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 September 30, ~~2017~~2018



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

For the transition period from to

Commission File Number: 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)



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

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

(713) 328-1000

(Registrant’s telephone number)

____________________________________________________________

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

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

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



Large accelerated filer	þ	Accelerated filer	¨

Non-accelerated filer	¨ ~~(Do not check if a smaller reporting company)~~	Smaller reporting company	¨

		Emerging growth company	¨

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of November ~~3, 2017~~2, 2018 was ~~81,454,621.~~91,625,532.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of September 30, ~~2017~~2018 and December 31, ~~2016~~2017	2
	Consolidated Statements of ~~Operations~~Income for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017	3
	Consolidated Statement of Shareholders’ Equity for the nine months ended September 30, ~~2017~~2018	4
	Consolidated Statements of Cash Flows for the nine months ended September 30, ~~2017~~2018 and ~~2016~~2017	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4947
Item 4.	Controls and Procedures	4948
Part II. Other Information
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5049
Item 3.	Defaults Upon Senior Securities	5049
Item 4.	Mine Safety Disclosures	5049
Item 5.	Other Information	5049
Item 6.	Exhibits	5150
Signatures		5251

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)


	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
Assets
Current assets
Cash and cash equivalents		$5,092			$4,194			$2,415			$9,540
Accounts receivable, net	89,809			64,208			128,780			107,441
Derivative assets							10,258			—
Other current assets	7,826			4,586			9,636			5,897
Total current assets	102,727			72,988			151,089			122,878
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,882,575			1,294,667			2,124,767			1,965,347
Unproved properties, not being amortized	740,205			240,961			579,275			660,287
Other property and equipment, net	10,538			10,132			10,885			10,176
Total property and equipment, net	2,633,318			1,545,760			2,714,927			2,635,810
Deposit for pending acquisition of oil and gas properties							21,500			—
Other assets	9,681			7,579			23,482			19,616
Total Assets		$2,745,726			$1,626,327			$2,910,998			$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$87,077			$55,631			$147,670			$74,558
Revenues and royalties payable	46,821			38,107			52,975			52,154
Accrued capital expenditures	111,485			36,594			117,556			119,452
Accrued interest	25,305			22,016			23,748			28,362
Accrued lease operating expense	16,394			12,377
Derivative liabilities	6,778			22,601			162,895			57,121
Other current liabilities	24,579			24,633			50,918			41,175
Total current liabilities	318,439			211,959			555,762			372,822
Long-term debt	1,701,439			1,325,418			1,327,689			1,629,209
Asset retirement obligations	24,671			20,848			17,071			23,497
Derivative liabilities	77,184			27,528			102,103			112,332
Deferred income taxes							4,699			3,635
Other liabilities	21,914			17,116			8,703			51,650
Total liabilities	2,143,647			1,602,869			2,016,027			2,193,145
Commitments and contingencies
Preferred stock
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of September 30, 2017 and none issued and outstanding as of December 31, 2016	213,400			—
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; 81,454,621 issued and outstanding as of September 30, 2017 and 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016	815			651
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	1,926,798			1,665,891			2,132,253			1,926,056
Accumulated deficit	(1,538,934		)	(1,643,084		)	(1,411,827		)	(1,555,974		)
Total shareholders’ equity	388,679			23,458			721,342			370,897
Total Liabilities and Shareholders’ Equity		$2,745,726			$1,626,327			$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 ~~OPERATIONS~~INCOME

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Revenues
Crude oil		$152,101			$95,154			$422,999			$254,758			$254,525			$152,101			$679,242			$422,999
Natural gas liquids	12,467			5,616			27,678			15,119			33,798			12,467			71,969			27,678
Natural gas	16,711			10,407			48,440			29,886			15,052			16,711			41,417			48,440
Total revenues	181,279			111,177			499,117			299,763			303,375			181,279			792,628			499,117

Costs and Expenses
Lease operating	34,874			24,282			100,767			71,071			41,022			34,874			115,446			100,767
Production taxes	7,741			4,886			21,092			12,940			14,516			7,741			37,578			21,092
Ad valorem taxes	1,736			1,426			5,776			3,950			2,588			1,736			8,201			5,776
Depreciation, depletion and amortization	67,564			48,949			181,018			160,492			80,108			67,564			217,005			181,018
General and administrative, net	16,029			18,119			49,328			59,046			12,811			16,029			58,368			49,328
(Gain) loss on derivatives, net	24,377			(11,744		)	(27,004		)	29,938			55,388			24,377			152,698			(27,004		)
Interest expense, net	20,673			21,190			62,350			58,913			15,406			20,673			46,522			62,350
Impairment of proved oil and gas properties	—			105,057			—			576,540
Other expense, net	462			499			1,640			1,568
Loss on extinguishment of debt													—			—			8,676			—
Other (income) expense, net													(690		)	462			2,305			1,640
Total costs and expenses	173,456			212,664			394,967			974,458			221,149			173,456			646,799			394,967

Income (Loss) Before Income Taxes	7,823			(101,487		)	104,150			(674,695		)
Income tax benefit	—			313			—			—
Net Income (Loss)		$7,823			($101,174	)		$104,150			($674,695	)
Income Before Income Taxes													82,226			7,823			145,829			104,150
Income tax expense													(880		)	—			(1,682		)	—
Net Income														$81,346			$7,823			$144,147			$104,150
Dividends on preferred stock	(2,249		)	—			(2,249		)	—			(4,457		)	(2,249		)	(13,794		)	(2,249		)
Net Income (Loss) Attributable to Common Shareholders		$5,574			($101,174	)		$101,901			($674,695	)
Accretion on preferred stock													(771		)	—			(2,264		)	—
Loss on redemption of preferred stock													—			—			(7,133		)	—
Net Income Attributable to Common Shareholders														$76,118			$5,574			$120,956			$101,901

Net Income (Loss) Attributable to Common Shareholders Per Common Share
Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.07			($1.72	)		$1.44			($11.49	)		$0.88			$0.07			$1.45			$1.44
Diluted		$0.07			($1.72	)		$1.43			($11.49	)		$0.85			$0.07			$1.42			$1.43

Weighted Average Common Shares Outstanding
Basic	81,053			58,945			70,728			58,705			86,727			81,053			83,461			70,728
Diluted	81,138			58,945			71,147			58,705			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, 2016	65,132,499		$651	Additional Paid-in Capital			$1,665,891				($1,643,084	Total Shareholders’ Equity	)		$23,458
Balance as of December 31, 2017															81,454,621		$815		$1,926,056			($1,555,974	)		$370,897
Stock-based compensation expense	—	—		17,967				—				17,967			—	—		15,701			—			15,701
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	722,122	8		(36		)		—				(28		)
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	15,600,000	156		222,222				—				222,378			9,500,000	95		213,762			—			213,857
Issuance of warrants	—	—		23,003				—				23,003
Dividends on preferred stock	—	—		(2,249		)		—				(2,249		)	—	—		(13,794		)	—			(13,794		)
Accretion on preferred stock															—	—		(2,264		)	—			(2,264		)
Loss on redemption of preferred stock															—	—		(7,133		)	—			(7,133		)
Net income	—	—		—				104,150				104,150			—	—		—			144,147			144,147
Balance as of September 30, 2017	81,454,621		$815		$1,926,798				($1,538,934	)			$388,679
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)


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2018			2017
Cash Flows From Operating Activities
Net income (loss)		$104,150			($674,695	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Net income								$144,147			$104,150
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	181,018			160,492			217,005			181,018
Impairment of proved oil and gas properties	—			576,540
(Gain) loss on derivatives, net	(27,004		)	29,938			152,698			(27,004		)
Cash received for derivative settlements, net	7,714			98,820
Cash received (paid) for derivative settlements, net							(64,710		)	7,714
Loss on extinguishment of debt							8,676			—
Stock-based compensation expense, net	8,462			30,834			13,786			8,462
Deferred income taxes							1,063			—
Non-cash interest expense, net	2,961			3,105			1,878			2,961
Other, net	4,249			2,427			4,100			4,249
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(25,885		)	1,768			(12,763		)	(25,885		)
Accounts payable	14,748			(20,294		)	10,863			14,748
Accrued liabilities	11,970			(7,954		)	(9,336		)	11,970
Other assets and liabilities, net	(1,786		)	(3,134		)	(2,115		)	(1,786		)
Net cash provided by operating activities	280,597			197,847			465,292			280,597
Cash Flows From Investing Activities
Capital expenditures	(433,561		)	(346,245		)	(662,459		)	(433,561		)
Acquisitions of oil and gas properties	(692,006		)	—			—			(692,006		)
Proceeds from divestitures of oil and gas properties, net	18,212			15,331
Deposit for pending divestiture of oil and gas properties	6,200			—
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	(3,804		)	(661		)	(2,687		)	(3,804		)
Net cash used in investing activities	(1,104,959		)	(331,575		)	(308,953		)	(1,104,959		)
Cash Flows From Financing Activities
Issuance of senior notes	250,000			—			—			250,000
Redemptions of senior notes and other long-term debt							(330,435		)	—
Redemption of preferred stock							(50,030		)	—
Borrowings under credit agreement	1,311,875			510,116			2,415,208			1,311,875
Repayments of borrowings under credit agreement	(1,183,275		)	(414,116		)	(2,396,671		)	(1,183,275		)
Payments of debt issuance costs and credit facility amendment fees	(8,964		)	(1,150		)	(627		)	(8,964		)
Sale of common stock, net of offering costs	222,378			—			213,857			222,378
Sale of preferred stock, net of issuance costs	236,404			—			—			236,404
Payment of dividends on preferred stock	(2,249		)	—
Payments of dividends on preferred stock							(13,794		)	(2,249		)
Other, net	(909		)	(805		)	(972		)	(909		)
Net cash provided by financing activities	825,260			94,045
Net cash provided by (used in) financing activities							(163,464		)	825,260
Net Increase (Decrease) in Cash and Cash Equivalents	898			(39,683		)	(7,125		)	898
Cash and Cash Equivalents, Beginning of Period	4,194			42,918			9,540			4,194
Cash and Cash Equivalents, End of Period		$5,092			$3,235			$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, ~~2016~~2017 (“~~2016~~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

The Company has provided a discussion of significant accounting policies, estimates, and judgments in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its 2016 Annual Report. There have been no changes to the Company’s significant accounting policies since December 31, 2016, other than the recently adopted accounting pronouncement described below and the accounting for the ExL Acquisition and related financing. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties”, “Note 8. Preferred Stock”, “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

Recently Adopted Accounting ~~Pronouncement~~Standards

~~Stock Compensation.~~Revenue From Contracts with Customers In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption.

. Effective January 1, ~~2017,~~2018, the Company adopted ASU ~~2016-09. Using~~No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASC 606”) using the modified retrospective ~~approach as prescribed by ASU 2016-09,~~method and has applied the ~~Company recognized previously unrecognized windfall tax benefits which resulted~~standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a ~~cumulative-effect adjustment~~five-step revenue recognition model to ~~retained earnings~~depict the transfer of ~~approximately $15.7 million. This adjustment increased deferred tax assets, which~~goods or services to customers in ~~turn increased~~an amount that reflects the ~~valuation allowance by the same amount as of the beginning of 2017, resulting~~consideration in ~~a net cumulative-effect adjustment to retained earnings of zero.~~exchange for those goods or services. As a result of adoption, on a prospective basis as prescribed by ASU 2016-09, all windfall tax benefits and tax shortfalls will be recorded as income tax expense or benefit in the consolidated statements of operations. As long asadopting ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information for the three and nine months ended September 30, 2017 has not been recast and continues to ~~conclude~~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 summarize the impact of adoption for the three and nine months ended September 30, 2018:



	Three Months Ended September 30, 2018
	Under ASC 606		Under ASC 605		Increase		% Increase
	(In thousands)
Revenues
Crude oil		$254,525		$254,382		$143	0.1	%
Natural gas liquids	33,798		32,018		1,780		5.6	%
Natural gas	15,052		14,280		772		5.4	%
Total revenues	303,375		300,680		2,695		0.9	%

Costs and Expenses
Lease operating	41,022		38,327		2,695		7.0	%

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



	Nine Months Ended September 30, 2018
	Under ASC 606		Under ASC 605		Increase		% Increase
	(In thousands)
Revenues
Crude oil		$679,242		$678,834		$408	0.1	%
Natural gas liquids	71,969		68,253		3,716		5.4	%
Natural gas	41,417		39,439		1,978		5.0	%
Total revenues	792,628		786,526		6,102		0.8	%

Costs and Expenses
Lease operating	115,446		109,344		6,102		5.6	%

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

Changes to crude oil, NGL, and natural gas revenues and lease operating expense are due to the conclusion that the ~~valuation allowance against its net deferred tax assets is necessary, this portion~~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 ~~ASU 2016-09 will have no significant effect on the Company’s consolidated balance sheets or consolidated statements of operations. In addition, windfall tax benefits~~control are ~~now required to be presented~~included in ~~cash flows from~~lease operating activities in the consolidated statements of cash flows as compared to cash flows from financing activities, which the Company has elected to adopt prospectively. There are no periods presented that would require reclassification of cash flows had the Company elected to adopt this guidance retrospectively. Further, the Company has elected to account for forfeitures as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.

~~Recently Issued Accounting Pronouncements~~expense.

Business Combinations. In January 2017, the ~~FASB~~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 ~~disposals)~~divestitures) of assets or businesses. Effective January 1, 2018, the Company adopted ASU 2017-01 isusing the prospective method and will apply the clarified definition of a business to ~~be applied on a~~

~~prospective basis~~future acquisitions and is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The Company currently plans to adopt the guidance on the effective date of January 1, 2018.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 ~~is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, provided that it is adopted in its entirety in~~using the ~~same period. Companies are required to use a full~~ retrospective approach ~~meaning~~as prescribed by ASU 2016-15. There were no changes to the ~~standard is applied to all periods presented. The Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements~~statement of cash flows ~~and related disclosures upon~~as a result of adoption. ~~The Company plans to adopt the guidance on the effective date of January 1, 2018.~~

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 ~~currently assessing~~in the ~~impact~~process of reviewing and determining the contracts to which ASU 2016-02 ~~which includes an analysis~~applies with the assistance of ~~existing~~a third party consultant. These include contracts ~~including~~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 ~~ASU 2016-02. Appropriate systems, controls, and processes to support the recognition and disclosure requirements of~~ the new ~~standard are also being evaluated.~~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) ~~an increase~~increases in depreciation, depletion and amortization and interest expense, (iii) ~~an increase~~decreases in ~~interest~~lease operating and general and administrative expense and (iv) additional ~~disclosures.~~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.

~~Revenue From Contracts With Customers.~~ ~~In May 2014, the FASB issued~~ As permitted by ASU No. ~~2014-09,~~ 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.

Revenue ~~From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under~~Recognition

The Company’s revenues are comprised solely of revenues from customers and include the ~~new standard,~~sale of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure ofinto these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows ~~arising~~are affected by economic factors based on its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. As of September 30, 2018 and December 31, 2017, receivables from contracts with ~~customers. ASU 2014-09~~customers were $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 ~~effective for interim and annual periods beginning after December 15, 2017 using either a full retrospective approach, which is described above, or a modified retrospective approach, meaning~~primarily sold at the ~~cumulative effect~~wellhead at an agreed upon index price, net of ~~initially applying the standard~~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 ~~most current period presented~~transaction and has concluded it is the principal and the purchasers of the NGLs and residue gas are the customers. Revenue is recognized on a gross basis, with gathering, processing and transportation fees recognized as lease operating expense in the ~~financial statements.~~consolidated statements of income as the Company maintains control throughout processing.

Transaction Price Allocated to Remaining Performance Obligations. The Company ~~is currently assessing~~applied the ~~impact of ASU 2014-09 which includes an analysis of existing contracts and current accounting policies and disclosures to identify potential differences that would result from applying~~practical expedient in ASC 606 exempting the ~~requirements~~disclosure of the ~~new standard. Appropriate changes~~transaction price allocated to ~~business processes, systems or controls will be implemented~~remaining performance obligations if the variable consideration is allocated entirely to ~~support recognition~~a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure ~~under~~of the ~~new standard. Although its assessment is in progress, the Company currently does not expect the adoption of ASU 2014-09~~transaction price allocated to ~~have a material impact on its consolidated financial statements because existing contractual~~remaining performance obligations ~~which determine when and how revenue~~ is ~~recognized, are~~ not materially changed under the new standard; thus, revenue associated with the majority of the Company’s existing contracts will continue to be recognized as control of products is transferred to the customer. The Company plans to adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.required.

Net Income ~~(Loss)~~Attributable to Common Shareholders Per Common Share

~~Supplemental~~The following table summarizes the calculation of net income ~~(loss)~~attributable to common shareholders per common share:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(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		$76,118			$5,574			$120,956			$101,901

Basic weighted average common shares outstanding	86,727			81,053			83,461			70,728
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	89,039			81,138			85,221			71,147

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.88			$0.07			$1.45			$1.44
Diluted		$0.85			$0.07			$1.42			$1.43

The computation of diluted net income attributable to common shareholders per common share ~~information is provided below:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(In thousands, except per share amounts)
Net Income (Loss) Attributable to Common Shareholders
$5,574

($101,174 )
$101,901

($674,695 )
Basic weighted average common shares outstanding 81,053
58,945
70,728
58,705
Effect of dilutive instruments 85
—
419
—
Diluted weighted average common shares outstanding 81,138
58,945
71,147
58,705
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic
$0.07

($1.72 )
$1.44

($11.49 )
Diluted
$0.07

($1.72 )
$1.43

($11.49 )

~~When the Company recognizes a net loss, as was the case for the three months~~excluded restricted stock, performance shares and ~~nine months ended September 30, 2016, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per~~ common ~~share.~~stock warrants that were anti-dilutive. The following table ~~below~~ presents the weighted average ~~dilutive and~~ anti-dilutive securities ~~outstanding~~ for the periods ~~presented which consisted of unvested restricted stock awards and units, unvested performance shares and exercisable common stock warrants:~~presented:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(In thousands)
Dilutive 85
—
419
—
Anti-dilutive 882
698
120
664



	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

Devon Acquisition. On August 13, 2018, the Company entered into a purchase and sale agreement with Devon Energy Production Company, L.P. (“Devon”), a subsidiary of Devon Energy Corporation, to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas (the “Devon Properties”) for an agreed upon price of $215.0 million, with an effective date of April 1, 2018, subject to customary purchase price adjustments (the “Devon Acquisition”). The Company paid $21.5 million as a deposit on August 13, 2018 and $183.4 million upon initial closing on October 17, 2018, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing 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.

Delaware Basin Divestiture. On July 11, 2018, the Company 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 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 of $135.6 million. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. 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.

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

2017 Acquisitions and Divestitures

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. ~~(together “ExL”)~~ to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward ~~Counties,~~counties, Texas ~~(the “ExL Properties”)~~ for ~~a purchase~~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 ~~transaction had an effective date of May 1, 2017. The~~ Company paid $75.0 million ~~to the seller~~ as a deposit on June 28, 2017, ~~and~~ $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 ~~preliminary~~ purchase price adjustments primarily related to the net cash flows from the ~~acquired wells and capital expenditures from the~~ effective date to the closing date. ~~Upon closing~~As part of the ExL Acquisition, the Company ~~became the operator of the ExL Properties with an approximate 70% average working interest.~~

~~The Company also~~ agreed to ~~pay an additional $50.0 million per year if the average daily closing spot price of~~ a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00 for any of the years of 2018, 2019, 2020 and 2021, with such payments due on January 29, 2019, January 28, 2020, January 28, 2021 and January 28, 2022, respectively. This paymentcontingent consideration arrangement (the “Contingent ExL ~~Payment”~~Consideration”) will be zero for the respective year if such EIA WTI average price of a barrel of oil is $50.00 or below for any of such years, and the Contingent ExL Payment is capped at $125.0 million in the aggregate. The Company, which was determined ~~that the Contingent ExL Payment is~~to be an embedded ~~derivative and has reflected~~derivative. As a result, the liability is recorded at fair value in the consolidated ~~financial statements. The~~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 ~~Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was $60.3 million and $52.3 million, respectively.~~period in which the changes occur. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

The Company funded the ExL Acquisition with net proceeds from the sale of preferred stock on August 10, 2017, net proceeds from the common stock offering completed on July 3, 2017, and net proceeds from the senior notes offering completed on July 14, 2017. See “Note 8. Preferred Stock” for details regarding the sale of Preferred Stock, “Note 9. Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering and “Note 6. Long-Term Debt” for details regarding the senior notes offering.

The ExL Acquisition was accounted for ~~under the acquisition method of accounting whereby~~as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in

determining the fair value of the oil and gas properties. Significant inputs into the calculation included ~~future commodity prices,~~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 ~~Payment~~Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included ~~future commodity prices,~~forward oil and gas price curves, volatility factors, ~~for the future commodity prices~~ and a risk adjusted discount rate. See “Note 11. Fair Value Measurements” for further details.

The purchase price allocation for the ExL Acquisition is preliminary and subject to change based on updates to purchase price adjustments primarily related to net cash flows from the acquired wells and capital expenditures from the effective date to the closing date. The Company currently expects to finalize its allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date during the third quarter of 2018.

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



	~~Preliminary~~ Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	~~292,551~~294,754
Unproved properties	443,194
Total oil and gas properties		$~~735,745~~737,948
Total assets acquired		$~~735,851~~738,054

Liabilities
Revenues and royalties payable		$~~5,036~~5,785
Asset retirement obligations	153
Contingent ExL ~~Payment~~Consideration	52,300
Total liabilities assumed		$~~57,489~~58,238
Net Assets Acquired		$~~678,362~~679,816

~~Included~~The results of operations for the ExL Acquisition have been included in the Company’s consolidated statements of ~~operations~~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 ~~are total revenues of $14.0 million and income before income taxes of $11.4 million from~~as shown in the ~~ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.~~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 ~~month periods~~months ended September 30, 2017, ~~and 2016,~~ 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,					Nine Months Ended September 30,
	2017		2016			2017		2016			Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	(In thousands, except per share amounts)										(In thousands, except per share amounts)
Total revenues		$189,499		$115,065			$534,607		$305,074			$189,499		$534,607
Net Income (Loss) Attributable to Common Shareholders		$14,654		($106,598	)		$115,053		($688,902	)
Net Income Attributable to Common Shareholders												$14,654		$115,053

Net Income (Loss) Attributable to Common Shareholders Per Common Share
Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.18		($1.43	)		$1.63		($9.27	)		$0.18		$1.63
Diluted		$0.18		($1.43	)		$1.62		($9.27	)		$0.18		$1.62

Weighted Average Common Shares Outstanding
Basic	81,053		74,545			70,728		74,305
Diluted	81,138		74,545			71,147		74,305

~~Sanchez Acquisition.~~Marcellus Divestiture. On ~~December 14, 2016,~~October 5, 2017, the Company ~~completed its initial closing of the acquisition of oil~~entered into a purchase and ~~gas properties in the Eagle Ford Shale from Sanchez Energy Corporation and SN Cotulla Assets,~~sale agreement with BKV Chelsea, LLC, a subsidiary of ~~Sanchez Energy Corporation (the “Sanchez Acquisition”). The transaction had~~Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an effective date of June 1, 2016 and was accounted for under the acquisition method of accounting whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then available information.

~~At the time of the initial closing, an adjustment to the purchase~~agreed upon price of ~~$16.8~~$84.0 million. The Company received $6.3 million ~~was made for leases that were not conveyed to the Company. On January 9,~~into escrow as a deposit on October 5, 2017 and ~~April 13,~~$67.6 million upon closing on November 21, 2017, for aggregate net proceeds of $73.9 million. As part of this divestiture, the Company ~~paid $7.0 million~~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 ~~$9.8 million, respectively, for these outstanding leases when conveyed to~~losses as a result of changes in the ~~Company.~~

~~The following presents the 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~~		~~$477~~
~~Oil and gas properties~~
~~Proved properties~~	~~99,938~~
~~Unproved properties~~	~~74,536~~
~~Total oil and gas properties~~		~~$174,474~~
~~Total assets acquired~~		~~$174,951~~

~~Liabilities~~
~~Revenues and royalties payable~~		~~$1,442~~
~~Other current liabilities~~	~~323~~
~~Asset retirement obligations~~	~~2,054~~
~~Other liabilities~~	~~1,078~~
~~Total liabilities assumed~~		~~$4,897~~
~~Net Assets Acquired~~		~~$170,054~~

~~Included~~fair value between periods recognized in the consolidated statements of ~~operations~~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 ~~three~~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”). 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 nine months ended September 30, ~~2017 are total revenues~~2018. The Avista Marcellus joint venture agreements terminated during the third quarter of ~~$9.1 million and $23.2 million, respectively, and income before income taxes of $4.0 million and $7.1 million, respectively, from~~2018 in connection with the ~~Sanchez Acquisition, representing activity~~sale of the ~~acquired properties subsequent to the closing~~remaining immaterial assets.

Steven A. Webster, Chairman of the ~~transaction through September 30, 2017.~~

~~Divestitures~~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.

~~Potential~~Utica Divestiture ~~of Utica Assets.~~. On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale ~~located primarily in Guernsey County, Ohio,~~ for an agreed upon price of $62.0 million. The ~~transaction has an effective date of April 1, 2017 and is expected to close by the end of November 2017. The~~ Company received $6.2 million ~~from the buyer~~ as a deposit on August 31, ~~2017.~~

~~The~~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 ~~could also receive~~agreed to a contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00, $53.00, and $56.00 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectivelyarrangement (the “Contingent Utica Consideration”)~~. The Contingent Utica Consideration will~~, which was determined to be ~~zero~~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 ~~the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years, and is capped at $15.0 million.~~further details.

~~Other Assets.~~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 ~~from this sale~~for each of the 2017 divestitures discussed above were recognized as a reduction of proved oil and gas ~~properties.~~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 September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, total property and equipment, net consisted of the following:


	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
	(In thousands)						(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,452,201			$4,687,416			$5,988,301			$5,615,153
Accumulated depreciation, depletion and amortization and impairments	(3,569,626		)	(3,392,749		)	(3,863,534		)	(3,649,806		)
Proved properties, net	1,882,575			1,294,667			2,124,767			1,965,347
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	697,370			211,067			516,537			612,589
Capitalized interest	42,835			29,894			62,738			47,698
Total unproved properties, not being amortized	740,205			240,961			579,275			660,287
Other property and equipment	25,344			23,127			28,134			25,625
Accumulated depreciation	(14,806		)	(12,995		)	(17,249		)	(15,449		)
Other property and equipment, net	10,538			10,132			10,885			10,176
Total property and equipment, net		$2,633,318			$1,545,760			$2,714,927			$2,635,810

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was ~~$13.04~~$13.29 and ~~$12.72~~$13.04 for the three months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively, and ~~$12.73~~$13.57 and ~~$13.79~~$12.73 for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~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 ~~$3.3~~$2.9 million and ~~$2.7~~$3.3 million for the three months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively, and ~~$10.6~~$15.6 million and ~~$8.5~~$10.6 million for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~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 $8.5 million ~~and $2.9 million~~ for the three months ended September 30, 2018 and 2017 and ~~2016, respectively,~~$27.6 million and $16.2 ~~million and $13.4~~ million for the nine months ended September 30, 2018 and 2017, ~~and 2016,~~ respectively.

~~Impairment of Proved Oil and Gas Properties~~

At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unproved properties not being amortized, and (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using 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 period (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

The Company did not recognize impairments of proved oil and gas properties for the three and nine months ended September 30, 2017. Primarily due to declines in the 12-Month Average Realized Prices of crude oil, the Company recognized impairments of proved oil and gas properties for the three and nine months ended September 30, 2016. Details of the 12-Month Average Realized Price of crude oil for the three and nine months ended September 30, 2017 and 2016 and the impairments of proved oil and gas properties for the three and nine months ended September 30, 2016 are summarized in the table below:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Impairment of proved oil and gas properties (in thousands)
$—
$105,057
$—
$576,540
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period $46.80 $39.84 $39.60 $47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period $47.74 $38.36 $47.74 $38.36
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period 2 % (4 %) 21 % (19 %)

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 income or loss attributable to the tax jurisdictions in which the Company operates.they occur.

The Company’s income tax ~~(expense) benefit~~expense differs from the income tax ~~(expense) benefit~~expense computed by applying the U.S. federal statutory corporate income tax rate of ~~35% to income (loss) before income taxes as follows:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(In thousands)
Income (loss) before income taxes
$7,823

($101,487 )
$104,150

($674,695 )
Income tax (expense) benefit at the statutory rate (2,738 ) 35,520
(36,452 ) 236,143
State income tax (expense) benefit, net of U.S. federal income taxes (247 ) 575
(1,974 ) 3,859
Tax shortfalls from stock-based compensation expense (273 ) —
(3,029 ) —
(Increase) decrease in deferred tax assets valuation allowance 3,253
(36,696 ) 41,570
(240,897 )
Other 5
914
(115 ) 895
Income tax benefit
$—

$313

$—

$—

~~Deferred Tax Assets Valuation Allowance~~

~~Deferred tax assets are recorded~~21% for ~~net operating losses~~the three and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

~~A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at~~nine months ended September 30, ~~2017, driven primarily by the impairments of proved oil~~2018 and gas properties recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential35% for future growth. Beginning in the third quarter of 2015, and continuing through the third quarter of 2017, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including September 30, 2017, were reduced to zero.

As a result of adopting ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets,

which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017.

~~For~~ the three and nine months ended September 30, 2017, ~~primarily~~to income before income taxes as follows:



	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 ~~result~~provisional estimate of ~~current activity, partial releases~~the impacts of ~~$3.3 million~~the Act in earnings for the year ended December 31, 2017 and ~~$41.6 million, respectively,~~also provided a one-year measurement period in which the Company would record additional impacts from the ~~valuation allowance was recorded~~enactment of the Act as they are identified. 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 ~~bring~~Section 162(m)’s deduction limit under the ~~net deferred tax assets to zero. After~~Act and the scope of transition relief available under the Act. The Company is currently evaluating the impact of ~~the partial release the valuation allowance~~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 and additional guidance provided within the one year measurement period.

Deferred Tax Asset Valuation Allowance

The deferred tax asset valuation allowance was $299.1 million and $333.0 million as of September 30, 2018 and December 31, 2017, ~~was $538.5 million. For~~respectively. Decreases in the valuation allowance for the three months and nine months ended September 30, ~~2016,~~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 ~~recorded additional valuation allowances of $36.7 million and $240.9 million, respectively, primarily as~~maintained a ~~result of the impairments of proved oil and gas properties during these periods.~~

~~The Company will continue to evaluate whether the~~full valuation allowance ~~is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net~~against its deferred tax assets ~~are~~based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not ~~to be realized. Future events or new evidence which may lead~~ that

the ~~Company to conclude that it is more likely than not its net~~ deferred tax assets ~~will~~would not be ~~realized include, but are not limited~~realized. The Company intends to cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that themaintain a full valuation allowance against its ~~net~~ deferred tax assets until there is ~~necessary,~~sufficient evidence to support the ~~Company will have no significant deferred income tax expense or benefit.~~reversal of such valuation allowance.

6. Long-Term Debt

Long-term debt consisted of the following as of September 30, ~~2017~~2018 and December 31, ~~2016:~~2017:


	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
	(In thousands)						(In thousands)
Senior Secured Revolving Credit Facility due 2022		$215,600			$87,000			$309,837			$291,300
7.50% Senior Notes due 2020	600,000			600,000			130,000			450,000
Unamortized premium for 7.50% Senior Notes	836			1,020			124			579
Unamortized debt issuance costs for 7.50% Senior Notes	(6,397		)	(7,573		)	(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	(8,527		)	(9,454		)	(7,219		)	(8,208		)
8.25% Senior Notes due 2025	250,000			—			250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(4,498		)	—			(4,073		)	(4,395		)
Other long-term debt due 2028	4,425			4,425			—			4,425
Long-term debt		$1,701,439			$1,325,418			$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 September 30, ~~2017,~~2018, had a borrowing base of ~~$837.5 million,~~$1.0 billion, with an elected commitment amount of ~~$800.0~~$900.0 million, and ~~$215.6 million of~~ borrowings outstanding of $309.8 million at a weighted average interest rate of ~~3.45%~~3.87%. ~~As of September 30, 2017, the Company had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility.~~ 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 Eagle Ford 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, ~~2017,~~2018, the Company entered into ~~a ninth amendment to~~ the credit agreement governing the revolving credit facility to, among other things (i) extend the maturity date of the revolving credit facility to May 4, 2022, subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced or redeemed on or prior to such time, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, (iii) increase the borrowing base from $600.0 million to $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof, (iv) replace the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio covenant that requires such ratio not to exceed 4.00 to 1.00, (v) remove the covenant requiring a minimum EBITDA to Interest Expense ratio, (vi) reduce the commitment fee from 0.50% to 0.375% when utilization of lender commitments is less than 50% of the borrowing base amount, (vii) remove the restriction from borrowing under the credit facility if the Company has or, after giving effect to the borrowing, will have a Consolidated Cash Balance in excess of $50.0 million, (viii) remove the mandatory repayment of borrowings to the extent the Consolidated Cash Balance exceeds $50.0 million if either (a) the Company’s ratio of Total Debt to EBITDA exceeds 3.50 to 1.00 or (b) the availability under the credit facility is equal to or less than 20% of the then effective borrowing base, (ix) permit the

issuance of unlimited Senior Unsecured Debt, subject to certain conditions, including pro forma compliance with the Company’s financial covenants, and (x) increase certain covenant baskets and thresholds.

~~On June 28, 2017, the Company entered into a tenth~~twelfth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) ~~amend~~establish the ~~calculation~~borrowing base at $1.0 billion, with an elected commitment amount of ~~certain financial covenants~~$900.0 million, until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from 2.00%-3.00% to ~~provide that EBITDA will be calculated~~1.50%-2.50% and base rate loans from 1.00%-2.00% to 0.50%-1.50%, each depending on ~~an annualized basis as~~level of the end of each of the first three fiscal quarters commencing with the quarter ending September 30, 2017, (ii) amend the restricted payments covenant to, among other things, provide for additional capacity to pay dividends with respect to, and make redemptions of, the Company’s equity interests, including the ability, subject to certain conditions, to pay dividends on or make redemptions of the Preferred Stock using proceeds of certain equity issuances or in an amount equal to the proceeds of certain divestitures,facility usage, (iii) amend the ~~definition~~covenant limiting payment of ~~“Disqualified Capital Stock”~~dividends and distributions on equity to ~~provide, among other things, that~~increase the ~~Preferred Stock does not constitute “Disqualified Capital Stock” for purposes of the revolving credit facility,~~Company’s ability to make dividends and distributions on its equity interests and (iv) provide that any of the Contingent ExL Payment does not constitute Debt (as defined in the revolving credit facility) for purposes of the revolving credit facility until such time as the amount of such obligation is determined, and (v) amend certain other ~~covenants,~~provisions, in each case as set forth therein. ~~See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.~~

Upon issuance of the 8.25% Senior Notes (described below), in accordance with the credit agreement governing the revolving credit facility, the Company’s borrowing base was reduced by 25% of the aggregate principal amount of the 8.25% Senior Notes, reducing the Company’s borrowing base from $900.0 million to $837.5 million.

On ~~November 3, 2017,~~October 29, 2018, the Company entered into ~~an eleventh~~the thirteenth amendment to its credit agreement governing the revolving credit facility. See “Note 14. Subsequent Events” for further details of the ~~eleventh~~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~~“Interest expense, ~~net~~net” in the consolidated statements of ~~operations.~~income.


Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Ratio of Outstanding Borrowings to Lender Commitments				Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	1.00%	2.00%	0.375%	0.50%	1.50%	0.375%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%	0.75%	1.75%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%	1.00%	2.00%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%	1.25%	2.25%	0.500%
Greater than or equal to 90%	2.00%	3.00%	0.500%	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 ~~discounts,~~ premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA ~~is calculated on an annualized basis as of the end of each of the first three fiscal quarters commencing with the fiscal quarter ending September 30, 2017, and thereafter~~ will be calculated based on the last four fiscal ~~quarter periods, in each case~~quarters after giving pro forma effect to EBITDA for material acquisitions and ~~dispositions~~divestitures of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of September 30, ~~2017,~~2018, the ratio of Total Debt to EBITDA was ~~3.09~~1.95 to 1.00 and the Current Ratio was ~~2.20~~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

~~8.25%~~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 and accrued and unpaid interest of $10.9 million. The redemptions were funded primarily from the net proceeds received from the divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of these divestitures. As a result of the redemptions, the Company recorded a loss on extinguishment of debt of $8.7 million, which included the redemption premiums of $6.0 million and the write-off of associated unamortized premiums and debt issuance costs of $2.7 million.

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 ~~2025~~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 aggregate principal amount of 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. The Company used the ~~net~~ proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to fund a portion of ~~the purchase price for~~ 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.

If a Change of Control (as defined in the indentures governing the 8.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest.

The indentures governing the 8.25% Senior Notes contain covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments. At September 30, 2017, the 8.25% Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility.

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 ~~June 28,~~August 10, 2017, the Company ~~entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP~~closed on the issuance and ~~its affiliates (the “GSO Funds”) to issue and sell~~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. The Company paid the~~Stock, to certain funds managed or sub-advised by GSO ~~Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement.~~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 ~~net~~ proceeds of approximately $236.4 million, net of issuance costs, to fund a portion of the ~~purchase price for the~~ ExL Acquisition and for general corporate purposes. The Company also entered into a registration rights agreement with the GSO Funds at the closing of the private placement, which provided certain registration and other rights for the benefit of the GSO Funds. During the fourth quarter of 2017, the Company filed a registration statement with the SEC to register the Preferred Stock. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.

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

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

The Preferred Stock outstanding is not mandatorily redeemable, but can be redeemed at the Company’s option and, in certain circumstances, at the option of the holders of the Preferred Stock. On or prior to August 10, 2018, the Company ~~may~~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 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~~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 ~~does not qualify as a liability instrument under ASC 480 - Distinguishing Liabilities from Equity, as the Preferred Stock~~ is not mandatorily redeemable. As the Preferred Stock does not qualify as a liability instrument, the Company next evaluated whether the Preferred Stock should be presented in shareholders' equity or temporary equity, between liabilities and shareholders' equity on its consolidated balance sheets. As the number of common shares that could be required to be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock. As such, the Preferred Stock must be presented as temporary ~~equity. The Company will reassess presentation of the Preferred Stock on its consolidated balance sheets on a quarterly basis.~~

The Warrants became exercisable upon issuance and qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. The Warrants meet the applicable criteria for equity ~~classification and are reflected in additional paid in capital~~ in the consolidated balance ~~sheets.~~

~~Net proceeds were allocated between the Preferred Stock and the Warrants based on their relative fair values at~~sheets with the issuance date ~~with $213.4 million allocated~~fair value accreted to the initial liquidation preference using the effective interest method.

The table below presents the reconciliation of changes in the carrying amount of Preferred Stock ~~and $23.0 million allocated to~~for the Warrants. The fair value of the Preferred Stock was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation of the Preferred Stock included the per share cash purchase price, redemption premiums, and liquidation preference, all as discussed

above, as well as redemption assumptions provided by the Company. The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:nine months ended September 30, 2018:



	~~Issuance Date Fair Value Assumptions~~Carrying Amount of Preferred Stock
~~Exercise price~~	~~$16.08~~(In thousands)
~~Expected term (in years)~~December 31, 2017	~~10.0~~	$214,262
~~Expected volatility~~Redemption of Preferred Stock	~~62.9~~(42,897		%)
~~Risk-free interest rate~~Accretion on Preferred Stock	~~2.2~~2,264		%
~~Dividend yield~~September 30, 2018	—	%$173,629

~~See “Note 11. Fair Value Measurements” for further discussion~~Loss on Redemption of Preferred Stock

During the first quarter of 2018, the Company redeemed 50,000 shares of Preferred Stock, representing 20% of the ~~significant inputs used in the~~issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million redemption price and ~~Warrants fair value calculations.~~

~~Preferred Stock Dividends~~$0.5 million accrued and ~~Accretion~~

Inunpaid dividends. The Company recognized a $7.1 million loss on the ~~third quarter of 2017, the Company declared and paid $2.2 million of dividends, in cash,~~redemption due to the ~~holders~~excess of ~~record~~the $50.0 million redemption price over the $42.9 million redemption date carrying value of the Preferred ~~Stock on September 1, 2017 for the period from issuance through September 15, 2017.~~

The Preferred Stock will be subject to accretion from its relative fair value at the issuance date of $213.4 million to a redemption value of $250.0 million over an approximate seven year term using the effective interest method.

Both the dividends and the accretion are presented on the statements of operations as reductions to net income, or increases to net loss, to compute net income (loss) attributable to common shareholders.Stock.

9. Shareholders’ Equity and Stock-Based Compensation

~~Increase in Authorized~~Sales of Common ~~Shares~~Stock

AtOn August 17, 2018, the ~~Company’s annual meeting~~Company completed a public offering of ~~shareholders on May 16, 2017, shareholders approved the proposal to amend the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized~~9.5 million shares of its common stock ~~from 90,000,000~~at a price per share of $22.55. The Company used the proceeds of $213.9 million, net of offering costs, to ~~180,000,000.~~

~~Sale~~fund the Devon Acquisition and for general corporate purposes. Pending the closing of ~~Common Stock~~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 ~~net~~ proceeds of $222.4 million, net of offering costs, to fund a portion ~~of the purchase price~~ 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

~~At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved~~The Company grants equity-based incentive awards under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”)~~, which~~ 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”)~~. From~~ and, from the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive ~~Plan, however,~~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 may grant restricted stock awards and units, stock appreciation rights that can be settled in cash or shares of common stock, performance shares, and stock options to employees, independent contractors, and non-employee directors. Under the Cash SAR Plan, the Company may grant stock appreciation rights that may only be settled in cash 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 and unit and 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 granted under the 2017 Incentive Plan counts as 1.00 share against the Maximum Share Limit. Stock appreciation rights to be settled in cash granted under the 2017 Incentive Plan and stock appreciation 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 and has no outstanding stock options. As of September 30, ~~2017,~~2018, there were ~~1,750,275~~296,654 shares of common ~~shares remaining~~stock available for grant under the 2017 Incentive Plan. The issuance of a restricted stock award, restricted stock unit, or performance share counts as 1.35 shares while the issuance of a stock option or stock-settled stock appreciation right counts as 1.00 share against the number of common shares available for grant under the 2017 Incentive Plan. As of September 30, 2017, the Company does not have any outstanding stock options and all outstanding stock appreciation rights will be settled solely in cash.

Restricted Stock Awards and ~~Units.~~ UnitsRestricted stock awards can be granted to employees and independent contractors and restricted stock units can be granted to employees, independent contractors, and non-employee directors. As of September 30, 2017, unrecognized compensation costs related to unvested restricted stock awards and units was $26.3 million and will be recognized over a weighted average period of 2.1 years.

The table below summarizes restricted stock award and unit activity for the nine months ended September 30, ~~2017:~~2018:

Restricted Stock Awards and Units
Weighted Average Grant Date
Fair Value
For the Nine Months Ended September 30, 2017
Unvested restricted stock awards and units, beginning of period 1,111,710

$36.93
Granted 1,020,465

$25.63
Vested (629,397 )
$39.58
Forfeited (12,922 )
$29.11
Unvested restricted stock awards and units, end of period 1,489,856

$28.14

During the first quarter of 2017, the Company granted 695,658 restricted stock units to employees and independent contractors with a grant date fair value of $18.8 million as part of its annual grant of long-term equity incentive awards. All of these restricted stock units contain a service condition, and certain of these restricted stock units also contain a performance condition. The performance condition has been met. In addition, the Company granted 44,465 restricted stock units to certain employees and independent contractors with a grant date fair value of $1.2 million in lieu of a portion of their annual incentive bonus otherwise payable to them in cash under the Company’s performance-based annual incentive bonus program.~~These restricted stock units vested substantially concurrent with the time of grant.~~



	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
Granted	1,391,422			$15.07
Vested	(615,762	)		$31.44
Forfeited	(23,880	)		$18.51
Unvested restricted stock awards and units, end of period	2,234,435			$19.14

During the second quarter of 2017, the Company granted 206,548 restricted stock awards and units to employees and non-employee directors with a grant date fair value of $5.0 million, all of which contain a service condition.

~~Stock Appreciation Rights (“SARs”).~~ SARs can be granted to employees and independent contractors under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”) or the 2017 Incentive Plan. SARs granted under the 2017 Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. All outstanding SARs will be settled solely in cash. The grant date fair value of SARs is calculated using the Black-Scholes-Merton option pricing model. The liability for SARs as of September 30, 2017 was $2.3 million, all of which was classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2016, the liability for SARs was $11.5 million, of which $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $1.3 million as of September 30, 2017, and will be recognized over a weighted average period of 1.3 years.

~~The table below summarizes the activity for SARs for~~ the nine months ended September 30, ~~2017:~~

Stock Appreciation Rights
Weighted
Average
Exercise
Prices

Weighted Average Remaining Life
(In years)

Aggregate Intrinsic Value
(In millions)

Aggregate Intrinsic Value of Exercises
(In millions)
For the Nine Months Ended September 30, 2017
Outstanding, beginning of period 722,638

$23.69

Granted 342,440

$26.94

Exercised (219,279 )
$17.28

$2.1
Forfeited —

$—

Expired (131,561 )
$24.19

Outstanding, end of period 714,238

$27.12
4.0
$—

Vested, end of period 185,899

$27.30

Vested and exercisable, end of period —

$27.30
3.5
$—

~~During the first quarter of 2017,~~2018, the Company granted ~~342,440 SARs under the Cash SAR Plan with a grant date fair value~~1,391,422 restricted stock awards and units primarily consisting of ~~$12.00 per SAR, or $4.1 million,~~1,343,412 restricted stock units to ~~certain~~ 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 vest ratably over an approximate three-year period. 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 September 30, 2018, unrecognized compensation costs related to unvested restricted stock awards and units were $26.8 million and will be recognized over a weighted average period of 2.0 years.

Cash SARs

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



	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
Granted	616,686		$14.67
Exercised	—		$—					$—
Forfeited	—		$—
Expired	—		$—
Outstanding, end of period	1,330,924		$21.35	4.6		$6.5
Vested, end of period	543,018		$27.18
Vested and exercisable, end of period	—		$27.18	2.8		$—

During the nine months ended September 30, 2018, the Company granted 616,686 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. ~~All of these~~These Cash SARs ~~contain a service condition~~vest ratably over an approximate three-year period and ~~performance condition. The performance condition has been met.~~expire approximately seven years from the grant date.

The grant date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model, was $4.9 million. The following table summarizes the assumptions used to calculate the grant date fair value of the Cash SARs granted during the nine months ended September 30, ~~2017:~~2018:



	Grant Date Fair Value Assumptions
Expected term (in years)	~~4.24~~6.0
Expected volatility	54.3	%
Risk-free interest rate	~~1.8~~2.8	%
Dividend yield	—	%

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 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 Cash SARs were $8.7 million as of September 30, 2018, and will be recognized over a weighted average period of 2.4 years.

Performance ~~Shares.~~Shares

The table below summarizes performance share activity for the nine months ended 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 nine months ended September 30, 2018, the Company ~~can grant~~granted 93,771 target performance shares to certain employees and independent contractors, ~~where each~~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. The~~stock, however, the number of performance shares that ~~will~~ vest ~~is based on~~ 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~~three-year performance period, the last day of which is also the vesting date.

During the first quarter of 2018, 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 shares that did not vest.

The grant date fair value of the performance ~~awards is~~shares, calculated using a Monte Carlo ~~simulation. As of September 30, 2017, unrecognized compensation costs related to unvested performance shares~~simulation, was ~~$2.7 million and will be recognized over a weighted average period of 1.8 years.~~

~~The table below summarizes performance share activity for the nine months ended September 30, 2017:~~

Target Performance Shares ⁽¹⁾

Weighted Average Grant Date
Fair Value
For the Nine Months Ended September 30, 2017
Unvested performance shares, beginning of period 154,510

$58.44
Granted 46,787

$35.14
Vested (56,342 )
$68.15
Forfeited —

$—
Unvested performance shares, end of period 144,955

$47.14


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

During the first quarter of 2017, the Company granted 46,787 target performance shares to certain employees and independent contractors with a grant date fair value of $35.14 per performance share, or $1.6 million, as part of its annual grant of long-term equity incentive awards. In addition to the market condition described above, the performance shares also contain a service condition and performance condition. The performance condition has been met. In addition, the Company issued 92,200 shares of common stock for 56,342 target performance shares that vested during the first quarter of 2017 with a multiplier of 164% based on the Company’s final TSR ranking during the performance period.

$1.8 million. The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the nine months ended September 30, ~~2017:~~2018:



	Grant Date Fair Value Assumptions
Number of simulations	500,000
Expected term (in years)	~~2.98~~3.0
Expected volatility	~~59.2~~61.5	%
Risk-free interest rate	~~1.5~~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.~~Net

Stock-based compensation expense associated with restricted stock awards and units, ~~stock appreciation rights to be settled in cash~~Cash SARs and performance shares, net of amounts capitalized, is ~~reflected as general~~included in “General and administrative, ~~expense~~net” in the consolidated statements of ~~operations, net of amounts capitalized to oil and gas properties.~~income.

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(In thousands)												(In thousands)
Restricted stock awards and units		$5,311			$5,487			$16,184			$23,079			$4,487			$5,311			$14,291			$16,184
Stock appreciation rights	429			3,361			(7,040		)	9,581
Cash SARs													(868		)	429			3,505			(7,040		)
Performance shares	581			722			1,861			2,052			411			581			1,374			1,861
	6,321			9,570			11,005			34,712			4,030			6,321			19,170			11,005
Less: amounts capitalized to oil and gas properties	(1,455		)	(1,150		)	(2,543		)	(3,878		)	(968		)	(1,455		)	(5,384		)	(2,543		)
Total stock-based compensation expense, net		$4,866			$8,420			$8,462			$30,834			$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 ~~crude oil and natural gas~~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 ~~drilling and completion capital expenditure program.~~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 ~~fixed~~over-the-counter price ~~swaps, basis~~ swaps, three-way collars, ~~and purchased and~~ sold call options and basis swaps, each of which ~~are~~is described below.

~~Fixed~~ 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 ~~a variable market price~~the difference to the ~~counterparties over specified periods for contracted volumes.~~counterparty.

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

~~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 market 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 market price, respectively.~~price. If the ~~market~~settlement price of the referenced index is below the ~~fixed~~ sub-floor price, the Company receives the ~~market~~difference between the floor price ~~plus~~and sub-floor price from the counterparty. If the settlement price of the referenced index is between the floor price and sub-floor price, the Company receives the difference between the ~~fixed~~ floor price and the ~~fixed sub-floor price.~~settlement price of the referenced index from the counterparty. If the ~~market~~settlement price of the referenced index 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.~~

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

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

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

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

~~basis. When~~As of September 30, 2018, the Company ~~has entered into three-way collars which span multiple years,~~had the ~~Company has elected to defer payment of certain of the premiums until the final year's contracts settle on a monthly basis.~~

~~The~~ following ~~tables set forth a summary of the Company’s~~ outstanding commodity derivative ~~positions~~instruments at weighted average contract ~~prices as of September 30, 2017:~~

~~Crude Oil Fixed Price Swaps~~volumes and prices:

Period Volumes (in Bbls/d) NYMEX Price ($/Bbl)
Q4 2017 15,000

$53.44
FY 2018 6,000

$49.55

~~Crude Oil Basis Swaps~~



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

Period Volumes (in Bbls/d) LLS-NYMEX Price Differential ($/Bbl)
December 2017 15,000

$4.13
FY 2018 6,000

$2.91

~~Crude Oil Three-Way Collars~~



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	—	—	—	—

NYMEX Prices
Period
Volumes
(in Bbls/d)

Sub-Floor Price
($/Bbl)

Floor Price
($/Bbl)

Ceiling Price
($/Bbl)
FY 2018 18,000

$39.17

$49.08

$60.48
FY 2019 6,000

$40.00

$47.80

$61.45

~~Crude Oil Net Sold Call Options~~

Period Volumes (in Bbls/d) NYMEX Ceiling Price ($/Bbl)
FY 2018 3,388

$71.33
FY 2019 3,875

$73.66
FY 2020 4,575

$75.98

~~Natural Gas Fixed Price Swaps~~

Period Volumes (in MMBtu/d) NYMEX Price ($/MMBtu)
Q4 2017 20,000

$3.30

~~Natural Gas Sold Call Options~~

Period Volumes (in MMBtu/d) NYMEX Ceiling Price ($/MMBtu)
Q4 2017 33,000

$3.00
FY 2018 33,000

$3.25
FY 2019 33,000

$3.25
FY 2020 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 ~~fair value~~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 ~~its counterparties~~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 ~~contracts~~instruments to be novated to a ~~lender~~Lender Counterparty if the Company’s net liability position exceeds the Company’s unsecured credit limit with ~~that counterparty~~the Non-Lender Counterparty and therefore do not require the posting of cash collateral.

Because ~~the counterparties have~~each Lender Counterparty has an investment grade credit ~~ratings, or~~rating and the Company has obtained ~~guarantees~~a guaranty from ~~the applicable counterparty’s~~each Non-Lender Counterparty’s parent company which has an investment grade ~~parent company,~~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 ~~and~~to minimize its ~~counterparty’s parent company, as applicable.~~

credit exposure to any individual counterparty.

Contingent Consideration Arrangements

The ~~Company has entered into~~purchase and sale agreements containing contingent consideration that are, or will be, required to be bifurcated and accounted for separately as derivative instruments. The Company records the contingent consideration on its consolidated balance sheets measured at fair value with gains and losses as a result of changes in the fair value of the contingent consideration recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The cash flows resulting from payments due from the Company for settlement of contingent consideration, which will occur in January 2019 at the earliest, are classified as cash flows from financing activities for the portion of the payment up to the acquisition date fair value with any amounts paid in excess classified as cash flows from operating activities.

~~As part~~ of the ExL Acquisition and divestitures of the Company’s assets in the Niobrara, Marcellus and Utica, included contingent consideration arrangements that entitle the Company ~~agreed~~ to receive or require the ~~Contingent ExL Payment that will require payment of $50.0 million per year for each of the years of 2018 through 2021, with a cap of $125.0 million,~~Company to pay specified amounts if the EIA WTI average price is greater than $50.00 per barrel for the respective year. The Company determined that the Contingent ExL Payment was not clearly and closely related to the purchase and sale agreement for the ExL Properties, and therefore bifurcated this embedded feature and recorded this derivative at its acquisition date fair value of $52.3 millioncommodity prices exceed specified thresholds, which are summarized in the ~~consolidated financial statements. As~~table below. See “Note 3. Acquisitions and Divestitures of ~~September 30, 2017, the estimated fair value~~Oil and Gas Properties” for details of ~~the Contingent ExL Payment was $60.3 million~~these acquisitions and ~~was classified as non-current “Derivative liabilities” in the consolidated balance sheets.~~divestitures.



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

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

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

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

(1)

The price used to determine whether the specified threshold for each year has been met for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration 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 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.

Derivative Assets and Liabilities

~~All~~Commodity derivative instruments and contingent consideration arrangements are recorded onin the ~~Company’s~~ 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.

The ~~combined~~ derivative instrument asset and liability fair ~~value assets and liabilities, including deferred premium obligations,~~values recorded in the ~~Company’s~~ consolidated balance sheets as of September 30, ~~2017~~2018 and December 31, ~~2016~~2017 are summarized below:


	September 30, 2017									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		$11,571			($8,757	)		$2,814			$19,408			($18,985	)		$423
Deferred premium obligations	—			(879		)	(879		)
Other current assets		$11,571			($9,636	)		$1,935
Contingent Niobrara Consideration										4,920			—			4,920
Contingent Utica Consideration										4,915			—			4,915
Derivative assets											$29,243			($18,985	)		$10,258
Commodity derivative instruments	10,415			(9,867		)	548			12,028			(12,028		)	—
Deferred premium obligations	—			(423		)	(423		)
Other assets-non current		$10,415			($10,290	)		$125
Contingent Niobrara Consideration										6,755			—			6,755
Contingent Marcellus Consideration										1,315			—			1,315
Contingent Utica Consideration										7,300			—			7,300
Other assets											$27,398			($12,028	)		$15,370

Commodity derivative instruments		($9,143	)		$8,757			($386	)		($123,611	)		$9,876			($113,735	)
Deferred premium obligations	(7,271		)	879			(6,392		)	(9,109		)	9,109			—
Contingent ExL Consideration										(49,160		)	—			(49,160		)
Derivative liabilities-current		($16,414	)		$9,636			($6,778	)		($181,880	)		$18,985			($162,895	)
Commodity derivative instruments	(13,711		)	9,867			(3,844		)	(45,532		)	6,314			(39,218		)
Deferred premium obligations	(13,463		)	423			(13,040		)	(5,714		)	5,714			—
Contingent ExL Payment	(60,300		)	—			(60,300		)
Contingent ExL Consideration										(62,885		)	—			(62,885		)
Derivative liabilities-non current		($87,474	)		$10,290			($77,184	)		($114,131	)		$12,028			($102,103	)


	December 31, 2016									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		$7,990			($6,753	)		$1,237			$4,869			($4,869	)		$—
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Derivative assets											$4,869			($4,869	)		$—
Commodity derivative instruments	3,882			(3,882		)	—			9,505			(9,505		)	—
Deferred premium obligations	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Contingent Marcellus Consideration										2,205			—			2,205
Contingent Utica Consideration										7,985			—			7,985
Other assets											$19,695			($9,505	)		$10,190

Commodity derivative instruments		($27,346	)		$6,753			($20,593	)		($52,671	)		($4,450	)		($57,121	)
Deferred premium obligations	(2,008		)	—			(2,008		)	(9,319		)	9,319			—
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)	(24,609		)	(2,098		)	(26,707		)
Deferred premium obligations	(2,569		)	—			(2,569		)	(11,603		)	11,603			—
Contingent ExL Payment	—			—			—
Contingent ExL Consideration										(85,625		)	—			(85,625		)
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)		($121,837	)		$9,505			($112,332	)

See “Note 11. Fair Value Measurements” for additional ~~details~~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, ~~and~~as well as its contingent consideration arrangements, are recognized as ~~(gain)~~“(Gain) loss on derivatives, ~~net~~net” in the ~~Company’s~~ consolidated statements of ~~operations~~income in the period in which the changes occur. ~~All deferred~~Deferred premium obligations associated with the Company’s commodity

derivative instruments are recognized ~~in (gain)~~as “(Gain) loss on derivatives, ~~net~~net” in the ~~Company’s~~ consolidated statements of ~~operations~~income in the period in which the deferred premium obligations are incurred. The ~~effect of derivative instruments and deferred premium obligations~~net (gain) loss on derivatives in the ~~Company’s~~ consolidated statements of ~~operations~~income for the three and nine months ended September 30, 2018 and 2017 ~~and 2016 is~~are summarized below:


	Three Months Ended September 30,						Nine Months Ended September 30,					Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016		2018			2017			2018			2017
	(In thousands)											(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$8,409			($8,309	)		($39,754	)		$12,006		$43,664			$8,409			$126,612			($39,754	)
NGL												5,086			—			9,885			—
Natural gas	(2,183		)	(3,490		)	(12,902		)	12,167		(192		)	(2,183		)	(3,084		)	(12,902		)
Deferred premium obligations incurred	10,151			55			17,652			5,765
Contingent ExL Payment	8,000			—			8,000			—
Total (Gain) Loss on Derivatives, Net		$24,377			($11,744	)		($27,004	)		$29,938
Deferred premium obligations												—			10,151			—			17,652
Contingent ExL Consideration												9,990			8,000			26,420			8,000
Contingent Niobrara Consideration												(1,705		)	—			(3,795		)	—
Contingent Marcellus Consideration												215			—			890			—
Contingent Utica Consideration												(1,670		)	—			(4,230		)	—
(Gain) Loss on Derivatives, Net													$55,388			$24,377			$152,698			($27,004	)

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements ~~under these contracts,~~of commodity derivative instruments, including deferred premium obligations, ~~paid,~~and contingent consideration arrangements result in ~~payments to~~cash received or ~~receipts from the counterparty~~paid during the period and are ~~presented~~recognized as “Cash received (paid) for derivative settlements, net” in the consolidated statements of cash flows. Cash 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 nine months ended September 30, 2018 and 2017, there were no settlements of contingent consideration arrangements. The net cash received (paid) for derivative settlements ~~net~~ in the ~~Company’s consolidated statements of cash flows. The effect of commodity derivative instruments and deferred premium obligations on the Company’s~~ consolidated statements of cash flows for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 are summarized below:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(In thousands)
Cash Flows from Operating Activities													(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$6,500			$23,165			$9,941			$104,549			($21,261	)		$6,500			($54,594	)		$9,941
NGL													(2,641		)	—			(3,829		)	—
Natural gas	522			—			(731		)	—			245			522			785			(731		)
Deferred premium obligations paid	(566		)	(2,808		)	(1,496		)	(5,729		)
Total Cash Received (Paid) for Derivative Settlements, Net		$6,456			$20,357			$7,714			$98,820
Deferred premium obligations													(2,605		)	(566		)	(7,072		)	(1,496		)
Cash Received (Paid) for Derivative Settlements, Net														($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 derivative instrument assets and liabilities measured at fair value on a recurring basis as of September 30, ~~2017~~2018 and December 31, ~~2016:~~2017:

September 30, 2017
Level 1 Level 2 Level 3
(In thousands)
Derivative instrument assets
$—

$3,362

$—
Derivative instrument liabilities
$—

($4,230 )
($60,300 )



	September 30, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$423			$—
Contingent Niobrara Consideration	—		—			11,675
Contingent Marcellus Consideration	—		—			1,315
Contingent Utica Consideration	—		—			12,215

Liabilities
Commodity derivative instruments		$—		($152,953	)		$—
Contingent ExL Consideration	—		—			(112,045		)



	December 31, ~~2016~~2017
	Level 1		Level 2			Level 3
	(In thousands)
~~Derivative instrument assets~~Assets
Commodity derivative instruments		$—		$~~1,237~~—			$—
~~Derivative instrument liabilities~~Contingent Niobrara Consideration	—		—			—
Contingent Marcellus Consideration	—		—			2,205
Contingent Utica Consideration	—		—			7,985

Liabilities
Commodity derivative instruments		$—		($~~45,552~~83,828	)		$—
Contingent ExL Consideration	—		—			(85,625		)

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

Commodity derivative instruments. The ~~Company uses Level 2 inputs to measure the~~ fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model ~~using~~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.~~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 fair value derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the fair value derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company nets the fair values of its derivative assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the nine months ended September 30, ~~2017~~2018 and ~~2016.~~2017.

Contingent ~~consideration.~~consideration arrangements. The ~~Company determined that~~fair values of the Contingent ExL Payment associated with the ExL Acquisition is an embedded derivative and is not clearly and closely related to the purchase and sale agreement for the ExL Properties. As a result, the Company bifurcated this embedded feature and reflected the liability at fair value in the consolidated financial statements. The fair value wascontingent consideration arrangements were determined by a third-party valuation specialist using a Monte Carlo ~~simulation~~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, which include adjustments for the counterparties’ credit quality for contingent consideration assets and 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 ~~was~~arrangements were designated as Level 3 within the valuation hierarchy. The Company reviewed the ~~valuation,~~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 ~~value~~values of the ~~Contingent ExL Payment~~contingent consideration arrangements, which were designated as ~~of September 30, 2017 and August 10, 2017 was a liability of $60.3 million and $52.3 million, respectively. As a result,~~Level 3 within the Company recorded a loss on the change in fair value of $8.0 million, which was classified as “(Gain) loss on derivatives, net” in the consolidated statements of operations. The Company had no transfers into or out of Level 3valuation hierarchy, for the nine months ended September 30, ~~2017~~2018 and ~~2016.~~ 2017:



	Contingent Consideration Arrangements
	Assets		Liability
	(In thousands)
December 31, 2017		$10,190		($85,625	)
Recognition of divestiture date fair value	7,880		—
Gain (loss) on changes in fair value, net⁽¹⁾	7,135		(26,420		)
Transfers into (out of) Level 3	—		—
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)	Recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income.

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

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

The fair value measurements of ~~assets acquired and liabilities assumed, other than contingent consideration which is discussed above,~~asset retirement obligations are measured onas of the date a ~~nonrecurring basis on the acquisition date by a third-party valuation specialist~~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 ~~represent~~are designated as Level 3 ~~inputs. Significant inputs to~~within the valuation of acquired oil and gas properties include estimates of estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the assets acquired and liabilities assumed as of the acquisition dates for the ExL Acquisition and Sanchez Acquisition.

The fair value measurements of asset retirement obligations are measured on a nonrecurring basis when a well is drilled or acquired or when production equipment and facilities are installed or acquired using a discounted cash flow model based on inputs that are

~~not observable in the market and therefore represent Level 3 inputs.~~hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

The fair value measurements of ~~the Preferred Stock~~assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured ~~on a nonrecurring basis on~~as of the ~~issuance~~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 ~~represent~~designated as Level 3 inputs. Significant inputs to the valuation of ~~the Preferred Stock~~acquired oil and gas properties include ~~the per share cash purchase~~forward oil and gas price ~~redemption premiums, liquidation preference,~~curves, estimated volumes of oil and ~~redemption assumptions provided by the Company.~~

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 ~~8. Preferred Stock~~3. Acquisitions and ~~Warrants”~~Divestitures of Oil and Gas Properties” for details ~~regarding the allocation~~of assets acquired and liabilities assumed as of the ~~net proceeds based on~~acquisition date for the ~~relative fair values of the Preferred Stock and Warrants.~~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, which are classified as Level 1 under the fair value hierarchy.~~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, net of unamortized premiums and debt issuance costs with the fair values measured using ~~Level 1 inputs based on~~ quoted secondary market trading ~~prices.~~prices which are designated as Level 1 within the valuation hierarchy.


	September 30, 2017				December 31, 2016				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		$594,439		$610,500		$593,447		$624,750		$129,144		$130,000		$446,087		$459,518
6.25% Senior Notes due 2023	641,473		659,750		640,546		672,750		642,781		664,625		641,792		674,375
8.25% Senior Notes due 2025	245,502		269,375		—		—		245,927		268,750		245,605		274,375
Other long-term debt due 2028	4,425		4,408		4,425		4,419		—		—		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)


	September 30, 2017													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		$3,512,988			$89,589			$—		($3,499,850	)		$102,727		$3,114,698			$133,308			$—		($3,096,917	)		$151,089
Total property and equipment, net	39,789			2,592,458			5,057		(3,986		)	2,633,318		6,570			2,709,162			3,028		(3,833		)	2,714,927
Investment in subsidiaries	(1,097,703		)	—			—		1,097,703			—		(576,826		)	—			—		576,826			—
Other assets	9,526			155			—		—			9,681		29,611			15,371			—		—			44,982
Total Assets		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726		$2,574,053			$2,857,841			$3,028		($2,523,924	)		$2,910,998

Liabilities and Shareholders’ Equity
Current liabilities		$128,778			$3,687,474			$5,057		($3,502,870	)		$318,439		$305,096			$3,347,575			$3,028		($3,099,937	)		$555,762
Long-term liabilities	1,716,898			92,431			—		15,879			1,825,208		1,357,294			87,092			—		15,879			1,460,265
Preferred stock	213,400			—			—		—			213,400		173,629			—			—		—			173,629
Total shareholders’ equity	405,524			(1,097,703		)	—		1,080,858			388,679		738,034			(576,826		)	—		560,134			721,342
Total Liabilities and Shareholders’ Equity		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726		$2,574,053			$2,857,841			$3,028		($2,523,924	)		$2,910,998


	December 31, 2016													December 31, 2017
	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		$2,735,830			$63,513			$—		($2,726,355	)		$72,988		$3,441,633			$105,533			$—		($3,424,288	)		$122,878
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760		5,953			2,630,707			3,028		(3,878		)	2,635,810
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—		(999,793		)	—			—		999,793			—
Other assets	7,423			156			—		—			7,579		9,270			10,346			—		—			19,616
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959		$165,701			$3,631,401			$3,028		($3,427,308	)		$372,822
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910		1,689,466			114,978			—		15,879			1,820,323
Preferred stock	—			—			—		—			—		214,262			—			—		—			214,262
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458		387,634			(999,793		)	—		983,056			370,897
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF ~~OPERATIONS~~INCOME

(In thousands)

(Unaudited)


	Three Months Ended September 30, 2017													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		$35			$181,244		$—		$—			$181,279			$38			$303,337			$—		$—			$303,375
Total costs and expenses	54,061			119,366		—		29			173,456			85,242			135,920			—		(13		)	221,149
Income (loss) before income taxes	(54,026		)	61,878		—		(29		)	7,823			(85,204		)	167,417			—		13			82,226
Income tax benefit	—			—		—		—			—
Income tax expense														—			(880		)	—		—			(880		)
Equity in income of subsidiaries	61,878			—		—		(61,878		)	—			166,537			—			—		(166,537		)	—
Net income		$7,852			$61,878		$—		($61,907	)		$7,823			$81,333			$166,537			$—		($166,524	)		$81,346
Dividends on preferred stock	(2,249		)	—		—		—			(2,249		)	(4,457		)	—			—		—			(4,457		)
Accretion on preferred stock														(771		)	—			—		—			(771		)
Loss on redemption of preferred stock														—			—			—		—			—
Net income attributable to common shareholders		$5,603			$61,878		$—		($61,907	)		$5,574			$76,105			$166,537			$—		($166,524	)		$76,118

Three Months Ended September 30, 2016

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$105

$111,072

$—

$—

$111,177
Total costs and expenses 28,551
184,047
—
66
212,664
Loss before income taxes (28,446 ) (72,975 ) —
(66 ) (101,487 )
Income tax benefit —
—
—
313
313
Equity in loss of subsidiaries (72,975 ) —
—
72,975
—
Net loss
($101,421 )
($72,975 )
$—

$73,222

($101,174 )
Dividends on preferred stock —
—
—
—
—
Net loss attributable to common shareholders
($101,421 )
($72,975 )
$—

$73,222

($101,174 )



	Three Months Ended September 30, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$35			$181,244		$—		$—			$181,279
Total costs and expenses	54,061			119,366		—		29			173,456
Income (loss) before income taxes	(54,026		)	61,878		—		(29		)	7,823
Income tax expense	—			—		—		—			—
Equity in income of subsidiaries	61,878			—		—		(61,878		)	—
Net income		$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		$5,603			$61,878		$—		($61,907	)		$5,574

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF ~~OPERATIONS~~INCOME

(In thousands)

(Unaudited)


	Nine Months Ended September 30, 2017													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		$291			$498,826		$—		$—			$499,117			$77			$792,551			$—		$—			$792,628
Total costs and expenses	80,660			314,237		—		70			394,967			278,942			367,902			—		(45		)	646,799
Income (loss) before income taxes	(80,369		)	184,589		—		(70		)	104,150			(278,865		)	424,649			—		45			145,829
Income tax benefit	—			—		—		—			—
Income tax expense														—			(1,682		)	—		—			(1,682		)
Equity in income of subsidiaries	184,589			—		—		(184,589		)	—			422,967			—			—		(422,967		)	—
Net income		$104,220			$184,589		$—		($184,659	)		$104,150			$144,102			$422,967			$—		($422,922	)		$144,147
Dividends on preferred stock	(2,249		)	—		—		—			(2,249		)	(13,794		)	—			—		—			(13,794		)
Accretion on preferred stock														(2,264		)	—			—		—			(2,264		)
Loss on redemption of preferred stock														(7,133		)	—			—		—			(7,133		)
Net income attributable to common shareholders		$101,971			$184,589		$—		($184,659	)		$101,901			$120,911			$422,967			$—		($422,922	)		$120,956

Nine Months Ended September 30, 2016

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$349

$299,414

$—

$—

$299,763
Total costs and expenses 151,445
822,582
—
431
974,458
Loss before income taxes (151,096 ) (523,168 ) —
(431 ) (674,695 )
Income tax benefit —
—
—
—
—
Equity in loss of subsidiaries (523,168 ) —
—
523,168
—
Net loss
($674,264 )
($523,168 )
$—

$522,737

($674,695 )
Dividends on preferred stock —
—
—
—
—
Net loss attributable to common shareholders
($674,264 )
($523,168 )
$—

$522,737

($674,695 )



	Nine Months Ended September 30, 2017
	Parent Company			Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$291			$498,826		$—		$—			$499,117
Total costs and expenses	80,660			314,237		—		70			394,967
Income (loss) before income taxes	(80,369		)	184,589		—		(70		)	104,150
Income tax expense	—			—		—		—			—
Equity in income of subsidiaries	184,589			—		—		(184,589		)	—
Net income		$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		$101,971			$184,589		$—		($184,659	)		$101,901

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30, 2017														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		($95,529	)		$376,126			$—		$—			$280,597			($218,926	)		$684,218			$—		$—			$465,292
Net cash used in investing activities	(728,833		)	(1,102,155		)	—		726,029			(1,104,959		)
Net cash provided by financing activities	825,260			726,029			—		(726,029		)	825,260
Net increase in cash and cash equivalents	898			—			—		—			898
Net cash provided by (used in) investing activities															375,265			(284,076		)	—		(400,142		)	(308,953		)
Net cash used in financing activities															(163,464		)	(400,142		)	—		400,142			(163,464		)
Net decrease in cash and cash equivalents															(7,125		)	—			—		—			(7,125		)
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194			9,540			—			—		—			9,540
Cash and cash equivalents, end of period		$5,092			$—			$—		$—			$5,092			$2,415			$—			$—		$—			$2,415


	Nine Months Ended September 30, 2016															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		($10,882	)		$208,729			$—			$—			$197,847			($95,529	)		$376,126			$—		$—			$280,597
Net cash used in investing activities	(122,846		)	(331,351		)	(740		)	123,362			(331,575		)	(728,833		)	(1,102,155		)	—		726,029			(1,104,959		)
Net cash provided by financing activities	94,045			122,622			740			(123,362		)	94,045			825,260			726,029			—		(726,029		)	825,260
Net decrease in cash and cash equivalents	(39,683		)	—			—			—			(39,683		)
Net increase in cash and cash equivalents																898			—			—		—			898
Cash and cash equivalents, beginning of period	42,918			—			—			—			42,918			4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$3,235			$—			$—			$—			$3,235			$5,092			$—			$—		$—			$5,092

13. Supplemental Cash Flow Information

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


	Nine Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2018			2017
	(In thousands)				(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$59,389		$55,808		$44,644			$59,389

Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		$98,829		$7,316
Contingent ExL Payment	52,300		—
Increase in capital expenditure payables and accruals						$61,893			$98,829
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	2,543		3,878		5,384			2,543
Asset retirement obligations capitalized to oil and gas properties	2,761		766		1,127			2,761

14. Subsequent Events

~~Potential Divestiture of Marcellus Assets~~

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, subject to customary purchase price adjustments. The transaction has an effective date of April 1, 2017 and is expected to close by the end of November 2017. On October 5, 2017, the buyer paid $6.3 million into escrow as a deposit.

The Company could also receive contingent consideration of $3.0 million per year if the average settlement prices of a 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. (the “CME HH average price”) is above $3.13, $3.18, and $3.30 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively. This conditional consideration will be zero for the respective year if such CME HH average price of a MMBtu of Henry Hub natural gas is at or below the per MMBtu amounts listed above for any of such years, and is capped at $7.5 million.

Simultaneous with the signing of the Marcellus Shale transaction discussed above, the Company’s existing joint venture partner in the Marcellus Shale, Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, entered into a purchase and sale agreement with BKV Chelsea, LLC to sell its interest in the same oil and gas properties. Simultaneous with the closing of these Marcellus Shale sale transactions, the agreements governing the Reliance joint venture will be assigned to the buyer and, after giving effect to such transactions, the Reliance joint venture will terminate except for limited post-closing obligations.

~~Hedging~~Commodity Derivative Instruments

In October ~~and November 2017,~~2018, the Company entered into the following ~~crude oil~~commodity derivative ~~positions~~instruments at weighted average contract volumes and prices:

~~Crude Oil Basis Swaps~~

Period Volumes (in Bbls/d) Midland-NYMEX Price Differential ($/Bbl)
FY 2018 6,000

($0.10 )



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	—		—		—		—

~~Crude Oil Three-Way Collars~~Redemption of 7.50% Senior Notes Due 2020

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.

NYMEX Prices
Period
Volumes
(in Bbls/d)

Sub-Floor Price
($/Bbl)

Floor Price
($/Bbl)

Ceiling Price
($/Bbl)
FY 2018 6,000

$40.00

$49.00

$59.13
FY 2019 6,000

$40.00

$49.00

$59.14
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.

~~Eleventh~~Thirteenth Amendment to the Credit Agreement

On ~~November 3, 2017,~~October 29, 2018, the Company entered into ~~an eleventh~~the thirteenth amendment to its credit agreement governing ~~the~~its revolving credit facility to, among other things, (i) establish the borrowing base at ~~$900.0 million,~~$1.3 billion, with an elected commitment amount of ~~$800.0 million,~~$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 ~~general basket available for restricted payments from $50.0 million~~ratio of Total Debt to ~~$75.0 million~~EBITDA exceeds 3.00 to 1.00, (iii) amend the definition of Capital Leases, and ~~(iii)~~(iv) amend certain other ~~provisions, in each case as set forth therein. The calculation of the borrowing base was supported solely by the reserves of the Company's Eagle Ford~~definitions and ~~Delaware Basin assets.~~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 ~~2016~~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

~~Operational Results~~Third Quarter 2018 Highlights

Total production for the three months ended September 30,~~2017~~ 2018 was ~~55,224~~64,627 Boe/d, an increase of ~~35%~~17% from the three months ended September 30, ~~2016,~~ 2017, primarily due to production from new wells in the Eagle Ford and Delaware Basin, partially offset by the divestitures in Utica and ~~the addition of production from the Sanchez Acquisition~~Marcellus in the fourth quarter of ~~2016~~2017 and ~~the ExL Acquisition~~Niobrara and Eagle Ford in the ~~third~~first quarter of ~~2017.~~2018, as well as normal production declines.

~~The following table summarizes our operated~~Operated drilling and completion activity for the three months ended September 30, ~~2017~~2018 along with our drilled but uncompleted and producing wells as of September 30, ~~2017.~~2018 are summarized in the table below.


	Three Months Ended September 30, 2017				September 30, 2017				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	24	19.8	19	17.7	32	27.2	512	448.7	32	31.3	25	24.3	20	19.4	516	463.1
Delaware Basin	5	3.8	3	2.4	7	5.6	26	21.8	7	5.3	10	8.7	7	5.6	57	47.2
Niobrara	—	—	—	—	—	—	130	57.7
Marcellus	—	—	—	—	11	4.3	81	26.0
Utica and other	—	—	—	—	—	—	4	3.1
Total	29	23.6	22	20.1	50	37.1	753	557.3	39	36.6	35	33.0	27	25.0	573	510.3

Drilling and completion expenditures for the third quarter of ~~2017~~2018 were ~~$165.0~~$241.1 million, of which ~~96%~~approximately 62% were in the Eagle Ford with the balance in the Delaware Basin. As a result of the relative outlook for crude oil prices in the Eagle Ford and Delaware ~~Basin.~~Basin, we elected to shift capital expenditures to the Eagle Ford in order to take advantage of the superior returns in the current environment. As of September 30, ~~2017,~~2018, we were operating ~~two~~six rigs, with four located in the Eagle Ford and ~~three rigs in the Delaware Basin. For the remainder of 2017, we expect to operate~~ two rigs in the Eagle Ford and four rigs, while bringing in a fifth rig temporarily, in the Delaware Basin. Our current 2017 drilling and completion capital expenditure plan increased to $600.0 million to $620.0 million as a result of updated plans in the Delaware Basin as a result of the ExL Acquisition, as well as an increase in non-operated activity on our acreagelocated in the Delaware Basin, and ~~Niobrara~~. ~~The primary focus for our remaining 2017 drilling and~~two completion ~~capital expenditures is on~~crews, both of which were in the ~~continued exploration and development~~Eagle Ford. For the remainder of ~~oil-focused plays, such as~~2018, we currently expect to continue operating an average of six rigs between the Eagle Ford and Delaware Basin, ~~where approximately 94%~~however, completion activity is expected to decline in the fourth quarter of ~~our remaining 2017~~2018 as we have planned for a frac holiday. Our current 2018 drilling, completion, and ~~completion~~infrastructure capital expenditure plan ~~is allocated.~~remains unchanged at $800.0 million to $825.0 million. See “—Liquidity and Capital Resources—~~2017~~2018 Drilling, Completion, and ~~Completion~~Infrastructure Capital Expenditure Plan and Funding Strategy” for additional details.

~~Financial Results~~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, as compared to a net loss attributable to common shareholders for the three months ended September 30, 2016 of $101.2 million, or $1.72 per diluted~~ share. The increase in net income attributable to common shareholders for the third quarter of ~~2017~~2018 as compared to the net ~~loss~~income attributable to common shareholders for the third quarter of ~~2016~~2017 was driven primarily by higher production volumes and commodity prices in the third quarter of ~~2017~~2018 compared to the third quarter of ~~2016 and no impairment~~2017, partially offset by a loss on derivatives, net of ~~proved oil and gas properties during~~$55.4 million in the third quarter of ~~2017~~2018 as compared to ~~the $105.1 million impairment of proved oil and gas properties recognized during the third quarter of 2016, partially offset by~~ a loss on derivatives, net of $24.4 million in the third quarter of 2017 ~~compared~~and an increase in

our depreciation, depletion and amortization (“DD&A”) expense of $12.5 million to ~~a gain on derivatives, net of $11.7~~$80.1 million infor the third quarter of ~~2016.~~2018 as compared to $67.6 million for the third quarter of 2017. See “—Results of Operations” below for further details.

~~ExL Acquisition~~Recent Developments

~~On June 28, 2017,~~In October 2018, we ~~entered into~~delivered a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) for a purchase pricenotice of ~~$648.0 million, subject to customary purchase price adjustments (the “ExL Acquisition”). The transaction had an effective date of May 1, 2017. We paid $75.0 million~~conditional redemption to the ~~seller as a deposit~~trustee for our 7.50% Senior Notes to call for redemption on ~~June 28, 2017 and $601.0 million upon closing on August 10, 2017, which included preliminary purchase price adjustments primarily~~

~~related to~~November 19, 2018, the net cash flows from the acquired wells and capital expenditures from the effective date to the closing date. Upon closing the ExL Acquisition, we became the operator of the ExL Properties with an approximate 70% average working interest.

We also agreed to a contingent payment of $50.0 million per year for each of the years of 2018 through 2021 with a cap of $125.0 million. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the contingent payment and “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details regarding our evaluation of the contingent payment as an embedded derivative.

We funded the ExL Acquisition with net proceeds from the issuance and sale of Preferred Stock on August 10, 2017, the net proceeds from the common stock offering completed on July 3, 2017, and the net proceeds from the senior notes offering completed on July 14, 2017. See below for further discussion of the Preferred Stock, the common stock offering, and the issuance of 8.25% Senior Notes.

~~Sale of Preferred Stock~~

On June 28, 2017, we entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”) to issue and sell in a private placement (i) $250.0 million (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 our 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. We paid the GSO Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement. The closing of the private placement occurred on August 10, 2017, contemporaneously with the closing of the ExL Acquisition. We used the net proceeds of approximately $236.4 million, net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. We also entered into a registration rights agreement with the GSO Funds at the closing of the private placement, pursuant to which we agreed to provide certain registration and other rights for the benefit of the GSO Funds. During the fourth quarter of 2017, we filed a registration statement with the SEC to register the Preferred Stock. See “Note 8. Preferred Stock” for further details regarding the Preferred Stock and Warrants.

~~Sale of Common Stock~~

On July 3, 2017, we completed a public offering of 15.6 million shares of our common stock at a price per share of $14.28. We used the net proceeds of $222.4 million, net of offering costs, to fund a portion of the purchase price of the ExL Acquisition and for general corporate purposes.

~~Issuance of Senior Notes~~

~~On July 14, 2017, we closed a public offering of $250.0~~remaining $130.0 million aggregate principal amount of ~~8.25%~~outstanding 7.50% Senior Notes ~~due 2025 (the “8.25% Senior Notes”). The 8.25% Senior Notes mature~~at a redemption price of 100% of par, plus accrued and unpaid interest. Our redemption obligation was conditioned on ~~July 15, 2025~~ and ~~have interest payable semi-annually each January 15 and July 15. We used the net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs,~~subject to ~~fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. See “Note 6. Long-Term Debt” for further details regarding the 8.25% Senior Notes.~~

~~Upon issuance of the 8.25% Senior Notes, in accordance with the credit agreement governing~~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 ~~borrowing base was reduced by 25%~~redemption obligation is no longer conditional. As a result of the ~~aggregate principal amount~~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 ~~8.25%~~7.50% Senior Notes, ~~reducing~~ the ~~borrowing base from $900.0 million~~May 4, 2022 maturity date of the credit agreement will no longer be subject to ~~$837.5 million. See “—Eleventh Amendment to the Credit Agreement” below for further discussion~~a springing maturity date of ~~our borrowing base.~~June 15, 2020.

~~Potential Divestitures~~

~~On August 31, 2017,~~In October 2018, we entered into ~~a purchase and sale agreement to sell substantially all of our assets in~~ the Utica Shale for an agreed upon price of $62.0 million. The transaction has an effective date of April 1, 2017 and is expected to close by the end of November 2017. We received $6.2 million from the buyer as a deposit on August 31, 2017. In addition, we could receive contingent consideration of $5.0 million per year for each of the years of 2018 through 2020 with a cap of $15.0 million. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of this transaction.

On October 5, 2017, we entered into a purchase and sale agreement to sell substantially all of our assets in the Marcellus Shale for an agreed upon price of $84.0 million, subject to customary purchase price adjustments. The transaction has an effective date of April 1, 2017 and is expected to close by the end of November 2017. In addition, we could receive contingent consideration of $3.0 million per year for each of the years of 2018 through 2020 with a cap of $7.5 million. See “Note 14. Subsequent Events” for further details of this transaction.

In addition, the process is ongoing to sell our assets in the Niobrara and we believe an agreement could be in place by the end of this year. We are also evaluating certain other of our non-core assets where we do not expect to allocate material capital expenditures over the next few years for potential divestiture. We believe that the divestitures described above are strategically

beneficial as they allow us to focus on two high quality plays in the Eagle Ford and Delaware Basin as well as enhance our future financial flexibility that would benefit us in light of the recent ExL Acquisition and related financings. There can be no assurance that we will complete any pending disposition, be able to sell our Niobrara assets, or divest any other assets in such time frame on acceptable terms or at all or receive any targeted aggregate gross proceeds.

~~Eleventh Amendment to the Credit Agreement~~

~~On November 3, 2017, we entered into an eleventh~~thirteenth amendment to our credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at ~~$900.0 million,~~$1.3 billion, with an elected commitment amount of ~~$800.0 million,~~$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 ~~general basket available for restricted payments from $50.0 million~~ratio of Total Debt to ~~$75.0 million~~EBITDA exceeds 3.00 to 1.00, (iii) amend the definition of Capital Leases, and ~~(iii)~~(iv) amend certain other ~~provisions, in each case as set forth therein. The calculation of the borrowing base was supported solely by the reserves of our Eagle Ford~~definitions and ~~Delaware Basin assets.~~provisions.

Results of Operations

Three Months Ended September 30, ~~2017~~2018, Compared to the Three Months Ended September 30, ~~2016~~2017

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended September 30, ~~2017~~2018 and ~~2016:~~2017:


	Three Months Ended September 30,				2017 Period Compared to 2016 Period					Three Months Ended September 30,				2018 Period Compared to 2017 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)		2018		2017		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,211		2,253		958			43	%	3,755		3,211		544			17	%
NGLs (MBbls)	623		435		188			43	%	1,055		623		432			69	%
Natural gas (MMcf)	7,476		6,372		1,104			17	%	6,815		7,476		(661		)	(9	%)
Total barrels of oil equivalent (MBoe)	5,080		3,750		1,330			35	%	5,946		5,080		866			17	%

Daily production volumes by product -
Crude oil (Bbls/d)	34,903		24,488		10,415			43	%	40,813		34,903		5,910			17	%
NGLs (Bbls/d)	6,777		4,730		2,047			43	%	11,469		6,777		4,692			69	%
Natural gas (Mcf/d)	81,265		69,262		12,003			17	%	74,072		81,265		(7,193		)	(9	%)
Total barrels of oil equivalent (Boe/d)	55,224		40,762		14,462			35	%	64,627		55,224		9,403			17	%

Daily production volumes by region (Boe/d) -
Eagle Ford	39,002		29,110		9,892			34	%	39,024		39,002		22			—	%
Delaware Basin	6,994		1,344		5,650			420	%	25,577		6,994		18,583			266	%
Niobrara	2,427		2,576		(149		)	(6	%)
Marcellus	6,120		6,811		(691		)	(10	%)
Utica and other	681		921		(240		)	(26	%)
Other										26		9,228		(9,202		)	(100	%)
Total barrels of oil equivalent (Boe/d)	55,224		40,762		14,462			35	%	64,627		55,224		9,403			17	%

Average realized prices -
Crude oil ($ per Bbl)		$47.37		$42.23		$5.14		12	%		$67.78		$47.37		$20.41		43	%
NGLs ($ per Bbl)	20.01		12.91		7.10			55	%	32.04		20.01		12.03			60	%
Natural gas ($ per Mcf)	2.24		1.63		0.61			37	%	2.21		2.24		(0.03		)	(1	%)
Total average realized price ($ per Boe)		$35.68		$29.65		$6.03		20	%		$51.02		$35.68		$15.34		43	%

Revenues (In thousands) -
Crude oil		$152,101		$95,154		$56,947		60	%		$254,525		$152,101		$102,424		67	%
NGLs	12,467		5,616		6,851			122	%	33,798		12,467		21,331			171	%
Natural gas	16,711		10,407		6,304			61	%	15,052		16,711		(1,659		)	(10	%)
Total revenues		$181,279		$111,177		$70,102		63	%		$303,375		$181,279		$122,096		67	%

Production volumes for the three months ended September 30, ~~2017~~2018 were ~~55,224~~64,627 Boe/d, an increase of ~~35%~~17% from ~~40,762~~55,224 Boe/d for the same period in ~~2016.~~2017. The increase is primarily due to production from new wells in the Delaware Basin, primarily drilled on properties from the ExL Acquisition, as well as in Eagle Ford, partially offset by the divestitures in Utica and ~~Delaware Basin and the addition of production from the Sanchez Acquisition~~Marcellus in the fourth quarter of ~~2016~~2017 and ~~the ExL Acquisition~~Niobrara and Eagle Ford in the

~~third~~ first quarter of ~~2017.~~2018. Revenues for the three months ended September 30, ~~2017~~2018 increased ~~63%~~67% to ~~$181.3~~$303.4 million compared to ~~$111.2~~$181.3 million for the same period in ~~2016~~2017 primarily due to ~~increased production~~higher crude oil prices and higher ~~commodity prices.~~crude oil production.

Lease operating expenses for the three months ended September 30, ~~2017~~2018 increased to $41.0 million ($6.90 per Boe) from $34.9 million ($6.86 ~~per Boe) from $24.3 million ($6.48~~ per Boe) for the same period in ~~2016.~~2017. The increase in lease operating expenses is primarily due to costs associated with increased production. The increase in lease operating expense per Boe is primarily due to ~~increased workover costs primarily on wells~~processing 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. 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 ~~Sanchez~~ExL Acquisition, ~~as well as to an~~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 ~~$7.7~~$14.5 million ~~(or 4.3%~~(4.8% of revenues) for the three months ended September 30, ~~2017~~2018 from ~~$4.9~~$7.7 million ~~(or 4.4%~~(4.3% of revenues) for the same period in ~~2016~~2017 primarily as a result of the increase in crude oil ~~NGL,~~ and ~~natural gas~~NGL revenues. The ~~decrease~~increase in production taxes as a percentage of revenues is primarily due to ~~a benefit~~the divestiture of substantially all of our assets in Marcellus in the ~~third~~fourth quarter of 2017, ~~of lower actual~~as our production ~~taxes than previously estimated~~ in ~~the Niobrara.~~Marcellus was not subject to production taxes.

Ad valorem taxes increased to ~~$1.7~~$2.6 million (0.9% of revenues) for the three months ended September 30, ~~2017~~2018 from ~~$1.4~~$1.7 million (1.0% of revenues) for the same period in ~~2016.~~2017. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and Delaware Basin and higher property tax valuations as a result of the increase in ~~2016 and new~~crude oil 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 ~~acquired~~are included in the ~~Sanchez Acquisition~~ad valorem tax assessment as wells drilled and producing during 2018 would not be included in ~~December 2016.~~ad valorem tax assessment until 2019.

~~Depreciation, depletion and amortization (“~~DD~~&A”)~~&A expense for the third quarter of ~~2017~~2018 increased ~~$18.6~~$12.5 million to ~~$67.6~~$80.1 million ($~~13.30~~13.47 per Boe) from the DD&A expense for the third quarter of ~~2016~~2017 of ~~$48.9~~$67.6 million ($~~13.05~~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 costs that occurred subsequent to the ~~addition to~~third quarter of 2017 as well as an increase in proved oil and gas properties ~~related to the ExL Acquisition,~~as a result of our ongoing capital expenditure program, partially offset by the ~~impairment of our~~reduction in proved oil and gas properties ~~recorded in the third quarter of 2016, reductions in estimated future development costs~~ as a result of ~~reduced service costs that occurred~~the divestitures in Utica and Marcellus in the fourth quarter of ~~2016,~~2017 and ~~the addition of crude oil reserves~~Niobrara and Eagle Ford in the ~~fourth~~first quarter of ~~2016.~~2018 and an increase in proved oil and gas reserves. The components of our DD&A expense were as follows:

Three Months Ended
September 30,
2017 2016
(In thousands)
DD&A of proved oil and gas properties
$66,221

$47,702
Depreciation of other property and equipment 584
656
Amortization of other assets 294
251
Accretion of asset retirement obligations 465
340
Total DD&A
$67,564

$48,949

We did not recognize an impairment of proved oil and gas properties for the three months ended September 30, 2017. Primarily due to the decline in the 12-Month Average Realized Price of crude oil, we recognized an impairment of proved oil and gas properties for the three months ended September 30, 2016. Details of the 12-Month Average Realized Price of crude oil for the three months ended September 30, 2017 and 2016 and the impairment of proved oil and gas properties for the three months ended September 30, 2016 are summarized in the table below:

Three Months Ended
September 30,
2017 2016
Impairment of proved oil and gas properties (in thousands)
$—
$105,057
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period $46.80 $39.84
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period $47.74 $38.36
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period

2 % (4 %)



	Three Months Ended September 30,
	2018		2017
	(In thousands)
DD&A of proved oil and gas properties		$79,051		$66,221
Depreciation of other property and equipment	607		584
Amortization of other assets	102		294
Accretion of asset retirement obligations	348		465
Total DD&A		$80,108		$67,564

General and administrative expense, net decreased to ~~$16.0~~$12.8 million for the three months ended September 30, ~~2017~~2018 from ~~$18.1~~$16.0 million for the corresponding period in ~~2016.~~2017. The decrease was primarily due to ~~a decrease in~~ stock-based compensation expense, net ~~resulting from~~as a ~~decrease in stock appreciation rights outstanding during the three months ended September 30, 2017 due to exercises and expirations and~~result of a larger decrease in the fair value of stock appreciation rights for the three months ended September 30, ~~2017~~2018 as compared to the same period in 2016, partially offset by higher compensation costs for the three months ended September 30, 2017 as compared to the same period in 2016 resulting from an increase in personnel as a result of the ExL Acquisition as well as additional expenses related to a program we implemented to provide financial assistance to employees impacted by Hurricane Harvey.

2017.

We recorded a loss on derivatives, net of ~~$24.4~~$55.4 million and ~~a gain on derivatives, net of $11.7~~$24.4 million for the three months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively. The components of our ~~(gain)~~ loss on derivatives, net were as follows:


	Three Months Ended September 30,						Three Months Ended September 30,
	2017			2016			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		$7,567			($8,309	)
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	842			—			9,382			842
Loss due to deferred premium obligations incurred	10,151			55			—			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							5,086			—
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	(2,183		)	(3,490		)	(192		)	(2,183		)
Contingent ExL Payment
Loss due to upward shift in the futures curve of forecasted crude oil prices from the closing date to the end of the period	8,000			—
(Gain) loss on derivatives, net		$24,377			($11,744	)
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period							6,830			8,000
Loss on derivatives, net								$55,388			$24,377

Interest expense, net for the three months ended September 30, ~~2017~~2018 was ~~$20.7~~$15.4 million as compared to ~~$21.2~~$20.7 million for the same period in ~~2016. An increase in~~2017. The decrease was primarily due to reduced interest expense as a result of the ~~$250.0 million aggregate principal amount~~redemptions of ~~our 8.25%~~the 7.50% Senior Notes ~~that were issued~~ in ~~July~~the fourth quarter of 2017 and first quarter of 2018, The decrease was partially offset by increased borrowings and associated interest expense on our revolving credit facility infor the ~~third quarter of 2017~~three months ended September 30, 2018 as compared to the third quarter of 2016 was more than offset by an increase in capitalized interest as a result of higher average balances of unevaluated leasehold and seismic costs for the third quarter of 2017 as compared to the third quarter of 2016, primarily due to the ExL Acquisition.three months ended September 30, 2017. The components of our interest expense, net were as follows:


	Three Months Ended September 30,						Three Months Ended September 30,
	2017			2016			2018			2017
	(In thousands)						(In thousands)
Interest expense on Senior Notes		$25,750			$21,454			$17,750			$25,750
Interest expense on revolving credit facility	1,969			1,161			5,092			1,969
Amortization of premiums and debt issuance costs	1,116			1,186			956			1,116
Other interest expense	293			340			124			293
Interest capitalized	(8,455		)	(2,951		)	(8,516		)	(8,455		)
Interest expense, net		$20,673			$21,190			$15,406			$20,673

The effective income tax rates for the third quarter of 2018 and 2017 were 1.1% and ~~2016~~0.0%, respectively, which were ~~0.0% and 0.3%, respectively. This is~~nominal as a result of maintaining 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~~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 ~~by the~~due to impairments of proved oil and gas properties we recognized ~~beginning~~ in the ~~third~~fourth quarter of 2015 and ~~continuing through~~ the ~~third quarter~~first three quarters of ~~2016. For~~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 ~~three~~next 12 months, ~~ended September 30, 2017, as~~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 ~~result~~release of ~~current quarter activity,~~ a ~~partial~~portion or substantially all of the valuation allowance. A release ~~from~~of the valuation allowance ~~was recorded to bring~~would result in the ~~net~~recognition of an increase in deferred tax assets ~~to zero. For~~and an income tax benefit in the ~~three months ended September 30, 2016, we recorded an additional valuation allowance primarily as a result~~period in which the release occurs, although the exact timing and amount of the ~~impairments~~release is subject to change based on numerous factors, including our projections of ~~proved oil and gas properties described above.~~future taxable income, which we continue to assess based on available information each reporting period.

For the three months ended September 30, 2018 and 2017, we declared and paid cash dividends of $4.5 million and $2.2 million, ~~of dividends, in cash, to the holders of record of the~~respectively, on our Preferred ~~Stock on September 1, 2017 for the period from issuance through September 15, 2017, which reduced net income to compute net income attributable to common shareholders.~~Stock.

Results of Operations

Nine Months Ended September 30, ~~2017,~~2018, Compared to the Nine Months Ended September 30, ~~2016~~2017

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the nine months ended September 30, ~~2017~~2018 and ~~2016:~~2017:


	Nine Months Ended September 30,				2017 Period Compared to 2016 Period					Nine Months Ended September 30,				2018 Period Compared to 2017 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)		2018		2017		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	8,867		6,780		2,087			31	%	10,272		8,867		1,405			16	%
NGLs (MBbls)	1,482		1,324		158			12	%	2,648		1,482		1,166			79	%
Natural gas (MMcf)	21,279		19,502		1,777			9	%	16,996		21,279		(4,283		)	(20	%)
Total barrels of oil equivalent (MBoe)	13,896		11,354		2,542			22	%	15,753		13,896		1,857			13	%

Daily production volumes by product -
Crude oil (Bbls/d)	32,481		24,744		7,737			31	%	37,628		32,481		5,147			16	%
NGLs (Bbls/d)	5,430		4,831		599			12	%	9,699		5,430		4,269			79	%
Natural gas (Mcf/d)	77,946		71,174		6,772			10	%	62,258		77,946		(15,688		)	(20	%)
Total barrels of oil equivalent (Boe/d)	50,902		41,438		9,464			23	%	57,703		50,902		6,801			13	%

Daily production volumes by region (Boe/d) -
Eagle Ford	36,569		30,101		6,468			21	%	37,241		36,569		672			2	%
Delaware Basin	3,871		660		3,211			487	%	20,236		3,871		16,365			423	%
Niobrara	2,627		2,845		(218		)	(8	%)
Marcellus	7,136		6,451		685			11	%
Utica and other	699		1,381		(682		)	(49	%)
Other										226		10,462		(10,236		)	(98	%)
Total barrels of oil equivalent (Boe/d)	50,902		41,438		9,464			23	%	57,703		50,902		6,801			13	%

Average realized prices -
Crude oil ($ per Bbl)		$47.70		$37.57		$10.13		27	%		$66.13		$47.70		$18.43		39	%
NGLs ($ per Bbl)	18.68		11.42		7.26			64	%	27.18		18.68		8.50			46	%
Natural gas ($ per Mcf)	2.28		1.53		0.75			49	%	2.44		2.28		0.16			7	%
Total average realized price ($ per Boe)		$35.92		$26.40		$9.52		36	%		$50.32		$35.92		$14.40		40	%

Revenues (In thousands) -
Crude oil		$422,999		$254,758		$168,241		66	%		$679,242		$422,999		$256,243		61	%
NGLs	27,678		15,119		12,559			83	%	71,969		27,678		44,291			160	%
Natural gas	48,440		29,886		18,554			62	%	41,417		48,440		(7,023		)	(14	%)
Total revenues		$499,117		$299,763		$199,354		67	%		$792,628		$499,117		$293,511		59	%

Production volumes for the nine months ended September 30, ~~2017~~2018 were ~~50,902~~57,703 Boe/d, an increase of ~~23%~~13% from ~~41,438~~50,902 Boe/d for the same period in ~~2016.~~2017. The increase is primarily due to production from new wells in the ~~Eagle Ford and~~ Delaware Basin, ~~and the addition of production~~primarily drilled on properties from ~~the Sanchez Acquisition in late 2016 and~~ the ExL Acquisition, as well as in Eagle Ford, partially offset by the divestitures in Utica and Marcellus in the ~~third~~fourth quarter of 2017 ~~partially offset by normal production declines.~~and Niobrara and Eagle Ford in the first quarter of 2018. Revenues for the nine months ended September 30, ~~2017~~2018 increased ~~67%~~59% to ~~$499.1~~$792.6 million from ~~$299.8~~$499.1 million for the same period in ~~2016~~2017 primarily due to ~~increased production~~higher crude oil prices and higher ~~commodity prices.~~crude oil production.

Lease operating expenses for the nine months ended September 30, ~~2017~~2018 increased to $115.4 million ($7.33 per Boe) from $100.8 million ($7.25 ~~per Boe) from $71.1 million ($6.26~~ per Boe) for the same period in ~~2016.~~2017. The increase in lease operating expenses is primarily due to costs associated with increased ~~production and increased workover costs primarily on wells recently acquired in the Sanchez Acquisition.~~production. The increase in lease operating expense per Boe is primarily due to processing 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 ~~workover costs described above as well as~~adoption of ASC in 606. Additionally, there was a net increase in lease operating expense per Boe related to anthe 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 Marcellus in the fourth quarter of 2017 and the increased 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.

Production taxes increased to ~~$21.1~~$37.6 million (or ~~4.2%~~4.7% of revenues) for the nine months ended September 30, ~~2017~~2018 from ~~$12.9~~$21.1 million (or ~~4.3%~~4.2% of revenues) for the same period in ~~2016~~2017 primarily as a result of the increase in crude oil and NGL ~~and natural gas~~revenues. The

~~revenues. The decrease~~increase in production taxes as a percentage of revenues is ~~primarily~~ due to ~~a benefit~~the divestiture of substantially all of our assets in Marcellus in the ~~nine months ended September 30,~~fourth quarter of 2017, ~~of lower actual~~as our production ~~taxes than previously estimated~~ in ~~Niobrara.~~Marcellus was not subject to production taxes.

Ad valorem taxes increased to ~~$5.8~~$8.2 million (1.0% of revenues) for the nine months ended September 30, ~~2017~~2018 from ~~$4.0~~$5.8 million (1.2% of revenues) for the same period in ~~2016.~~2017. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and ~~Delaware Basin in 2016 and~~ new wells drilled or acquired in the ~~Sanchez Acquisition~~Delaware Basin and higher property tax valuations as a result of the increase in ~~December 2016.~~crude oil 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 nine months ended September 30, ~~2017~~2018 increased ~~$20.5~~$36.0 million to $217.0 million ($13.78 per Boe) from $181.0 million ($13.03 ~~per Boe) from $160.5 million ($14.14~~ per Boe) for the same period in ~~2016.~~2017. The increase in DD&A expense is attributable to increased production ~~partially offset by the decrease~~as well as an increase in the DD&A rate per Boe. The ~~decrease~~increase in the DD&A rate per Boe is due primarily to ~~impairments of our proved oil and gas properties recorded during the nine months ended September 30, 2016, reductions~~increases in ~~estimated~~ future development costs ~~as a result of reduced service costs~~ that occurred insubsequent to the ~~fourth~~third quarter of ~~2016, and the addition of crude oil reserves in the fourth quarter of 2016, partially offset by the allocation~~2017 as well as an increase to proved oil and gas properties ~~related to~~as a result of our ongoing capital expenditure program, partially offset by the ~~ExL Acquisition.~~reduction in proved oil and gas properties as a result of the divestitures in Utica and Marcellus in the fourth quarter of 2017 and Niobrara and Eagle Ford in the first quarter of 2018 and an increase in proved oil and gas reserves. The components of our DD&A expense were as follows:

Nine Months Ended
September 30,
2017 2016
(In thousands)
DD&A of proved oil and gas properties
$176,876

$156,595
Depreciation of other property and equipment 1,842
1,994
Amortization of other assets 966
892
Accretion of asset retirement obligations 1,334
1,011
Total DD&A
$181,018

$160,492

We did not recognize impairments of proved oil and gas properties for the nine months ended September 30, 2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil, we recognized impairments of proved oil and gas properties for the nine months ended September 30, 2016. Details of the 12-Month Average Realized Price of crude oil for the nine months ended September 30, 2017 and 2016 and impairments of proved oil and gas properties for the nine months ended September 30, 2016 are summarized in the table below:

Nine Months Ended
September 30,
2017 2016
Impairments of proved oil and gas properties (in thousands)
$—
$576,540
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period $39.60 $47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period $47.74 $38.36
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period

21 % (19 %)



	Nine Months Ended September 30,
	2018		2017
	(In thousands)
DD&A of proved oil and gas properties		$213,727		$176,876
Depreciation of other property and equipment	1,801		1,842
Amortization of other assets	476		966
Accretion of asset retirement obligations	1,001		1,334
Total DD&A		$217,005		$181,018

General and administrative expense, net ~~decreased~~increased to ~~$49.3~~$58.4 million for the nine months ended September 30, ~~2017~~2018 from ~~$59.0~~$49.3 million for the same period in ~~2016.~~2017. The ~~decrease~~increase was primarily due to ~~a decrease~~an increase in stock-based compensation expense, net as a result of ~~a decrease~~an increase in the fair value of stock appreciation rights for the nine months ended September 30, ~~2017~~2018 compared to ~~an increase~~a decrease in fair value for the nine months ended September 30, ~~2016, partially offset by~~2017 as well as an increase in personnel costs and higher annual bonuses awarded in the first quarter of ~~2017~~2018 compared to the first quarter of ~~2016.~~

2017.

We recorded a loss on derivatives, net of $152.7 million and a gain on derivatives, net of $27.0 million ~~and a loss on derivatives, net of $29.9 million~~ for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively. The components of our (gain) loss on derivatives, net were as follows:


	Nine Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		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		($28,334	)		$10,209		$113,282			($28,334	)
(Gain) loss due to new derivative positions executed during the period	(11,420		)	1,797		13,330			(11,420		)
Loss due to deferred premium obligations incurred	17,652			5,667		—			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						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	(12,902		)	—		(3,152		)	(12,902		)
Loss due to new derivative positions executed during the period	—			12,167		68			—
Loss due to deferred premium obligations incurred	—			98
Contingent ExL Payment
Loss due to upward shift in the futures curve of forecasted crude oil prices from the closing date to the end of the period	8,000			—
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period						19,285			8,000
(Gain) loss on derivatives, net		($27,004	)		$29,938		$152,698			($27,004	)

Interest expense, net for the nine months ended September 30, ~~2017~~2018 was ~~$62.4~~$46.5 million as compared to ~~$58.9~~$62.4 million for the same period in ~~2016.~~2017. The ~~increase~~decrease was due primarily to ~~the~~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 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 ~~the~~ $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in ~~July~~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 nine months ended September 30, ~~2017~~2018 as compared to the nine months ended September 30, 2016, partially offset by an increase in capitalized interest as a result of higher average balances of unevaluated leasehold and seismic costs for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, primarily as a result of the ExL Acquisition.2017. The components of our interest expense, net were as follows:


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2018			2017
	(In thousands)						(In thousands)
Interest expense on Senior Notes		$68,660			$64,364			$57,003			$68,660
Interest expense on revolving credit facility	5,656			2,827			13,741			5,656
Amortization of debt issuance costs, premiums, and discounts	3,381			4,296			2,996			3,381
Other interest expense	876			854			394			876
Capitalized interest	(16,223		)	(13,428		)	(27,612		)	(16,223		)
Interest expense, net		$62,350			$58,913			$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 nine months ended 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 nine months ended September 30, 2018 and 2017 was 1.2% and ~~2016 was~~ 0.0%~~. This is~~, respectively, which were nominal as a result of maintaining 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.

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 we recognized ~~beginning~~ in the ~~third~~fourth quarter of 2015 and ~~continuing through~~ the ~~third quarter~~first three quarters of ~~2016. For~~2016, which limits our ability to consider subjective positive evidence, such as its projections of future taxable income.

We currently believe it is reasonably possible for us to achieve a three-year cumulative level of profitability within the ~~nine~~next 12 months, ~~ended September 30, 2017, as~~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 ~~result~~release of ~~current year activity,~~ a ~~partial~~portion or substantially all of the valuation allowance. A release ~~from~~of the valuation allowance ~~was needed to bring~~would result in the ~~net~~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 ~~zero. For the nine months ended September 30, 2017,~~change based on numerous factors, including our projections of future taxable income, which we ~~recorded additional valuation allowance primarily as a result of impairments of proved oil and gas properties described above.~~continue to assess based on available information each reporting period.

For the nine months ended September 30, 2018 and 2017, we declared and paid cash dividends of $13.8 million and $2.2 million, respectively, on our Preferred Stock.

During the first quarter of ~~dividends, in cash,~~2018, we redeemed 50,000 shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million redemption price and $0.5 million accrued and unpaid dividends. We recognized a $7.1 million loss on the redemption due to the ~~holders~~excess of ~~record~~the $50.0 million redemption price over the $42.9 million redemption date carrying value of the Preferred ~~Stock on September 1, 2017 for the period from issuance through September 15, 2017, which reduced net income to compute net income attributable to common shareholders.~~Stock.

Liquidity and Capital Resources

~~2017~~2018 Drilling, Completion, and ~~Completion~~Infrastructure Capital Expenditure Plan and Funding Strategy. ~~In November 2017, our 2017~~Our 2018 drilling, completion, and ~~completion~~infrastructure capital expenditure plan ~~was increased to $600.0~~remains unchanged at $800.0 million to $620.0 million from the previous range of $590.0 million to $610.0 million, due to updated plans in the Delaware Basin as a result of the ExL Acquisition, as well as an increase in non-operated activity on our acreage in the Delaware Basin and Niobrara.$825.0 million. We currently intend to finance the remainder of our ~~2017~~2018 drilling, completion, and ~~completion~~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. ~~Below~~The following is a summary of our capital expenditures for the three ~~months ended March 31, 2017, June 30, 2017~~ and ~~September 30, 2017 and for the~~ nine months ended September 30, ~~2017~~2018:


	Three Months Ended						Nine Months Ended		Three Months Ended						Nine Months Ended
	March 31, 2017		June 30, 2017		September 30, 2017		September 30, 2017		March 31, 2018		June 30, 2018		September 30, 2018		September 30, 2018
	(In thousands)								(In thousands)
Drilling and completion
Drilling, completion, and infrastructure
Eagle Ford		$111,472		$129,933		$122,281		$363,686		$135,677		$101,249		$149,386		$386,312
Delaware Basin	10,360		11,727		36,055		58,142		73,892		116,743		91,761		282,396
All other regions	6,412		6,734		6,698		19,844		284		—		—		284
Total drilling and completion	128,244		148,394		165,034		441,672
Total drilling, completion, and infrastructure									209,853		217,992		241,147		668,992
Leasehold and seismic	14,516		34,447		11,819		60,782		5,520		6,129		6,668		18,317
Total Capital Expenditures ⁽¹⁾		$142,760		$182,841		$176,853		$502,454
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 ~~obligations.~~costs.

Sources and Uses of Cash. Our primary use of cash is related to our drilling, completion and ~~completion~~infrastructure capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the nine months ended September 30, ~~2017,~~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 November ~~3, 2017,~~2, 2018, our revolving credit facility had a borrowing base of ~~900.0 million,~~$1.3 billion, with an elected commitment amount of ~~$800.0~~$1.1 billion, with $618.0 million ~~with $297.1 million~~of borrowings outstanding and $0.4 million in letters of credit issued, which reduce the amounts available under our revolving credit facility. As a result of the Fall 2017 borrowing base redetermination, the borrowing base was established at $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof. The calculation of the Fall 2017 borrowing base was supported solely by the reserves of our Eagle Ford and Delaware Basin assets.outstanding. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility. See “Note ~~6. Long-Term Debt” for details of the ninth and tenth amendments and “Note~~ 14. Subsequent Events” for details of the recent ~~eleventh amendment to the credit agreement governing our revolving credit facility.~~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 ~~6. Long-term Debt” for details of the issuance of the 8.25% Senior Notes, “Note 8. Preferred Stock” for details of the Preferred Stock issuance and “Note~~ 9. Shareholders’ Equity and Stock-Based Compensation” for details ofregarding 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 ~~“—General Overview—Potential Divestitures” above~~“Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for 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 ~~$280.6~~$465.3 million and ~~$197.8~~$280.6 million for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively. The ~~change~~increase was driven primarily by an increase in revenues as a result of higher ~~production and commodity~~crude oil prices and ~~a decrease in working capital requirements,~~higher crude oil production, partially offset by ~~a decrease~~an increase in the net cash ~~received from~~paid for derivative settlements and an increase in operating expenses and cash general and administrative expense.

Net cash used in investing activities ~~was $1.1 billion and $331.6~~decreased to $309.0 million for the nine months ended September 30, ~~2017 and 2016, respectively. The change~~2018, from $1,105.0 million for the corresponding period in 2017. This was due primarily to a decrease in cash ~~paid~~payments for the ExL Acquisition, increased capital expenditures, and cash paid for the Sanchez Acquisition in January and April 2017 for leases that were not conveyed in conjunction with the initial closing in December 2016, partially offset by the deposit received in connection with the pending divestiture of substantially all of our assets in the Utica Shale and increased proceeds from divestitures of oil and gas properties. The divestituresacquisitions of oil and gas properties, as well as cash received from the divestitures in ~~2017 were primarily related to the divestiture~~Niobrara and Eagle Ford in early 2018, partially offset by an increase in capital expenditures as a result of ~~a small undeveloped acreage position~~our ongoing drilling, completion, and infrastructure activity in Eagle Ford and the Delaware ~~Basin for net proceeds of $15.3 million.~~Basin.

Net cash ~~provided by~~used in financing activities was ~~$825.3 million and $94.0~~$163.5 million for the nine months ended September 30, 2018 compared to net cash provided by financing activities for the nine months ended September 30, 2017 ~~and 2016, respectively.~~of $825.3 million. The ~~increase~~change was primarily due to ~~net proceeds related to~~payments for the ~~issuance~~redemptions of ~~the 8.25%~~our 7.50% Senior Notes ~~the sale of~~and Preferred Stock, ~~and the sale of common stock, and increased~~decreased borrowings, net of repayments under our revolving credit facility, ~~in 2017 as compared to 2016, partially offset~~decreased cash provided by the issuance of senior notes and preferred stock, and increased ~~debt issuance costs related to the amendments to the credit agreement governing the revolving credit facility and~~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 ~~our~~ revolving credit facility” and “—Financing Arrangements—Senior Secured Revolving Credit Facility” for further details of our revolving credit facility.

Contingent ~~consideration.~~consideration arrangements. ~~In connection with~~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 ~~a contingent payment of $50.0 million per year for each of the years of 2018 through 2021 with a cap of $125.0 million. In connection with the sale of our Utica Shale assets, we could receive~~ contingent consideration ~~of $5.0 million per year for each of the years of 2018 through 2020 with a cap of $15.0 million.~~arrangements, where we will receive or be required to pay certain amounts if commodity prices are greater than specified thresholds. See “Note ~~3. Acquisitions and Divestitures of Oil and Gas Properties”~~10. Derivative Instruments” for further details of ~~the~~each of these contingent consideration ~~associated with the ExL Acquisition~~arrangements and ~~Utica Shale assets. In connection with the sale of our Marcellus Shale assets, we could receive contingent consideration of $3.0 million per year~~“Item 3. Quantitative and Qualitative Disclosures About Market Risk” for ~~each of the years of 2018 through 2020 with a cap of $7.5 million. See “Note 14. Subsequent Events” for further~~ details of the sensitivities to commodity price for each contingent consideration ~~associated with the Marcellus Shale assets.~~arrangement.

~~Hedging.~~Commodity derivative instruments. ~~To manage our exposure~~We use commodity derivative instruments to mitigate the effects of commodity price ~~risk and to provide a level of certainty in the cash flows to support our drilling and completion capital expenditure plan, we hedge~~volatility for a portion of our forecasted ~~production.~~sales of production and achieve a more predictable level of cash flow.

As of November ~~6, 2017,~~2, 2018, we had the following outstanding commodity derivative ~~positions~~instruments at weighted average contract volumes and prices:

~~Crude Oil Fixed Price Swaps~~

Period Volumes (in Bbls/d) NYMEX Price ($/Bbl)
Q4 2017 15,000

$53.44
FY 2018 6,000

$49.55

~~Crude Oil Basis Swaps~~



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

Period Volumes (in Bbls/d) LLS-NYMEX Price Differential ($/Bbl)
December 2017 15,000

$4.13
FY 2018 6,000

$2.91



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 Volumes (in Bbls/d) Midland-NYMEX Price Differential ($/Bbl)
FY 2018 6,000

($0.10 )

~~Crude Oil Three-Way Collars~~

NYMEX Prices
Period
Volumes
(in Bbls/d)

Sub-Floor Price
($/Bbl)

Floor Price
($/Bbl)

Ceiling Price
($/Bbl)
FY 2018 24,000

$39.38

$49.06

$60.14
FY 2019 12,000

$40.00

$48.40

$60.29

~~Crude Oil Net Sold Call Options~~

Period Volumes (in Bbls/d) NYMEX Ceiling Price ($/Bbl)
FY 2018 3,388

$71.33
FY 2019 3,875

$73.66
FY 2020 4,575

$75.98

~~Natural Gas Fixed Price Swaps~~

Period Volumes (in MMBtu/d) NYMEX Price ($/MMBtu)
Q4 2017 20,000

$3.30

~~Natural Gas Sold Call Options~~

Period Volumes (in MMBtu/d) NYMEX Ceiling Price ($/MMBtu)
Q4 2017 33,000

$3.00
FY 2018 33,000

$3.25
FY 2019 33,000

$3.25
FY 2020 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	—

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 ~~or Preferred Stock~~ prior to scheduled maturities through debt ~~or Preferred Stock~~ repurchases, either in the open market or in privately negotiated transactions, through debt ~~or Preferred Stock~~ redemptions or tender offers, or through repayments of bank borrowings. 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 September 30, ~~2017~~2018 (in thousands):


	October - December 2017		2018		2019		2020		2021		2022		2023 and Thereafter		Total		October - December 2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$—		$600,000		$—		$215,600		$904,425		$1,720,025		$—		$—		$130,000		$—		$309,837		$900,000		$1,339,837
Cash interest on senior notes and other long-term debt ⁽²⁾	20,409		106,444		106,444		106,444		61,444		61,444		83,236		545,865
Cash interest on senior notes ⁽²⁾																	20,313		71,000		71,000		61,250		61,250		82,188		367,001
Cash interest and commitment fees on revolving credit facility ⁽³⁾	2,463		9,639		9,639		9,639		9,639		3,320		—		44,339		3,637		14,233		14,233		14,233		4,903		—		51,239
Capital leases	464		1,823		1,800		1,050		—		—		—		5,137		450		1,800		1,050		—		—		—		3,300
Operating leases	1,260		4,939		4,799		4,597		4,450		1,854		—		21,899		1,158		4,500		4,219		3,702		3,639		24,658		41,876
Drilling rig contracts ⁽⁴⁾	11,006		23,170		8,881		—		—		—		—		43,057		12,412		35,541		15,932		792		—		—		64,677
Delivery commitments ⁽⁵⁾	3,503		8,615		7,301		4,829		3,684		282		26		28,240		938		3,726		2,807		2,487		30		26		10,014
Asset retirement obligations and other ⁽⁶⁾	884		1,765		429		378		129		261		23,404		27,250
Total Contractual Obligations		$39,989		$156,395		$139,293		$726,937		$79,346		$282,761		$1,011,091		$2,435,812
Produced water disposal commitments ⁽⁶⁾																	3,331		21,336		21,443		21,445		21,501		17,678		106,734
Asset retirement obligations and other ⁽⁷⁾																	633		2,853		910		377		244		16,499		21,516
Total Contractual Obligations ⁽⁸⁾																		$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, ~~other long-term debt due 2028,~~ and borrowings outstanding under our revolving credit facility which matures in 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been 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 ~~and other long-term debt~~ includes cash payments for interest on the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, and the 8.25% Senior Notes due ~~2025 and other long-term debt due 2028.~~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 September 30, ~~2017~~2018 of ~~3.45%~~3.87%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of September 30, ~~2017,~~2018, at the applicable commitment fee rate of 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 ~~throughput commitments, some of~~service agreements which require ~~delivery of a~~ minimum ~~volume~~volumes of natural gas ~~and NGLs. We may incur volume deficiency fees from time~~ to ~~time if we elect to voluntarily curtail production due to market or operational considerations.~~be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural ~~gas and NGLs.~~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 September 30, ~~2017~~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 September 30, ~~2017,~~2018, had a borrowing base of ~~$837.5 million,~~$1.0 billion, with an elected commitment amount of ~~$800.0~~$900.0 million, ~~with $215.6~~and $309.8 million of borrowings outstanding at a weighted average interest rate of ~~3.45% and $0.4 million in letters of credit outstanding.~~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 ~~issuance~~redemption of the ~~8.25%~~7.50% Senior Notes ~~(described below), in accordance with~~discussed below, the May 4, 2022 maturity date of the credit agreement ~~governing~~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 ~~our borrowing base~~ was reduced ~~by 25% of the aggregate principal amount of the 8.25% Senior Notes, reducing the borrowing base~~ from $900.0 million to ~~$837.5 million. As a result of~~$830.0 million, however, the ~~Fall 2017 borrowing base redetermination, the borrowing base was established at $900.0 million, with an~~ elected commitment amount ofremained unchanged at $800.0 million, until the next redetermination thereof. The calculation of the Fall 2017 borrowing base was supported solely by the reserves of our Eagle Ford and Delaware Basin assets. The borrowing base under our 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.million.

On May 4, ~~2017,~~2018, we entered into ~~a ninth amendment to our credit agreement governing~~ the ~~revolving credit facility to, among other things, extend the maturity date, increase the maximum credit amount, and increase the borrowing base. On June 28, 2017, we entered into a tenth~~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 ~~certain financial~~the covenant limiting payment of dividends and ~~restricted payments covenants as well as amend certain definitions.~~ 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 ~~November 3, 2017,~~October 29, 2018, we entered into

~~an eleventh~~ the thirteenth amendment to the credit agreement governing the revolving credit facility to, among other things, ~~establish~~increase the borrowing base ~~at $900.0 million, with an~~and elected commitment amount ~~of $800.0 million,~~ and ~~increase~~reduce the ~~general basket available~~margins applied to Eurodollar and base rate loans. See “Note 14. Subsequent Events” for ~~restricted payments.~~further details.

See “Note 6. Long-Term Debt” for ~~additional~~ details of ~~the ninth and tenth amendments,~~ 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. See “Note 14. Subsequent Events�� for additional details~~agreement as of September 30, 2018.

7.50% Senior Notes

During the first quarter of 2018, we redeemed $320.0 million of the ~~eleventh amendment.~~

~~Preferred Stock Purchase Agreement~~

On June 28, 2017, we entered into a Preferred Stock Purchase Agreement with the GSO Funds to issue and sell in a private placement (i) $250.0 million (250,000 shares) of Preferred Stock and (ii) Warrants for 2,750,000 sharesoutstanding aggregate principal amount of our ~~common stock, with~~7.50% Senior Notes at a ~~term of ten years and an exercise price of $16.08 per share, for a cash purchase~~ price equal to ~~$970.00 per share~~101.875% of ~~Preferred Stock purchased. We~~par. Upon the redemptions, we paid ~~the GSO Funds $5.0~~$336.9 million, which included redemption premiums of $6.0 million as well as accrued but unpaid interest of $10.9 million. As a ~~commitment fee upon signing the Preferred Stock Purchase Agreement. The closing~~result of the ~~private placement occurred~~redemptions, we recorded a loss on ~~August 10, 2017 contemporaneously with~~extinguishment of debt of $8.7 million, which included the ~~closing~~redemption premiums $6.0 million paid to redeem the notes and non-cash charges of $2.7 million attributable to the ~~ExL Acquisition. We received net proceeds~~write-off of ~~approximately $236.4 million, net of~~unamortized premium and debt issuance costs, from the issuance and sale of the Preferred Stock, which were used to fund a portion of the purchase price of the ExL Acquisition. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition and “Note 8. Preferred Stock” for further details regarding the Preferred Stock and Warrants.

~~Common Stock Offering~~costs.

On ~~July 3, 2017,~~October 18, 2018, we ~~completed~~delivered a ~~public offering~~notice of ~~15.6 million shares of~~conditional redemption to the trustee for our common stock at a price per share of $14.28. We used the net proceeds of $222.4 million, net of offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes.

~~8.25%~~7.50% Senior Notes ~~due 2025~~

~~On July 14, 2017, we closed a public offering of $250.0~~to call for redemption on November 19, 2018, the remaining $130.0 million aggregate principal amount of ~~8.25% Senior Notes due 2025. The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. We used~~ the net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. See “Note 6. Long-Term Debt” for further details regarding the 8.25% Senior Notes.

~~7.50% Senior Notes due 2020~~

~~We have the right to redeem all or a portion of the 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. InThe 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 ~~any~~the amendment to the credit agreement discussed above, therefore, our redemption ~~or repurchase~~obligation is no longer conditional. See “Note 14. Subsequent Events” for further details.

Redemption of ~~notes,~~Preferred Stock

During the first quarter of 2018, we ~~could enter into other transactions, which include refinancing~~redeemed 50,000 shares of Preferred Stock, representing 20% of the ~~7.50%~~issued and outstanding Preferred Stock, for $50.5 million, consisting of the $50.0 million redemption price and $0.5 million accrued and unpaid 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 redemption date carrying value of the Preferred 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.~~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.

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 ~~other than contingent consideration and preferred stock,~~ are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our ~~2016~~2017 Annual Report. See ~~“Note 3. Acquisitions and Divestitures of Oil and Gas Properties”,~~ “Note 8. Preferred Stock”, “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for details of the Preferred Stock and contingent consideration ~~and preferred stock.~~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 September 30, ~~2017~~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 ~~Prices.~~Price”). The sensitivity analysis is as of September 30, ~~2017~~2018 and, accordingly, does not consider drilling and completion activity, acquisitions or ~~dispositions~~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 September 30, ~~2017~~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)
September 30, 2017 Actual	$47.74	$2.41	$457
September 30, 2018 Actual					$62.65	$2.55	$1,553

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$52.72	$2.72	$920	$463	$68.99	$2.85	$2,105	$552
Crude Oil and Natural Gas -10%	$42.77	$2.08	$—	($457)	$56.32	$2.25	$1,001	($552)

Crude Oil Price Sensitivity
Crude Oil +10%	$52.72	$2.41	$858	$401	$68.99	$2.55	$2,062	$509
Crude Oil -10%	$42.77	$2.41	$62	($395)	$56.32	$2.55	$1,044	($509)

Natural Gas Price Sensitivity
Natural Gas +10%	$47.74	$2.72	$519	$62	$62.65	$2.85	$1,596	$43
Natural Gas -10%	$47.74	$2.08	$395	($62)	$62.65	$2.25	$1,510	($43)

Income Taxes

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

A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at September 30, 2017, driven primarily by the impairments of proved oil and gas properties beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as our potential for future growth. Beginning in the third quarter of 2015, and continuing through the third quarter of 2017, we concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including September 30, 2017, were reduced to zero.

As a result of adopting ASU 2016-09, we recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative- effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017.

For the three and nine months ended September 30, 2017, primarily as a result of current activity, a partial release of $3.3 million and $41.6 million, respectively, from the valuation allowance was needed to bring the net deferred tax assets to zero. After the impact of the partial release, the valuation allowance as of September 30, 2017 was $538.5 million. For the three and nine months ended September 30, 2016, we recorded additional valuation allowances of $36.7 million and $240.9 million, respectively, primarily as a result of the impairments of proved oil and gas properties recognized discussed above.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new

evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit.

As of September 30, ~~2017,~~2018, we have estimated U.S. federal net operating loss carryforwards of ~~$913.1 million.~~$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 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 September 30, ~~2017,~~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 ~~our recent adoption of ASU 2016-09~~the pronouncements we recently adopted as well as the recently issued accounting pronouncements from the Financial Accounting Standards Board.

~~Volatility of Crude Oil and Natural Gas Prices~~

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of crude oil, which are affected by changes in market supply and demand, overall economic activity, global political environment, weather, inventory storage levels and other factors, as well as the level and prices at which we have hedged our future production.

~~We review the carrying value of our oil and gas properties on a quarterly basis under the full cost method of accounting. See “Note 4. Property and Equipment, Net” for additional details.~~

We use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted production and thereby achieve a more predictable level of cash flows to support our drilling and completion capital expenditure program. We do not enter into derivative instruments for speculative or trading purposes. As of September 30, 2017, our commodity derivative instruments consisted of fixed price swaps, basis swaps, three-way collars and purchased and sold call options. See “Note 10. Derivative Instruments” for further details of our crude oil and natural gas derivative positions as of September 30, 2017 and “Note 14. Subsequent Events” for further details of the crude oil derivative positions entered into subsequent to September 30, 2017.

We determined that the Contingent ExL Payment is not clearly and closely related to the purchase and sale agreement for the ExL Properties, and therefore bifurcated this embedded feature and reflected the liability at fair value in the consolidated financial statements. The fair value of the contingent consideration was determined by a third-party valuation specialist using a Monte Carlo simulation including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note 10. Derivative Instruments” and “Note 11. Fair Value Measurements” for further details.

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

results of the ~~ExL~~Devon Properties;

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

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

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

our ability to maintain a sound financial position;

receipt of receivables and proceeds from divestitures;

our ability to complete planned transactions on desirable terms; and

the impact of governmental regulation, taxes, market changes and world ~~events; and~~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, ~~including the ExL Acquisition,~~ other actions by lenders and holders of our capital stock, the potential impact of

government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, failure to realize the anticipated benefits of an acquisition, including the ~~ExL~~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 ~~2016~~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” ofin our ~~2016~~2017 Annual Report. Except as disclosed ~~in this report,~~below, there have been no material changes from the disclosure made in our ~~2016~~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 nine months ended September 30, 2018 as well as the impact on the crude oil, NGL, and natural gas revenues assuming a 10% increase and decrease in our average realized crude oil, NGL, and natural gas prices, excluding the impact of derivative settlements:



	Three Months Ended September 30, 2018
	Crude oil		NGLs		Natural gas		Total
	(In thousands)
Revenues		$254,525		$33,798		$15,052		$303,375

Impact of a 10% fluctuation in average realized prices		$25,450		$3,381		$1,506		$30,337



	Nine Months Ended September 30, 2018
	Crude oil		NGLs		Natural gas		Total
	(In thousands)
Revenues		$679,242		$71,969		$41,417		$792,628

Impact of a 10% fluctuation in average realized prices		$67,931		$7,197		$4,147		$79,275

We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not enter into commodity derivative instruments for speculative purposes. As of September 30, 2018, our commodity derivative instruments consisted of price swaps, three-way collars, basis swaps, and sold call options. See “Note 10. Derivative Instruments” for further details of our crude oil, NGL and natural gas commodity derivative instruments as of September 30, 2018 and “Note 14. Subsequent Events” for further details of our crude oil derivative instruments entered into subsequent to September 30, 2018.

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



	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	)

The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors and risk adjusted discount rates. See “Note 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 September 30, 2018, as well as the impact on the fair values assuming a 10% increase and decrease in the 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 (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 September 30, 2018, we had approximately $1.3 billion of long-term debt outstanding. Of this amount, approximately $1.0 billion was fixed-rate debt with a weighted average interest rate of 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 September 30, ~~2017~~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 September 30, ~~2017~~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

~~Except as disclosed below, there~~There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our 2017 Annual ~~Report on Form 10-K for the year ended December 31, 2016 and our Quarterly Report on Form 10-Q for the period ended June 30, 2017.~~

~~A future issuance, sale or exchange of our stock or warrants could trigger a limitation on our ability to utilize net operating loss carryforwards.~~

Our ability to utilize U.S. net operating loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited under Section 382 of the Code upon the occurrence of ownership changes resulting from issuances of our stock or the sale or exchange

of our stock by certain shareholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of our stock during any three-year period. For this purpose, “stock” includes certain preferred stock and warrants (including the Preferred Stock and the Warrants issued to finance in part, the ExL Acquisition). In the event of such an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these loss carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Future issuances, sales or exchanges of our stock could, taken together with prior transactions with respect to our stock, trigger an ownership change under Section 382 of the Code and therefore a limitation on our ability to utilize our U.S. loss carryforwards. Any such limitation could cause some of such loss carryforwards to expire before we would be able to utilize them to reduce taxable income in future periods, possibly resulting in a substantial income tax expense or write down of our tax assets or both.

~~Holders of the Preferred Stock have rights that may restrict our ability to operate our business or be adverse to holders of our common stock.~~

The Statement of Resolutions Establishing Series of 8.875% Redeemable Preferred Stock of Carrizo Oil & Gas, Inc. (the “Statement of Resolutions”) contains covenants that, among other things, so long as the GSO Funds and their affiliates beneficially own more than 50% of the outstanding Preferred Stock, limit our ability to, without the written consent of a designated representative of the Preferred Stock, but subject to certain exceptions, (i) issue stock senior to or on parity with the Preferred Stock, (ii) incur indebtedness that would cause us to exceed a specified leverage ratio, (iii) amend, modify, alter or supplement our articles of incorporation or the Statement of Resolutions in a manner that would adversely affect the rights, preferences or privileges of the Preferred Stock, (iv) enter into or amend certain debt agreements that would be more restrictive on the payment of dividends on, or redemption of, the Preferred Stock than those existing on the Preferred Stock closing and (v) pay distributions on, purchase or redeem our common stock or other stock junior to the Preferred Stock that would cause us to exceed a specified leverage ratio. We can be required to redeem the Preferred Stock (i) after the seventh anniversary of its initial issuance or (ii) at any time we fail to pay a dividend, subject to limited cure rights.

Holders of the Preferred Stock will, in certain circumstances, have additional rights in the event we fail to timely pay dividends, fail to redeem the Preferred Stock upon a change of control if required or fail to redeem the Preferred Stock upon request of the holders of the Preferred Stock following the seventh anniversary of the date of issuing the Preferred Stock. These rights include, subject to certain exceptions, (i) that holders of a majority of the then-outstanding Preferred Stock will have the exclusive right, voting separately as a class, to appoint and elect up to two directors to our board of directors, (ii) that approval of the holders of a majority of the then-outstanding Preferred Stock will be required prior to incurring indebtedness subject to a leverage ratio, declaring or paying prohibited distributions or issuing equity of subsidiaries to third parties; and (iii) that holders of a majority of the then-outstanding Preferred Stock will have the right to increase dividend payments and the ability to require us to pay dividends in common stock.

Holders of the Preferred Stock also have limited voting rights, including those with respect to potential amendments to our articles of incorporation or the Statement of Resolutions that have an adverse effect on the existing terms of the Preferred Stock and in certain other limited circumstances or as required by law.Report.

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

The information regarding the private placement of the Preferred Stock and Warrants set forth in “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report is incorporated by reference into this Part II. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. Such private placement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. To the extent that any shares of common stock are issued upon exercise of the Warrants by a Warrant holder, they will be issued in transactions anticipated to be exempt from registration under the Securities Act by virtue of Section 3(a)(9) thereof. The maximum number of shares of common stock that may be issued under the Warrants is 2,750,000.None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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



Exhibit Number		Exhibit Description
~~3.1~~ †1.1	—	~~Statement~~Underwriting Agreement, dated as of ~~Resolutions Establishing Series of 8.875% Redeemable Preferred Stock of~~August 14, 2018, by and between Carrizo Oil & Gas, Inc.~~, filed with the Secretary of State~~ and Citigroup Global Markets Inc. and Goldman Sachs & Co. LLC, as representatives of the ~~State of Texas and effective August 10, 2017~~Underwriters (incorporated herein by reference to Exhibit ~~3.1~~1.1 to the Company’s Current Report on Form 8-K filed on August ~~11, 2017 (File No. 000-29187087))~~16, 2018).
~~4.1~~	—	Twentieth Supplemental Indenture dated July 14, 2017 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on July 14, 2017 (File No. 000-29187-87)).
~~4.2~~	—	Warrant Agreement, dated as of August 10, 2017, between Carrizo Oil & Gas, Inc. and Wells Fargo Bank, N.A., as warrant agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
~~10.1~~	—	Registration Rights Agreement, dated as of August 10, 2017, by and among Carrizo Oil & Gas, Inc. and the GSO Funds party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
~~10.2~~	—	Standstill and Voting Agreement, dated as of August 10, 2017, between Carrizo Oil & Gas, Inc. and the GSO Funds party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
*10.3	—	Eleventh Amendment to Credit Agreement, dated as of November 3, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto.
*31.1	—	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	—	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	—	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	—	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101	—	Interactive Data Files


*†	~~Filed herewith.~~Incorporated by reference as indicated.


+*	Schedules to this exhibit have been omitted pursuant to Item 601(b) of Regulation S-K; a copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.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:	November ~~8, 2017~~7, 2018		By:	/s/ David L. Pitts
		��		Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	November ~~8, 2017~~7, 2018		By:	/s/ Gregory F. Conaway
				Vice President and Chief Accounting Officer (Principal Accounting Officer)

~~-52-~~-51-



Period	Volumes (in Bbls/d)	NYMEX Price ($/Bbl)
Q4 2017	15,000		$53.44
FY 2018	6,000		$49.55



Period	Volumes (in Bbls/d)	LLS-NYMEX Price Differential ($/Bbl)
December 2017	15,000		$4.13
FY 2018	6,000		$2.91



		NYMEX Prices
Period	Volumes (in Bbls/d)	Sub-Floor Price ($/Bbl)		Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
FY 2018	18,000		$39.17		$49.08		$60.48
FY 2019	6,000		$40.00		$47.80		$61.45



Period	Volumes (in Bbls/d)	NYMEX Ceiling Price ($/Bbl)
FY 2018	3,388		$71.33
FY 2019	3,875		$73.66
FY 2020	4,575		$75.98



Period	Volumes (in MMBtu/d)	NYMEX Price ($/MMBtu)
Q4 2017	20,000		$3.30



Period	Volumes (in MMBtu/d)	NYMEX Ceiling Price ($/MMBtu)
Q4 2017	33,000		$3.00
FY 2018	33,000		$3.25
FY 2019	33,000		$3.25
FY 2020	33,000		$3.50



	Three Months Ended September 30, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$105			$111,072			$—		$—			$111,177
Total costs and expenses	28,551			184,047			—		66			212,664
Loss before income taxes	(28,446		)	(72,975		)	—		(66		)	(101,487		)
Income tax benefit	—			—			—		313			313
Equity in loss of subsidiaries	(72,975		)	—			—		72,975			—
Net loss		($101,421	)		($72,975	)		$—		$73,222			($101,174	)
Dividends on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($101,421	)		($72,975	)		$—		$73,222			($101,174	)



Period	Volumes (in Bbls/d)	Midland-NYMEX Price Differential ($/Bbl)
FY 2018	6,000		($0.10	)