receipts~~received or ~~payments~~paid during the period and are ~~presented~~recognized as “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows. Cash ~~payments made to settle~~received or paid in settlement of contingent consideration assets or liabilities, respectively, are classified as cash flows from financing activities up to the divestiture or acquisition date fair value with any excess classified as cash flows from operating activities. For the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, ~~the Company did not receive or pay cash for the~~there were no settlements of contingent consideration arrangements. The net cash received (paid) for derivative settlements ~~of commodity derivatives and deferred premium obligations~~ in the consolidated statements of cash flows for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 are summarized below:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2018			2017			2018			2017
Cash Flows from Operating Activities	(In thousands)												(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil derivatives		($21,210	)		$409			($33,333	)		$3,441
NGL derivatives	(756		)	—			(1,188		)	—
Natural gas derivatives	488			(104		)	540			(1,253		)
Crude oil														($21,261	)		$6,500			($54,594	)		$9,941
NGL													(2,641		)	—			(3,829		)	—
Natural gas													245			522			785			(731		)
Deferred premium obligations	(2,605		)	(566		)	(4,467		)	(930		)	(2,605		)	(566		)	(7,072		)	(1,496		)
Cash Received (Paid) for Derivative Settlements, Net		($24,083	)		($261	)		($38,448	)		$1,258			($26,262	)		$6,456			($64,710	)		$7,714

11. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s ~~commodity~~ derivative instrument ~~and contingent consideration arrangement~~ assets and liabilities measured at fair value on a recurring basis as of ~~June~~September 30, 2018 and December 31, 2017:

~~June~~September 30, 2018

Level 1

Level 2

Level 3

(In thousands)

Assets

Commodity derivative instruments

$—

$~~1,163~~423

$—

Contingent Niobrara Consideration

—

~~9,970~~11,675

Contingent Marcellus Consideration

—

~~1,530~~1,315

Contingent Utica Consideration

—

~~10,545~~12,215

Liabilities

Commodity derivative instruments

$—

($~~131,398~~152,953

)

$—

Contingent ExL Consideration

—

(~~102,055~~112,045

)



	December 31, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$—			$—
Contingent Niobrara Consideration	—		—			—
Contingent Marcellus Consideration	—		—			2,205
Contingent Utica Consideration	—		—			7,985

Liabilities
Commodity derivative instruments		$—		($83,828	)		$—
Contingent ExL Consideration	—		—			(85,625		)

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

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

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

Contingent consideration arrangements. The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors, and risk adjusted discount rates, which include adjustments for the counterparties’ credit quality for contingent consideration assets and ~~volatility factors.~~the Company’s credit quality for the contingent consideration liabilities. As some of these assumptions are not observable throughout the full term of the contingent consideration arrangements, the contingent consideration arrangements were designated as Level 3 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

The following table presents the reconciliation of changes in the fair values of the contingent consideration arrangements, which were designated as Level 3 within the valuation hierarchy, for the ~~six~~nine months ended ~~June~~September 30, ~~2018:~~2018 and 2017:


	Contingent Consideration Arrangements					Contingent Consideration Arrangements
	Assets		Liability			Assets		Liability
For the Six Months Ended June 30, 2018	(In thousands)
Beginning of period		$10,190		($85,625	)
						(In thousands)
December 31, 2017							$10,190		($85,625	)
Recognition of divestiture date fair value	7,880		—			7,880		—
Gain (loss) on changes in fair value, net⁽¹⁾	3,975		(16,430		)	7,135		(26,420		)
Transfers into (out of) Level 3	—		—			—		—
End of period		$22,045		($102,055	)
September 30, 2018							$25,205		($112,045	)



	Contingent Consideration Arrangements
	Assets		Liability
	(In thousands)
December 31, 2016		$—		$—
Recognition of acquisition date fair value	—		(52,300		)
Loss on change in fair value⁽¹⁾	—		(8,000		)
Transfers into (out of) Level 3	—		—
September 30, 2017		$—		($60,300	)


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

See “Note 10. Derivative Instruments” for additional information regarding the contingent consideration arrangements.

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

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

Fair Value of Other Financial Instruments

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


	June 30, 2018				December 31, 2017				September 30, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)								(In thousands)
7.50% Senior Notes due 2020		$129,044		$130,325		$446,087		$459,518		$129,144		$130,000		$446,087		$459,518
6.25% Senior Notes due 2023	642,446		656,500		641,792		674,375		642,781		664,625		641,792		674,375
8.25% Senior Notes due 2025	245,817		266,250		245,605		274,375		245,927		268,750		245,605		274,375
Other long-term debt due 2028	—		—		4,425		4,445		—		—		4,425		4,445

12. Condensed Consolidating Financial Information

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

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)


	June 30, 2018													September 30, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated		Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,128,244			$120,425			$—		($3,116,164	)		$132,505		$3,114,698			$133,308			$—		($3,096,917	)		$151,089
Total property and equipment, net	6,445			2,562,799			3,028		(3,847		)	2,568,425		6,570			2,709,162			3,028		(3,833		)	2,714,927
Investment in subsidiaries	(743,363		)	—			—		743,363			—		(576,826		)	—			—		576,826			—
Other assets	8,630			12,279			—		—			20,909		29,611			15,371			—		—			44,982
Total Assets		$2,399,956			$2,695,503			$3,028		($2,376,648	)		$2,721,839		$2,574,053			$2,857,841			$3,028		($2,523,924	)		$2,910,998

Liabilities and Shareholders’ Equity
Current liabilities		$257,137			$3,362,551			$3,028		($3,119,185	)		$503,531		$305,096			$3,347,575			$3,028		($3,099,937	)		$555,762
Long-term liabilities	1,526,788			76,315			—		15,879			1,618,982		1,357,294			87,092			—		15,879			1,460,265
Preferred stock	172,858			—			—		—			172,858		173,629			—			—		—			173,629
Total shareholders’ equity	443,173			(743,363		)	—		726,658			426,468		738,034			(576,826		)	—		560,134			721,342
Total Liabilities and Shareholders’ Equity		$2,399,956			$2,695,503			$3,028		($2,376,648	)		$2,721,839		$2,574,053			$2,857,841			$3,028		($2,523,924	)		$2,910,998



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

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

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

(In thousands)

(Unaudited)


	Three Months Ended June 30, 2018														Three Months Ended September 30, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated			Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$19			$263,954			$—		$—			$263,973			$38			$303,337			$—		$—			$303,375
Total costs and expenses	106,335			121,869			—		(23		)	228,181			85,242			135,920			—		(13		)	221,149
Income (loss) before income taxes	(106,316		)	142,085			—		23			35,792			(85,204		)	167,417			—		13			82,226
Income tax expense	—			(483		)	—		—			(483		)	—			(880		)	—		—			(880		)
Equity in income of subsidiaries	141,602			—			—		(141,602		)	—			166,537			—			—		(166,537		)	—
Net income		$35,286			$141,602			$—		($141,579	)		$35,309			$81,333			$166,537			$—		($166,524	)		$81,346
Dividends on preferred stock	(4,474		)	—			—		—			(4,474		)	(4,457		)	—			—		—			(4,457		)
Accretion on preferred stock	(740		)	—			—		—			(740		)	(771		)	—			—		—			(771		)
Loss on redemption of preferred stock	—			—			—		—			—			—			—			—		—			—
Net income attributable to common shareholders		$30,072			$141,602			$—		($141,579	)		$30,095			$76,105			$166,537			$—		($166,524	)		$76,118


	Three Months Ended June 30, 2017												Three Months Ended September 30, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated		Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$174			$166,309		$—		$—			$166,483		$35			$181,244		$—		$—			$181,279
Total costs and expenses	7,731			102,415		—		31			110,177		54,061			119,366		—		29			173,456
Income (loss) before income taxes	(7,557		)	63,894		—		(31		)	56,306		(54,026		)	61,878		—		(29		)	7,823
Income tax expense	—			—		—		—			—		—			—		—		—			—
Equity in income of subsidiaries	63,894			—		—		(63,894		)	—		61,878			—		—		(61,878		)	—
Net income		$56,337			$63,894		$—		($63,925	)		$56,306		$7,852			$61,878		$—		($61,907	)		$7,823
Dividends on preferred stock	—			—		—		—			—		(2,249		)	—		—		—			(2,249		)
Accretion on preferred stock	—			—		—		—			—		—			—		—		—			—
Loss on redemption of preferred stock	—			—		—		—			—		—			—		—		—			—
Net income attributable to common shareholders		$56,337			$63,894		$—		($63,925	)		$56,306		$5,603			$61,878		$—		($61,907	)		$5,574

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

(In thousands)

(Unaudited)


	Six Months Ended June 30, 2018														Nine Months Ended September 30, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated			Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$39			$489,214			$—		$—			$489,253			$77			$792,551			$—		$—			$792,628
Total costs and expenses	193,700			231,982			—		(32		)	425,650			278,942			367,902			—		(45		)	646,799
Income (loss) before income taxes	(193,661		)	257,232			—		32			63,603			(278,865		)	424,649			—		45			145,829
Income tax expense	—			(802		)	—		—			(802		)	—			(1,682		)	—		—			(1,682		)
Equity in income of subsidiaries	256,430			—			—		(256,430		)	—			422,967			—			—		(422,967		)	—
Net income		$62,769			$256,430			$—		($256,398	)		$62,801			$144,102			$422,967			$—		($422,922	)		$144,147
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 attributable to common shareholders		$44,806			$256,430			$—		($256,398	)		$44,838			$120,911			$422,967			$—		($422,922	)		$120,956


	Six Months Ended June 30, 2017												Nine Months Ended September 30, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated		Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$256			$317,582		$—		$—			$317,838		$291			$498,826		$—		$—			$499,117
Total costs and expenses	26,599			194,871		—		41			221,511		80,660			314,237		—		70			394,967
Income (loss) before income taxes	(26,343		)	122,711		—		(41		)	96,327		(80,369		)	184,589		—		(70		)	104,150
Income tax expense	—			—		—		—			—		—			—		—		—			—
Equity in income of subsidiaries	122,711			—		—		(122,711		)	—		184,589			—		—		(184,589		)	—
Net income		$96,368			$122,711		$—		($122,752	)		$96,327		$104,220			$184,589		$—		($184,659	)		$104,150
Dividends on preferred stock	—			—		—		—			—		(2,249		)	—		—		—			(2,249		)
Accretion on preferred stock	—			—		—		—			—		—			—		—		—			—
Loss on redemption of preferred stock	—			—		—		—			—		—			—		—		—			—
Net income attributable to common shareholders		$96,368			$122,711		$—		($122,752	)		$96,327		$101,971			$184,589		$—		($184,659	)		$101,901

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30, 2018														Nine Months Ended September 30, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated			Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities		($158,309	)		$434,181			$—		$—			$275,872			($218,926	)		$684,218			$—		$—			$465,292
Net cash provided by (used in) investing activities	348,235			(84,355		)	—		(349,826		)	(85,946		)	375,265			(284,076		)	—		(400,142		)	(308,953		)
Net cash used in financing activities	(197,367		)	(349,826		)	—		349,826			(197,367		)	(163,464		)	(400,142		)	—		400,142			(163,464		)
Net decrease in cash and cash equivalents	(7,441		)	—			—		—			(7,441		)	(7,125		)	—			—		—			(7,125		)
Cash and cash equivalents, beginning of period	9,540			—			—		—			9,540			9,540			—			—		—			9,540
Cash and cash equivalents, end of period		$2,099			$—			$—		$—			$2,099			$2,415			$—			$—		$—			$2,415


	Six Months Ended June 30, 2017														Nine Months Ended September 30, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated			Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities		($77,501	)		$256,656			$—		$—			$179,155			($95,529	)		$376,126			$—		$—			$280,597
Net cash used in investing activities	(109,780		)	(364,887		)	—		108,231			(366,436		)	(728,833		)	(1,102,155		)	—		726,029			(1,104,959		)
Net cash provided by financing activities	185,315			108,231			—		(108,231		)	185,315			825,260			726,029			—		(726,029		)	825,260
Net decrease in cash and cash equivalents	(1,966		)	—			—		—			(1,966		)
Net increase in cash and cash equivalents															898			—			—		—			898
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194			4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$2,228			$—			$—		$—			$2,228			$5,092			$—			$—		$—			$5,092

13. Supplemental Cash Flow Information

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


	Six Months Ended June 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
	(In thousands)					(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$29,853			$39,603		$44,644			$59,389

Non-cash investing activities:
Increase in capital expenditure payables and accruals		$35,543			$48,395		$61,893			$98,829
Contingent consideration arrangement related to divestitures of oil and gas properties	(7,880		)	—
Fair value of contingent consideration (assets) liabilities on date of (divestiture) acquisition						(7,880		)	52,300
Stock-based compensation expense capitalized to oil and gas properties						5,384			2,543
Asset retirement obligations capitalized to oil and gas properties						1,127			2,761

14. Subsequent Events

~~Divestiture of Non-Operated Delaware Basin Assets~~Commodity Derivative Instruments

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

~~Hedging~~

~~In August~~October 2018, the Company entered into the following ~~crude oil~~commodity derivative ~~positions~~instruments at ~~the~~ weighted average contract ~~prices summarized below:~~volumes and prices:

Period Type of Contract Index
Volumes
(Bbls/d)

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

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



Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	2019	Three-Way Collars	NYMEX WTI	6,000	—			$45.00		$55.00		$93.01	—
Crude oil	2019	Basis Swaps	LLS-WTI Cushing	1,000		$5.78	—		—		—		—

Redemption of 7.50% Senior Notes Due 2020


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

On October 18, 2018, the Company delivered a notice of conditional redemption to the trustee for its 7.50% Senior Notes to call for redemption on November 19, 2018, the remaining $130.0 million outstanding aggregate principal amount of 7.50% Senior Notes at a redemption price of 100% of par, plus accrued and unpaid interest. The Company’s redemption obligation was conditioned on and subject to there being made available to the Company under its revolving credit facility a commitment amount of at least $1.1 billion as of November 19, 2018, which was satisfied on October 29, 2018 in connection with the amendment to the credit agreement discussed below, therefore, the Company’s redemption obligation is no longer conditional. As a result of the redemption, the Company expects to record a loss on extinguishment of debt of approximately $0.8 million, which is solely attributable to the write-off of unamortized premium and debt issuance costs.

Upon redemption of the 7.50% Senior Notes, the May 4, 2022 maturity date of the credit agreement will no longer be subject to a springing maturity date of June 15, 2020.

Thirteenth Amendment to the Credit Agreement

On October 29, 2018, the Company entered into the thirteenth amendment to its credit agreement governing its revolving credit facility to, among other things, (i) establish the borrowing base at $1.3 billion, with an elected commitment amount of $1.1 billion, until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from 1.50%-2.50% to 1.25%-2.25% and base rate loans from 0.50%-1.50% to 0.25%-1.25%, each depending on the level of facility usage and each subject to an increase of 0.25% for any period during which the ratio of Total Debt to EBITDA exceeds 3.00 to 1.00, (iii) amend the definition of Capital Leases, and (iv) amend certain other definitions and provisions.

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

The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our 2017 Annual Report. The following discussion and analysis contains statements, including, but not limited to, statements related to our plans, strategies, objectives, and expectations. Please see “Forward-Looking Statements” for further details about these statements.

General Overview

~~Second~~Third Quarter 2018 Highlights

Total production for the three months ended ~~June~~September 30,2018 was ~~57,077~~64,627 Boe/d, an increase of ~~12%~~17% from the three months ended ~~June~~September 30, 2017, primarily due to ~~the addition of~~ production from ~~the ExL Acquisition~~new wells in the ~~third quarter of 2017,~~Eagle Ford and Delaware Basin, partially offset by the divestitures in ~~the~~ Utica and Marcellus ~~Shales~~ in the fourth quarter of 2017 and ~~the~~ Niobrara ~~Formation~~ and Eagle Ford in the first quarter of 2018, ~~and~~as well as normal production declines.

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


	Three Months Ended June 30, 2018				June 30, 2018				Three Months Ended September 30, 2018				September 30, 2018
	Drilled		Completed		Drilled But Uncompleted		Producing		Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	19	17.7	18	15.6	15	14.0	485	434.9	32	31.3	25	24.3	20	19.4	516	463.1
Delaware Basin	9	7.8	12	9.3	10	8.6	46	37.6	7	5.3	10	8.7	7	5.6	57	47.2
Total	28	25.5	30	24.9	25	22.6	531	472.5	39	36.6	35	33.0	27	25.0	573	510.3

Drilling and completion expenditures for the ~~second~~third quarter of 2018 were ~~$218.0~~$241.1 million, of which ~~nearly 55% was~~approximately 62% were in the ~~Delaware Basin~~Eagle Ford with the balance in the Delaware Basin. As a result of the relative outlook for crude oil prices in the Eagle ~~Ford. We currently expect~~Ford and Delaware Basin, we elected to ~~operate an average~~shift capital expenditures to the Eagle Ford in order to take advantage of the superior returns in the current environment. As of September 30, 2018, we were operating six rigs, with four located in the Eagle Ford and two located in the Delaware Basin, and ~~2-3~~two completion crews, ~~for~~both of which were in the Eagle Ford. For the remainder of ~~2018. Given the faster cycle times in~~2018, we currently expect to continue operating an average of six rigs between the Eagle Ford and Delaware Basin, however, completion activity is expected to decline in the fourth quarter of 2018 as ~~well as the Company’s decision to maintain~~we have planned for a ~~six rig program for the remainder of the year, our~~frac holiday. Our current 2018 drilling, completion, and infrastructure capital expenditure plan ~~has been increased from $750.0 million to $800.0 million to~~remains unchanged at $800.0 million to $825.0 million. See “—Liquidity and Capital Resources—2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy” for additional details.

In July 2018, we closed on the divestiture of certain non-operated assets in the Delaware Basin for aggregate net proceeds of $30.9 million.

In August 2018, we entered into a purchase and sale agreement with Devon to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas for an agreed upon price of $215.0 million, subject to customary purchase price adjustments. We paid $21.5 million as a deposit upon signing the purchase and sale agreement and $183.4 million upon closing in October for an aggregate purchase price of $204.9 million. The final purchase price remains subject to post-closing adjustments. Certain of the acreage included in the acquisition is subject to a third party’s right to purchase a 20% interest in such acreage.

In August 2018, we completed a public offering of 9.5 million shares of our common stock at a price per share of $22.55. We used the net proceeds of $213.9 million, net of offering costs, to fund the purchase price of the Devon Acquisition and for general corporate purposes. Pending the closing of the Devon Acquisition, we used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility.

We recorded net income attributable to common shareholders for the three months ended September 30, 2018 of $76.1 million, or $0.85 per diluted share, as compared to net income attributable to common shareholders for the three months ended September 30, 2017 of $5.6 million, or $0.07 per diluted share. The increase in net income attributable to common shareholders for the third quarter of 2018 as compared to the net income attributable to common shareholders for the third quarter of 2017 was driven primarily by higher production volumes and commodity prices in the third quarter of 2018 compared to the third quarter of 2017, partially offset by a loss on derivatives, net of $55.4 million in the third quarter of 2018 as compared to a loss on derivatives, net of $24.4 million in the third quarter of 2017 and an increase in

our depreciation, depletion and amortization (“DD&A”) expense of $12.5 million to $80.1 million for the third quarter of 2018 as compared to $67.6 million for the third quarter of 2017. See “—Results of Operations” below for further details.

Recent Developments

In October 2018, we delivered a notice of conditional redemption to the trustee for our 7.50% Senior Notes to call for redemption on November 19, 2018, the remaining $130.0 million aggregate principal amount of outstanding 7.50% Senior Notes at a redemption price of 100% of par, plus accrued and unpaid interest. Our redemption obligation was conditioned on and subject to there being made available to us under the revolving credit facility a commitment amount of at least $1.1 billion as of November 19, 2018, which was satisfied on October 29, 2018 in connection with the amendment to the credit agreement discussed below, therefore, our redemption obligation is no longer conditional. As a result of the redemption, we expect to record a loss on extinguishment of debt of approximately $0.8 million, which is solely attributable to the write-off of unamortized premium and debt issuance costs. Additionally, upon redemption of the 7.50% Senior Notes, the May 4, 2022 maturity date of the credit agreement will no longer be subject to a springing maturity date of June 15, 2020.

In October 2018, we entered into the ~~twelfth~~thirteenth amendment to our credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at ~~$1.0~~$1.3 billion, with an elected commitment amount of ~~$900.0 million,~~$1.1 billion, until the next redetermination thereof, (ii) reduce the applicable margins ~~applied to~~for Eurodollar loans from ~~2.0%-3.0%~~1.50%-2.50% to ~~1.5%-2.5%~~1.25%-2.25% and base rate loans from 0.50%-1.50% to 0.25%-1.25%, each depending on the level of facility usage and each subject to an increase of 0.25% for any period during which the ratio of Total Debt to EBITDA exceeds 3.00 to 1.00, (iii) amend the ~~covenant limiting payment~~definition of ~~dividends and distributions on equity to increase our ability to make dividends and distributions on our equity interests~~Capital Leases, and (iv) amend certain other ~~provisions, in each case as set forth therein.~~

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

~~Recent Developments~~

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

Results of Operations

Three Months Ended ~~June~~September 30, 2018, Compared to the Three Months Ended ~~June~~September 30, 2017

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


	Three Months Ended June 30,				2018 Period Compared to 2017 Period					Three Months Ended September 30,				2018 Period Compared to 2017 Period
	2018		2017		Increase (Decrease)			% Increase (Decrease)		2018		2017		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,445		3,060		385			13	%	3,755		3,211		544			17	%
NGLs (MBbls)	853		453		400			88	%	1,055		623		432			69	%
Natural gas (MMcf)	5,372		6,775		(1,403		)	(21	%)	6,815		7,476		(661		)	(9	%)
Total barrels of oil equivalent (MBoe)	5,193		4,643		550			12	%	5,946		5,080		866			17	%

Daily production volumes by product -
Crude oil (Bbls/d)	37,860		33,629		4,231			13	%	40,813		34,903		5,910			17	%
NGLs (Bbls/d)	9,379		4,982		4,397			88	%	11,469		6,777		4,692			69	%
Natural gas (Mcf/d)	59,029		74,451		(15,422		)	(21	%)	74,072		81,265		(7,193		)	(9	%)
Total barrels of oil equivalent (Boe/d)	57,077		51,019		6,058			12	%	64,627		55,224		9,403			17	%

Daily production volumes by region (Boe/d) -
Eagle Ford	37,039		38,055		(1,016		)	(3	%)	39,024		39,002		22			—	%
Delaware Basin	19,783		2,151		17,632			820	%	25,577		6,994		18,583			266	%
Other	255		10,813		(10,558		)	(98	%)	26		9,228		(9,202		)	(100	%)
Total barrels of oil equivalent (Boe/d)	57,077		51,019		6,058			12	%	64,627		55,224		9,403			17	%

Average realized prices -
Crude oil ($ per Bbl)		$66.70		$46.67		$20.03		43	%		$67.78		$47.37		$20.41		43	%
NGLs ($ per Bbl)	24.93		17.19		7.74			45	%	32.04		20.01		12.03			60	%
Natural gas ($ per Mcf)	2.40		2.35		0.05			2	%	2.21		2.24		(0.03		)	(1	%)
Total average realized price ($ per Boe)		$50.83		$35.86		$14.97		42	%		$51.02		$35.68		$15.34		43	%

Revenues (In thousands) -
Crude oil		$229,798		$142,806		$86,992		61	%		$254,525		$152,101		$102,424		67	%
NGLs	21,269		7,786		13,483			173	%	33,798		12,467		21,331			171	%
Natural gas	12,906		15,891		(2,985		)	(19	%)	15,052		16,711		(1,659		)	(10	%)
Total revenues		$263,973		$166,483		$97,490		59	%		$303,375		$181,279		$122,096		67	%

Production volumes for the three months ended ~~June~~September 30, 2018 were ~~57,077~~64,627 Boe/d, an increase of ~~12%~~17% from ~~51,019~~55,224 Boe/d for the same period in 2017. The increase is primarily due to production from new wells in the ~~Eagle Ford and the addition of production~~Delaware Basin, primarily drilled on properties from the ExL Acquisition, as well as in ~~the third quarter of 2017,~~Eagle Ford, partially offset by the divestitures in ~~the~~ Utica and Marcellus ~~Shales~~ in the fourth quarter of 2017 and ~~the~~ Niobrara ~~Formation~~ and Eagle Ford in the first quarter of ~~2018 and normal production declines.~~2018. Revenues for the three months ended ~~June~~September 30, 2018 increased ~~59%~~67% to ~~$264.0~~$303.4 million compared to ~~$166.5~~$181.3 million for the same period in 2017 primarily due to higher crude oil prices and ~~increased~~higher crude oil ~~and NGL production, primarily as a result of the ExL Acquisition.~~production.

Lease operating expenses for the three months ended ~~June~~September 30, 2018 ~~decreased~~increased to ~~$35.2~~$41.0 million ($~~6.77~~6.90 per Boe) from ~~$36.0~~$34.9 million ($~~7.76~~6.86 per Boe) for the same period in 2017. The ~~decrease~~increase in lease operating expenses is primarily due to ~~a reduction in workover~~ costs ~~for the three months ended June 30, 2018 when compared to the same period in 2017.~~associated with increased production. The ~~decrease~~increase in lease operating expense per Boe is primarily due to the addition of production from the ExL Acquisition beginning in the third quarter of 2017, which has a lower operating cost per Boe than our other crude oil properties, partially offset by an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties, as a result of the divestiture in the Marcellus Shale in the fourth quarter of 2017, as well as processing fees for certain of our natural gas and NGL processing contracts that, effective January 1, 2018, are ~~now~~ presented in lease operating expenses as a result of the adoption of ASC in 606. This more than offset a net decrease in lease operating expense per Boe related to the change in the proportion of production from properties acquired in the ExL Acquisition, which have lower operating costs per Boe than our other Delaware Basin and Eagle Ford properties, and the increased proportion of total production from crude oil properties, as a result of the divestiture in Marcellus in the fourth quarter of 2017, which have a higher per operating cost per Boe than natural gas properties.

Production taxes increased to ~~$12.5~~$14.5 million ~~(or 4.7%~~(4.8% of revenues) for the three months ended ~~June~~September 30, 2018 from ~~$7.1~~$7.7 million ~~(or 4.3%~~(4.3% of revenues) for the same period in 2017 primarily as a result of the increase in crude oil and NGL revenues. The increase in production taxes as a percentage of revenues is primarily due to the divestiture of substantially all of our assets in ~~the~~ Marcellus ~~Shale~~ in the fourth quarter of 2017, as our production in Marcellus was not subject to production taxes.

Ad valorem taxes increased to ~~$3.6~~$2.6 million (0.9% of revenues) for the three months ended ~~June~~September 30, 2018 from ~~$1.1~~$1.7 million (1.0% of revenues) for the same period in 2017. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and ~~new wells drilled or acquired in the~~ Delaware Basin ~~as well as an increase in our annual estimate of ad valorem taxes for 2018 due to~~and higher ~~expected~~ property tax valuations as a result of the increase in crude oil ~~prices.~~prices, partially offset by a reduction in ad valorem taxes resulting from the divestitures discussed above. The decrease in ad valorem taxes as a percentage of revenues is primarily due to the timing of when wells are included in the ad valorem tax assessment as wells drilled and producing during 2018 would not be included in ad valorem tax assessment until 2019.

DD&A expense for the ~~second~~third quarter of 2018 increased ~~$13.4~~$12.5 million to ~~$72.4~~$80.1 million ($~~13.95~~13.47 per Boe) from the DD&A expense for the ~~second~~third quarter of 2017 of ~~$59.1~~$67.6 million ($~~12.72~~13.30 per Boe). The increase in DD&A expense is attributable to increased production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is due primarily to increases in future development ~~cost assumptions~~costs that occurred subsequent to the ~~second~~third quarter of 2017 as well as an increase toin proved oil and gas properties ~~related to the ExL Acquisition in the third quarter~~as a result of ~~2017,~~our ongoing capital expenditure program, partially offset by the reduction in proved oil and gas properties as a result of the divestitures in ~~the~~ Utica and Marcellus ~~Shales~~ in the fourth quarter of 2017 and ~~the~~ Niobrara ~~Formation~~ and Eagle Ford in the first quarter of ~~2018.~~2018 and an increase in proved oil and gas reserves. The components of our DD&A expense were as follows:


	Three Months Ended June 30,				Three Months Ended September 30,
	2018		2017		2018		2017
	(In thousands)				(In thousands)
DD&A of proved oil and gas properties		$71,346		$57,695		$79,051		$66,221
Depreciation of other property and equipment	613		612		607		584
Amortization of other assets	140		321		102		294
Accretion of asset retirement obligations	331		444		348		465
Total DD&A		$72,430		$59,072		$80,108		$67,564

General and administrative expense, net ~~increased~~decreased to ~~$18.3~~$12.8 million for the three months ended ~~June~~September 30, 2018 from ~~$11.6~~$16.0 million for the corresponding period in 2017. The ~~increase~~decrease was primarily due to ~~an increase in~~ stock-based compensation expense, net as a result of ~~an increase~~a larger decrease in the fair value of stock appreciation rights for the three months ended ~~June~~September 30, 2018 as compared to ~~a decrease in fair value for~~ the same period in 2017.

We recorded a loss on derivatives, net of ~~$67.7~~$55.4 million and ~~a gain on derivatives, net of $26.1~~$24.4 million for the three months ended ~~June~~September 30, 2018 and 2017, respectively. The components of our ~~(gain)~~ loss on derivatives, net were as follows:


	Three Months Ended June 30,						Three Months Ended September 30,
	2018			2017			2018			2017
	(In thousands)						(In thousands)
Crude oil derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period		$59,602			($10,122	)
Gain due to new derivative positions executed during the period	(6,165		)	(19,614		)
Loss due to upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period								$34,282			$7,567
Loss due to new derivative positions executed during the period							9,382			842
Loss due to deferred premium obligations incurred	—			7,554			—			10,151
NGL derivative positions:
Loss due to upward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period	6,564			—			5,086			—
Natural gas derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period	153			(3,883		)
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period							(192		)	(2,183		)
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period	7,560			—			6,830			8,000
(Gain) loss on derivatives, net		$67,714			($26,065	)
Loss on derivatives, net								$55,388			$24,377

Interest expense, net for the three months ended ~~June~~September 30, 2018 was ~~$15.6~~$15.4 million as compared to ~~$21.1~~$20.7 million for the same period in 2017. The decrease was primarily due ~~primarily~~ to an increase in capitalized interest as a result of higher average balances of unevaluated leasehold and seismic costs for the three months ended June 30, 2018 as compared to the three months ended June 30, 2017, primarily as a result of the ExL Acquisition in the third quarter of 2017, as well as reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the fourth quarter of 2017 and first quarter of ~~2018.~~2018, The decrease was partially offset by ~~interest expense on $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in the third quarter of 2017~~increased borrowings and ~~an increase in~~associated interest expense on our revolving credit facility ~~as a result of increased borrowings~~ for the three months ended ~~June~~September 30, 2018 as compared to the three months ended ~~June~~September 30, 2017. The components of our interest expense, net were as follows:


	Three Months Ended June 30,						Three Months Ended September 30,
	2018			2017			2018			2017
	(In thousands)						(In thousands)
Interest expense on Senior Notes		$17,767			$21,455			$17,750			$25,750
Interest expense on revolving credit facility	5,490			2,261			5,092			1,969
Amortization of premiums and debt issuance costs	937			1,079			956			1,116
Other interest expense	133			298			124			293
Interest capitalized	(8,728		)	(3,987		)	(8,516		)	(8,455		)
Interest expense, net		$15,599			$21,106			$15,406			$20,673

The effective income tax rates for the ~~second~~third quarter of 2018 and 2017 were ~~1.3%~~1.1% and 0.0%, respectively. The variance in the effective income tax rate results from current state and deferred income tax expense of $0.5 million recognized during the second quarter of 2018. The tax expense was driven by changes to our state apportionment for estimated state deferred tax liabilitiesrespectively, which were nominal as a result of the significant changes in our areas of operation that occurred in late 2017 and early 2018, whereby all remaining operations are located in Texas. The effective income tax rate was 0.0% during the second quarter of 2017 as a result ofmaintaining a full valuation allowance against our net deferred tax assets. The increase in the effective rate between the periods is due to $0.9 million of Texas franchise tax recognized for the three months ended September 30, 2018 due to an increase in the apportionment of income to the state of Texas as a result of our divestitures in the fourth quarter of 2017 and first quarter of 2018.

Throughout 2017 and the first nine months of 2018, we maintained a full valuation allowance against our deferred tax assets ~~driven by~~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 September 30, 2018, primarily due to impairments of proved oil and gas properties recognized in the ~~third~~fourth quarter of 2015 and ~~continuing through~~ the ~~third quarter~~first three quarters of ~~2016.~~2016, which limits our ability to consider subjective positive evidence, such as its projections of future taxable income.

We currently believes it is reasonably possible for us to achieve a three-year cumulative level of profitability within the next 12 months, and considering the rebound in crude oil prices during 2018 and improved outlook for 2019, would enhance our ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of a portion or substantially all of the valuation allowance. A release of the valuation allowance would result in the recognition of an increase in deferred tax assets and an income tax benefit in the period in which the release occurs, although the exact timing and amount of the release is subject to change based on numerous factors, including our projections of future taxable income, which we continue to assess based on available information each reporting period.

For the three months ended ~~June~~September 30, 2018 and 2017, we declared and paid cash dividends of $4.5 million ~~of cash dividends~~and $2.2 million, respectively, on our Preferred ~~Stock, which reduced net income to compute net income attributable to common shareholders.~~Stock.

Results of Operations

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

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


	Six Months Ended June 30,				2018 Period Compared to 2017 Period					Nine Months Ended September 30,				2018 Period Compared to 2017 Period
	2018		2017		Increase (Decrease)			% Increase (Decrease)		2018		2017		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	6,517		5,656		861			15	%	10,272		8,867		1,405			16	%
NGLs (MBbls)	1,593		859		734			85	%	2,648		1,482		1,166			79	%
Natural gas (MMcf)	10,182		13,803		(3,621		)	(26	%)	16,996		21,279		(4,283		)	(20	%)
Total barrels of oil equivalent (MBoe)	9,807		8,816		991			11	%	15,753		13,896		1,857			13	%

Daily production volumes by product -
Crude oil (Bbls/d)	36,008		31,250		4,758			15	%	37,628		32,481		5,147			16	%
NGLs (Bbls/d)	8,800		4,746		4,054			85	%	9,699		5,430		4,269			79	%
Natural gas (Mcf/d)	56,252		76,260		(20,008		)	(26	%)	62,258		77,946		(15,688		)	(20	%)
Total barrels of oil equivalent (Boe/d)	54,183		48,706		5,477			11	%	57,703		50,902		6,801			13	%

Daily production volumes by region (Boe/d) -
Eagle Ford	36,335		35,332		1,003			3	%	37,241		36,569		672			2	%
Delaware Basin	17,522		2,284		15,238			667	%	20,236		3,871		16,365			423	%
Other	326		11,090		(10,764		)	(97	%)	226		10,462		(10,236		)	(98	%)
Total barrels of oil equivalent (Boe/d)	54,183		48,706		5,477			11	%	57,703		50,902		6,801			13	%

Average realized prices -
Crude oil ($ per Bbl)		$65.17		$47.90		$17.27		36	%		$66.13		$47.70		$18.43		39	%
NGLs ($ per Bbl)	23.96		17.71		6.25			35	%	27.18		18.68		8.50			46	%
Natural gas ($ per Mcf)	2.59		2.30		0.29			13	%	2.44		2.28		0.16			7	%
Total average realized price ($ per Boe)		$49.89		$36.05		$13.84		38	%		$50.32		$35.92		$14.40		40	%

Revenues (In thousands) -
Crude oil		$424,717		$270,898		$153,819		57	%		$679,242		$422,999		$256,243		61	%
NGLs	38,171		15,211		22,960			151	%	71,969		27,678		44,291			160	%
Natural gas	26,365		31,729		(5,364		)	(17	%)	41,417		48,440		(7,023		)	(14	%)
Total revenues		$489,253		$317,838		$171,415		54	%		$792,628		$499,117		$293,511		59	%

Production volumes for the ~~six~~nine months ended ~~June~~September 30, 2018 were ~~54,183~~57,703 Boe/d, an increase of ~~11%~~13% from ~~48,706~~50,902 Boe/d for the same period in 2017. The increase is primarily due to production from new wells in the ~~Eagle Ford and the addition of production~~Delaware Basin, primarily drilled on properties from the ExL Acquisition, as well as in ~~the third quarter of 2017,~~Eagle Ford, partially offset by the divestitures in ~~the~~ Utica and Marcellus ~~Shales~~ in the fourth quarter of 2017 and ~~the~~ Niobrara ~~Formation~~ and Eagle Ford in the first quarter of ~~2018 and normal production declines.~~2018. Revenues for the ~~six~~nine months ended ~~June~~September 30, 2018 increased ~~54%~~59% to ~~$489.3~~$792.6 million from ~~$317.8~~$499.1 million for the same period in 2017 primarily due to higher crude oil prices and ~~increased~~higher crude oil ~~and NGL production, primarily as a result of the ExL Acquisition.~~production.

Lease operating expenses for the ~~six~~nine months ended ~~June~~September 30, 2018 increased to ~~$74.4~~$115.4 million ($~~7.59~~7.33 per Boe) from ~~$65.9~~$100.8 million ($~~7.47~~7.25 per Boe) for the same period in 2017. The increase in lease operating expenses is primarily due to costs associated with new wells completed in the Eagle Ford and Delaware Basin since the second quarter of 2017, partially offset by the divestitures in the Utica and Marcellus Shales in the fourth quarter of 2017 and the Niobrara Formation and Eagle Ford in the first quarter of 2018.increased production. The increase in lease operating expense per Boe is primarily due to anprocessing fees for certain of our natural gas and NGL processing contracts that, effective January 1, 2018, are presented in lease operating expenses as a result of the adoption of ASC in 606. Additionally, there was a net increase in lease operating expense per Boe related to the increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties, as a result of the divestiture in ~~the~~ Marcellus ~~Shale~~ in the fourth quarter of 2017 ~~as well as processing fees for certain~~and the increased proportion of production from properties acquired in the ExL Acquisition, which have lower operating costs per Boe than our ~~natural gas~~other Delaware Basin and ~~NGL processing contracts that are now presented in lease operating expenses as a result of the adoption of ASC 606.~~

Eagle Ford properties.

Production taxes increased to ~~$23.1~~$37.6 million (or 4.7% of revenues) for the ~~six~~nine months ended ~~June~~September 30, 2018 from ~~$13.4~~$21.1 million (or 4.2% of revenues) for the same period in 2017 primarily as a result of the increase in crude oil and NGL revenues. The

increase in production taxes as a percentage of revenues is ~~primarily~~ due to the divestiture of substantially all of our assets in ~~the~~ Marcellus ~~Shale~~ in the fourth quarter of 2017, as our production in Marcellus was not subject to production taxes.

Ad valorem taxes increased to ~~$5.6~~$8.2 million (1.0% of revenues) for the ~~six~~nine months ended ~~June~~September 30, 2018 from ~~$4.0~~$5.8 million (1.2% of revenues) for the same period in 2017. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and new wells drilled or acquired in the Delaware Basin ~~as well as an increase in our annual estimate of ad valorem taxes for 2018 due to~~and higher ~~expected~~ property tax valuations as a result of the increase in crude oil ~~prices.~~prices, partially offset by a reduction in ad valorem taxes resulting from the divestitures discussed above. The decrease in ad valorem taxes as a percentage of revenues is primarily due to the timing of when wells are included in the ad valorem tax assessment as wells drilled and producing during 2018 would not be included in ad valorem tax assessment until 2019.

DD&A expense for the ~~six~~nine months ended ~~June~~September 30, 2018 increased ~~$23.4~~$36.0 million to ~~$136.9~~$217.0 million ($~~13.96~~13.78 per Boe) from ~~$113.5~~$181.0 million ($~~12.87~~13.03 per Boe) for the same period in 2017. The increase in DD&A expense is attributable to increased production as well as an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is due primarily to increases in future development ~~cost assumptions~~costs that occurred subsequent to the ~~second~~third quarter of 2017 as well as an increase to proved oil and gas properties ~~related to the ExL Acquisition in the third quarter~~as a result of ~~2017,~~our ongoing capital expenditure program, partially offset by the reduction in proved oil and gas properties as a result of the divestitures in ~~the~~ Utica and Marcellus ~~Shales~~ in the fourth quarter of 2017 and ~~the~~ Niobrara ~~Formation~~ and Eagle Ford in the first quarter of ~~2018.~~2018 and an increase in proved oil and gas reserves. The components of our DD&A expense were as follows:


	Six Months Ended June 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(In thousands)				(In thousands)
DD&A of proved oil and gas properties		$134,676		$110,655		$213,727		$176,876
Depreciation of other property and equipment	1,194		1,258		1,801		1,842
Amortization of other assets	374		672		476		966
Accretion of asset retirement obligations	653		869		1,001		1,334
Total DD&A		$136,897		$113,454		$217,005		$181,018

General and administrative expense, net increased to ~~$45.6~~$58.4 million for the ~~six~~nine months ended ~~June~~September 30, 2018 from ~~$33.3~~$49.3 million for the same period in 2017. The increase was primarily due to an increase in stock-based compensation expense, net as a result of an increase in the fair value of stock appreciation rights for the ~~six~~nine months ended ~~June~~September 30, 2018 compared to a decrease in fair value for the ~~six~~nine months ended ~~June~~September 30, 2017 as well as an increase in personnel costs and higher annual bonuses awarded in the first quarter of 2018 compared to the first quarter of 2017.

We recorded a loss on derivatives, net of ~~$97.3~~$152.7 million and a gain on derivatives, net of ~~$51.4~~$27.0 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively. The components of our (gain) loss on derivatives, net were as follows:


	Six Months Ended June 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In thousands)						(In thousands)
Crude oil derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period		$89,802			($28,549	)		$113,282			($28,334	)
Gain due to new derivative positions executed during the period	(6,854		)	(19,614		)
(Gain) loss due to new derivative positions executed during the period							13,330			(11,420		)
Loss due to deferred premium obligations incurred	—			7,501			—			17,652
NGL derivative positions:
Loss due to upward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period	4,799			—			9,885			—
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period	(2,641		)	(10,719		)	(3,152		)	(12,902		)
Gain due to new derivative positions executed during the period	(251		)	—
Loss due to new derivative positions executed during the period							68			—
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period	12,455			—			19,285			8,000
(Gain) loss on derivatives, net		$97,310			($51,381	)		$152,698			($27,004	)

Interest expense, net for the ~~six~~nine months ended ~~June~~September 30, 2018 was ~~$31.1~~$46.5 million as compared to ~~$41.7~~$62.4 million for the same period in 2017. The decrease was due primarily to ~~an increase in capitalized interest as a result of higher average balances of~~

unevaluated leasehold and seismic costs for the six months ended June 30, 2018 as compared to the six months ended June 30, 2017, primarily as a result of the ExL Acquisition in the third quarter of 2017, as well as reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the fourth quarter of 2017 and first quarter of ~~2018.~~2018 as well as an increase in capitalized interest as a result of higher

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


	Six Months Ended June 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In thousands)						(In thousands)
Interest expense on Senior Notes		$39,253			$42,910			$57,003			$68,660
Interest expense on revolving credit facility	8,649			3,687			13,741			5,656
Amortization of debt issuance costs, premiums, and discounts	2,040			2,265			2,996			3,381
Other interest expense	270			583			394			876
Capitalized interest	(19,096		)	(7,768		)	(27,612		)	(16,223		)
Interest expense, net		$31,116			$41,677			$46,522			$62,350

As a result of our redemption of $320.0 million aggregate principal amount of our 7.50% Senior Notes, we recorded a loss on extinguishment of debt of $8.7 million for the ~~six~~nine months ended ~~June~~September 30, 2018, which included redemption premiums of $6.0 million paid to redeem the notes and non-cash charges of $2.7 million attributable to the write-off of unamortized premium and debt issuance costs.

The effective income tax rate for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 was ~~1.3%~~1.2% and 0.0% respectively. The variance in the effective income tax rate results from current state and deferred income tax expense of $0.8 million recognized during the six months ended June 30, 2018. This was due to changes to our state apportionment for estimated state deferred tax liabilities, respectively, which were nominal as a result of the significant changes in our areas of operation that occurred in late 2017 and early 2018 as well as current period activity. The effective income tax rate was 0.0% during the six months ended June 30, 2017 as a result ofmaintaining a full valuation allowance against our net deferred tax assets. The increase in the effective rate between the periods is due to $1.7 million of Texas franchise tax recognized for the nine months ended September 30, 2018 due to an increase in the apportionment of income to the state of Texas as a result of our divestitures in the fourth quarter of 2017 and first quarter of 2018.

We currently believe it is reasonably possible for us to achieve a three-year cumulative level of profitability within the next 12 months, and considering the rebound in crude oil prices during 2018 and improved outlook for 2019, would enhance our ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of a portion or substantially all of the valuation allowance. A release of the valuation allowance would result in the recognition of an increase in deferred tax assets and an income tax benefit in the period in which the release occurs, although the exact timing and amount of the release is subject to change based on numerous factors, including our projections of future taxable income, which we continue to assess based on available information each reporting period.

For the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, we declared and paid ~~$9.3~~cash dividends of $13.8 million ~~of cash dividends~~and $2.2 million, respectively, on our Preferred ~~Stock, which reduced net income to compute net income attributable to common shareholders.~~Stock.

~~As a result~~During the first quarter of ~~our redemption of~~2018, we redeemed 50,000 shares of Preferred Stock, ~~at $1,000.00 per share, or~~representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million ~~we recorded a loss on~~ redemption ~~of preferred stock of $7.1~~price and $0.5 million for the six months ended June 30, 2018, which reduced net income to compute net income attributable to common shareholders. The loss on redemption of preferred stock included $0.1 million of direct costs incurred as a result of the redemption and a non-cash charge of $7.0 million attributable to the difference between $50.0 million, which was the consideration transferred to the holders of the Preferred Stock excluding accrued and unpaid ~~dividends, and~~dividends. We recognized a $7.1 million loss on the redemption due to the excess of the $50.0 million redemption price over the $42.9 million ~~which was 20% of the~~redemption date carrying value of the Preferred ~~Stock on the date of redemption.~~Stock.

Liquidity and Capital Resources

2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy. Our 2018 drilling, completion, and infrastructure capital expenditure plan ~~has been increased from $750.0 million to $800.0 million to~~remains unchanged at $800.0 million to $825.0 million. We currently intend to finance the remainder of our 2018 drilling, completion, and infrastructure capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather

delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. The following is a summary of our capital expenditures for the three and ~~six~~nine months ended ~~June~~September 30, 2018:


	Three Months Ended				Six Months Ended		Three Months Ended						Nine Months Ended
	March 31, 2018		June 30, 2018		June 30, 2018		March 31, 2018		June 30, 2018		September 30, 2018		September 30, 2018
	(In thousands)						(In thousands)
Drilling, completion, and infrastructure
Eagle Ford		$135,677		$101,249		$236,926		$135,677		$101,249		$149,386		$386,312
Delaware Basin	73,892		116,743		190,635		73,892		116,743		91,761		282,396
All other regions	284		—		284		284		—		—		284
Total drilling, completion, and infrastructure	209,853		217,992		427,845		209,853		217,992		241,147		668,992
Leasehold and seismic	5,520		6,129		11,649		5,520		6,129		6,668		18,317
Total Capital Expenditures ⁽¹⁾		$215,373		$224,121		$439,494
Total capital expenditures ⁽¹⁾								$215,373		$224,121		$247,815		$687,309


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

Sources and Uses of Cash. Our primary use of cash is related to our drilling, completion and infrastructure capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the ~~six~~nine months ended ~~June~~September 30, 2018, 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 ~~August 1,~~November 2, 2018, our revolving credit facility had a borrowing base of ~~$1.0~~$1.3 billion, with an elected commitment amount of ~~$900.0 million,~~$1.1 billion, with ~~$513.4~~$618.0 million of borrowings outstanding. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility. See “Note ~~6. Long-Term Debt”~~14. Subsequent Events” for ~~further~~ details of the recent ~~twelfth~~thirteenth amendment.

Securities offerings. As situations or conditions arise, we may choose to issue debt, equity or other securities to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all. See “Note 9. Shareholders’ Equity and Stock-Based Compensation” for details regarding the recent common stock offering.

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

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

Overview of Cash Flow Activities. Net cash provided by operating activities was ~~$275.9~~$465.3 million and ~~$179.2~~$280.6 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively. The ~~change~~increase was driven primarily by an increase in revenues as a result of higher ~~production~~crude oil prices and ~~commodity prices,~~higher crude oil production, partially offset by an increase in the net cash paid for derivative settlements and an increase in operating expenses and cash general and administrative ~~expense and an increase in working capital requirements.~~expense.

Net cash used in investing activities ~~was $85.9~~decreased to $309.0 million for the ~~six~~nine months ended ~~June~~September 30, 2018, ~~and $366.4~~from $1,105.0 million for the ~~six months ended June 30,~~corresponding period in 2017. ~~The change~~This was due primarily to ~~cash received from the divestitures in the Niobrara Formation and Eagle Ford in early 2018, as well as~~ a decrease in cash payments for acquisitions of oil and gas properties, as well as cash received from the divestitures in Niobrara and Eagle Ford in early 2018, partially offset by an increase in capital expenditures as a result of our ongoing drilling, completion, and infrastructure activity in Eagle Ford and the Delaware Basin.

Net cash used in financing activities was ~~$197.4~~$163.5 million for the ~~six~~nine months ended ~~June~~September 30, 2018 ~~and~~compared to net cash provided by financing activities for the ~~six~~nine months ended ~~June~~September 30, 2017 ~~was $185.3~~of $825.3 million. The ~~increase in net cash used in financing activities~~change was primarily due to payments for the redemptions of ~~the~~our 7.50% Senior Notes and ~~the~~ Preferred Stock, ~~as well as~~decreased borrowings, net of repayments under our revolving credit facility, decreased cash provided by the issuance of senior notes and preferred stock, and increased cash dividends paid on the Preferred Stock.

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

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

Contingent consideration arrangements. As part of the ExL Acquisition, as well as in each of the divestitures of our assets in Niobrara, Marcellus, and Utica, we agreed to contingent consideration arrangements, where we will receive or be required to pay certain amounts if commodity prices are greater than specified thresholds. See “Note 10. Derivative Instruments” for further details of each of these contingent consideration ~~arrangements. See also~~arrangements and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for details of the sensitivities to commodity price offor each contingent consideration arrangement.

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

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

Period Type of Contract Index
Volumes
(Bbls/d)

Fixed Price
($/Bbl)

Sub-Floor Price
($/Bbl)

Floor Price
($/Bbl)

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

$49.55

$—

$—

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



Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	4Q18	Price Swaps	NYMEX WTI	6,000		$49.55	—		—		—		—
Crude oil	4Q18	Three-Way Collars	NYMEX WTI	24,000	—			$39.38		$49.06		$60.14	—
Crude oil	4Q18	Basis Swaps	LLS-WTI Cushing	18,000	—		—		—		—			$5.11
Crude oil	4Q18	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			($0.10	)
Crude oil	4Q18	Sold Call Options	NYMEX WTI	3,388	—		—		—			$71.33	—

Crude oil	2019	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$73.40	—
Crude oil	2019	Basis Swaps	LLS-WTI Cushing	4,000	—		—		—		—			$4.87
Crude oil	2019	Basis Swaps	WTI Midland-WTI Cushing	7,389	—		—		—		—			($4.82	)
Crude oil	2019	Sold Call Options	NYMEX WTI	3,875	—		—		—			$73.66	—

Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	13,000	—		—		—		—			($1.27	)
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—

Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			$0.03



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)
NGLs	4Q18	Price Swaps	OPIS-Ethane	2,200		$12.01	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Propane	1,500		$34.23	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Butane	200		$38.85	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Isobutane	600		$38.98	—	—	—	—
NGLs	4Q18	Price Swaps	OPIS-Natural Gasoline	600		$55.23	—	—	—	—


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


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

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



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	4Q18	Price Swaps	NYMEX Henry Hub	25,000		$3.01	—	—	—		—
Natural gas	4Q18	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.25	—

Natural gas	2019	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.25	—

Natural gas	2020	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.50	—

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

If cash flows from operations and borrowings under our revolving credit facility and the other sources of cash described under “—Sources and Uses of Cash” are insufficient to fund our remaining 2018 drilling, completion, and infrastructure capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our remaining 2018 drilling, completion, and infrastructure capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Based on existing market conditions and our expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from divestitures, securities offerings or borrowings to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings. See “Note 14. Subsequent Events” for details of the notice of conditional redemption for the remaining $130.0 million aggregate principal amount of outstanding 7.50% Senior Notes.

Contractual Obligations

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


	July - December 2018		2019		2020		2021		2022		2023 and Thereafter		Total		October - December 2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$130,000		$—		$485,000		$900,000		$1,515,000		$—		$—		$130,000		$—		$309,837		$900,000		$1,339,837
Cash interest on senior notes ⁽²⁾	35,500		71,000		71,000		61,250		61,250		82,188		382,188		20,313		71,000		71,000		61,250		61,250		82,188		367,001
Cash interest and commitment fees on revolving credit facility ⁽³⁾	10,332		20,214		20,214		20,214		6,963		—		77,937		3,637		14,233		14,233		14,233		4,903		—		51,239
Capital leases	900		1,800		1,050		—		—		—		3,750		450		1,800		1,050		—		—		—		3,300
Operating leases	2,330		3,461		4,219		3,702		3,639		24,658		42,009		1,158		4,500		4,219		3,702		3,639		24,658		41,876
Drilling rig contracts ⁽⁴⁾	20,200		18,677		1,196		—		—		—		40,073		12,412		35,541		15,932		792		—		—		64,677
Delivery commitments ⁽⁵⁾	1,861		3,706		2,786		2,467		30		26		10,876		938		3,726		2,807		2,487		30		26		10,014
Produced water disposal commitments ⁽⁶⁾	5,283		18,599		18,698		18,708		18,764		17,453		97,505		3,331		21,336		21,443		21,445		21,501		17,678		106,734
Asset retirement obligations and other ⁽⁷⁾	1,833		2,972		657		376		239		15,745		21,822		633		2,853		910		377		244		16,499		21,516
Total Contractual Obligations ⁽⁸⁾		$78,239		$140,429		$249,820		$106,717		$575,885		$1,040,070		$2,191,160		$42,872		$154,989		$261,594		$104,286		$401,404		$1,041,049		$2,006,194

(1)

Long-term debt consists of the principal amounts of the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, the 8.25% Senior Notes due 2025, and borrowings outstanding under our revolving credit facility which matures in 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been redeemed or refinanced on or prior to such time). Subsequent to September 30, 2018, we delivered a notice of conditional redemption to the trustee for our 7.50% Senior Notes to call for redemption the remaining $130.0 million aggregate principal amount of our outstanding 7.50% Senior Notes due 2020, which was satisfied on October 29, 2018 in connection with entering into the thirteenth amendment to our credit agreement governing our revolving credit facility. See “Note 14. Subsequent Events” for further details.


(2)	Cash interest on senior notes includes cash payments for interest on the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, and the 8.25% Senior Notes due 2025.

(3)

Cash interest on our revolving credit facility was calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of ~~June~~September 30, 2018 of ~~3.74%~~3.87%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of ~~June~~September 30, 2018, at the applicable commitment fee rate of ~~0.50%~~0.375%.


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


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


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


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


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

Financing Arrangements

Senior Secured Revolving Credit Facility

We have a senior secured revolving credit facility with a syndicate of banks that, as of ~~June~~September 30, 2018, had a borrowing base of $1.0 billion, with an elected commitment amount of $900.0 million, and ~~$485.0~~$309.8 million of borrowings outstanding at a weighted average interest rate of ~~3.74%~~3.87%. The credit agreement governing our senior secured revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been redeemed or refinanced on or prior to such time) and any outstanding borrowings are due. Upon redemption of the 7.50% Senior Notes discussed below, the May 4, 2022 maturity date of the credit agreement will no longer be subject to a springing maturity date of June 15, 2020.

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

On May 4, 2018, we entered into the twelfth amendment to the credit agreement governing the revolving credit facility to, among other things, increase the borrowing base and elected commitment amount, reduce the margins applied to Eurodollar and base rate

loans, and amend the covenant limiting payment of dividends and distributions on equity to increase our ability to make dividends and distributions on our equity interests. See “Note 6. Long-Term Debt” for further details.

On October 29, 2018, we entered into the thirteenth amendment to the credit agreement governing the revolving credit facility to, among other things, increase the borrowing base and elected commitment amount and reduce the margins applied to Eurodollar and base rate loans. See “Note 14. Subsequent Events” for further details.

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

agreement as of September 30, 2018.

7.50% Senior Notes

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

~~We have~~On October 18, 2018, we delivered a notice of conditional redemption to the ~~right~~trustee for our 7.50% Senior Notes to ~~redeem all or a portion of~~call for redemption on November 19, 2018, the remaining $130.0 million aggregate principal amount of the outstanding 7.50% Senior Notes at a redemption ~~prices~~price of ~~101.875% until September 14, 2018 and~~ 100% ~~beginning September 15, 2018 and thereafter, in each case~~of par, plus accrued and unpaid interest. The redemption obligation was conditioned on and subject to there being made available to us under our revolving credit facility a commitment amount of at least $1.1 billion as of November 19, 2018, which was satisfied on October 29, 2018 in connection with the amendment to the credit agreement discussed above, therefore, our redemption obligation is no longer conditional. See “Note 14. Subsequent Events” for further details.

Redemption of Preferred Stock

InDuring the first quarter of 2018, we redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred ~~Stock. Upon redemption, we paid~~Stock, for $50.5 million, ~~which consisted~~consisting of ~~$1,000.00 per share of Preferred Stock redeemed, plus~~the $50.0 million redemption price and $0.5 million accrued and unpaid ~~dividends, with~~dividends. We recognized a ~~portion~~$7.1 million loss on the redemption due to the excess of the proceeds from the divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the divestitures of oil and gas properties. As a result of the redemption, we recorded a loss on redemption of preferred stock of $7.1 million, which included $0.1 million of direct costs incurred as a result of the redemption and a non-cash charge of $7.0 million attributable to the difference between $50.0 million ~~which was~~redemption price over the ~~consideration transferred to the holders of the Preferred Stock excluding accrued and unpaid dividends, and~~ $42.9 million ~~which was 20% of the~~redemption date carrying value of the Preferred ~~Stock on the date of redemption.~~Stock.

Redemption of Other Long-Term Debt

During the second quarter of 2018, we redeemed the remaining $4.4 million outstanding principal amount of our 4.375% Convertible Senior Notes due 2028 at a price equal to 100% of par. Upon redemption, we paid $4.5 million, which included accrued and unpaid interest of $0.1 ~~million from the last interest payment date up to, but not including, the redemption date.~~million.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, commitments and contingencies and preferred stock. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2017 Annual Report. See “Note 8. Preferred Stock”, “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for details of the ~~preferred stock~~Preferred Stock and contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our ~~June~~September 30, 2018 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, 2018 and, accordingly, does not consider drilling and completion activity, acquisitions or divestitures of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to ~~June~~September 30, 2018 that may require revisions to estimates of proved reserves.


	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
June 30, 2018 Actual	$57.10	$2.71	$1,158
September 30, 2018 Actual					$62.65	$2.55	$1,553

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$62.87	$3.01	$1,654	$496	$68.99	$2.85	$2,105	$552
Crude Oil and Natural Gas -10%	$51.31	$2.40	$595	($563)	$56.32	$2.25	$1,001	($552)

Crude Oil Price Sensitivity
Crude Oil +10%	$62.87	$2.71	$1,613	$455	$68.99	$2.55	$2,062	$509
Crude Oil -10%	$51.31	$2.71	$647	($511)	$56.32	$2.55	$1,044	($509)

Natural Gas Price Sensitivity
Natural Gas +10%	$57.10	$3.01	$1,198	$40	$62.65	$2.85	$1,596	$43
Natural Gas -10%	$57.10	$2.40	$1,117	($41)	$62.65	$2.25	$1,510	($43)

Income Taxes

Primarily as a result of the impairments of proved oil and gas properties recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016, we had a cumulative historical three year pre-tax loss and a net deferred tax asset position at June 30, 2018. We have assessed the realizability of our deferred tax assets and, beginning in the third quarter of 2015 and continuing through the second quarter of 2018, have concluded that it was more likely than not our deferred tax assets will not be realized and a valuation allowance was required. Based on current estimates, we anticipate that during 2019, we will no longer be in a cumulative historical three year pre-tax loss, at which time, based on analysis of available evidence, we may conclude that it is more likely than not our deferred tax assets will be realized. This conclusion could result in a portion or all of the remaining valuation allowance to be recognized in earnings as an income tax benefit. See “Note 5. Income Taxes” for further details of our valuation allowance as of June 30, 2018.

As of ~~June~~September 30, 2018, we have estimated U.S. federal net operating loss carryforwards of ~~$1.2~~$1.1 billion. Our ability to utilize these U.S. loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold.

Due to the issuance of the Preferred Stock and the common stock ~~offerings~~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, 2018, we do not believe we have a Section 382 limitation on the ability to utilize our U.S. loss carryforwards. Future equity transactions involving us or 5% shareholders of us (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes and therefore a limitation on the annual utilization of the U.S. loss carryforwards.

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

Recently Adopted and Recently Issued Accounting Pronouncements

See “Note 2. Summary of Significant Accounting Policies” for discussion of the pronouncements we recently adopted as well as the recently issued accounting pronouncements from the Financial Accounting Standards Board.

Forward-Looking Statements

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

our growth strategies;

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

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

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

changes in working capital requirements, reserves, and acreage;

the use of commodity derivative instruments to mitigate the effects of commodity price ~~risk management activities and the impact on~~volatility for a portion of our ~~average realized prices;~~forecasted sales of production;

anticipated trends in our business;

availability of pipeline connections and water disposal on economic terms;

effects of competition on us;

our future results of operations;

profitability of drilling locations;

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

our planned expenditures, prospects and capital expenditure plan;

future market conditions in the oil and gas industry;

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

results of the Devon Properties;

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

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

our ability to maintain a sound financial position;

receipt of receivables and proceeds from divestitures;

our ability to complete planned transactions on desirable terms; and

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

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “possible,” “scheduled,” “should,” “guidance” or other similar words. Such statements rely on assumptions and involve risks and uncertainties, many of which are beyond our control, including, but not limited to, those relating to a worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in ~~oil and gas~~commodity prices, the need to replace reserves depleted by production, impairments of proved oil and gas properties, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base ~~determinations (including determinations by lenders)~~redeterminations and availability under our revolving credit facility, evaluations of us by lenders under our revolving credit facility, waivers or amendments under our revolving credit facility in connection with acquisitions, other actions by lenders and holders of our capital stock, the potential impact of

government regulations, including current and proposed

legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, failure to realize the anticipated benefits of an acquisition, including the ~~any acquisition,~~Devon Acquisition, exercise of third party purchase rights under area of mutual interest provisions under a joint operating agreement, market conditions and other factors affecting our ability to pay dividends on or redeem the Preferred Stock, integration and other acquisition risks, other factors affecting our ability to reach agreements or complete acquisitions or dispositions, actions by sellers and buyers, effects of purchase price adjustments, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes, ~~and impact fees,~~ delays, costs and difficulties relating to our joint ventures, actions by joint venture parties, results of exploration activities, the availability, market conditions and completion of land acquisitions and dispositions, costs of oilfield services, completion and connection of wells, and other factors detailed in this quarterly report.

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

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under “Part I. Item 1A. Risk Factors” and other sections of our 2017 Annual Report and in our other filings with the SEC, including this quarterly report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2017 Annual Report. Except as disclosed below, there have been no material changes from the disclosure made in our 2017 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, 2018 as well as the ~~impacts~~impact on the crude oil, NGL, and natural gas revenues assuming a 10% ~~fluctuation~~increase and decrease in our average realized crude oil, NGL, and natural gas prices, excluding the impact of derivative settlements:


	Three Months Ended June 30, 2018								Three Months Ended September 30, 2018
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$229,798		$21,269		$12,906		$263,973		$254,525		$33,798		$15,052		$303,375

Impact of a 10% fluctuation in average realized prices		$22,980		$2,127		$1,291		$26,398		$25,450		$3,381		$1,506		$30,337


	Six Months Ended June 30, 2018								Nine Months Ended September 30, 2018
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$424,717		$38,171		$26,365		$489,253		$679,242		$71,969		$41,417		$792,628

Impact of a 10% fluctuation in average realized prices		$42,472		$3,817		$2,636		$48,925		$67,931		$7,197		$4,147		$79,275

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

Instruments” for further details of our crude oil, NGL and natural gas commodity derivative ~~positions~~instruments as of ~~June~~September 30, 2018 and “Note 14. Subsequent Events” for further details of our crude oil derivative ~~positions~~instruments entered into subsequent to ~~June~~September 30, 2018.

The ~~fair value~~primary drivers of our commodity derivative ~~contracts~~instrument fair values are ~~largely determined by estimates of~~ the underlying forward ~~curves of the relevant~~oil and gas price ~~indices.~~curves. The following table sets forth the fair values as of ~~June~~September 30, 2018, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the ~~respective~~underlying forward oil and gas price curves:

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

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

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

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



	Crude oil			NGLs			Natural gas			Total
	(In thousands)
Fair value liability as of September 30, 2018		$128,497			$7,378			$1,832			$137,707

Impact of a 10% increase in forward commodity prices		$75,109			$1,887			$2,266			$79,262
Impact of a 10% decrease in forward commodity prices		($56,318	)		($1,845	)		($1,376	)		($59,539	)

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

The following table sets forth the fair values of the contingent consideration arrangements as of ~~June~~September 30, 2018, as well as the impact on the fair values assuming a 10% increase and decrease in the ~~respective future commodity prices:~~underlying forward oil and gas price curves:

Contingent ExL Consideration Contingent Niobrara Consideration Contingent Marcellus Consideration Contingent Utica Consideration
(In thousands)
Potential (payment) receipt per year
($50,000 )
$5,000

$3,000

$5,000
Maximum potential (payment) receipt
($125,000 )
$15,000

$7,500

$15,000

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

$1,530

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



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

Fair value (liability) asset as of September 30, 2018		($112,045	)		$11,675			$1,315			$12,215
Impact of a 10% increase in forward commodity prices		($2,685	)		$835			$625			$690
Impact of a 10% decrease in forward commodity prices		$5,490			($1,270	)		($530	)		($1,130	)

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding borrowings on our revolving credit facility. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate 7.50% Senior Notes, 6.25% Senior Notes, and 8.25% Senior Notes, but can impact their fair values. As of ~~June~~September 30, 2018, we had approximately ~~$1.5~~$1.3 billion of long-term debt ~~outstanding, net of unamortized premiums and debt issuance costs.~~outstanding. Of this amount, approximately $1.0 billion was fixed-rate debt ~~net of unamortized premiums and debt issuance costs,~~ with a weighted average interest rate of ~~7.10%~~6.89%. See “Note 11. Fair Value Measurements” for further details on the fair value of our 7.50% Senior Notes, 6.25% Senior Notes, and 8.25% Senior Notes.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of ~~June~~September 30, 2018 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended ~~June~~September 30, 2018 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

The following disclosure updates the legal proceeding set forth under the heading “Barrow-Shaver Litigation” in the 2017 Annual Report to reflect developments during the three months ended September 30, 2018 and should be read together with the corresponding disclosure in the 2017 Annual Report.

Barrow-Shaver Litigation

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 filed a motion for rehearing with the Twelfth Court of Appeals at Tyler, Texas, which was not granted, and petitioned the Texas Supreme Court for review. In August 2018, the Texas Supreme Court granted review and set oral argument for December 4, 2018. 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 above, the Twelfth Court of Appeals at Tyler, Texas found in favor of the Company on all grounds.

Item 1A. Risk Factors

There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our 2017 Annual Report.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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



Exhibit Number		Exhibit Description
†1~~3.1~~.1		~~Amended~~Underwriting Agreement, dated as of August 14, 2018, by and ~~Restated Bylaws of~~between Carrizo Oil & Gas, Inc.~~, adopted May 23, 2018~~ and Citigroup Global Markets Inc. and Goldman Sachs & Co. LLC, as representatives of the Underwriters (incorporated herein by reference to Exhibit ~~3.1~~1.1 to the Company’s Current Report on Form 8-K filed on ~~May 29, 2018 (File No. 000-29187-87)).~~
†~~10.1~~		Form of Indemnification Agreement for Directors and Executive Officers of the Company, adopted May 23, 2018 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 29, 2018 (File No. 000-29187-87))August 16, 2018).
*31.1	—	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	—	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	—	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	—	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101	—	Interactive Data Files


†	Incorporated by reference as indicated.


*	Filed herewith.

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

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

~~-48-~~-51-