10-Q

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

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

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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 was 81,454,621.

TABLE OF CONTENTS

		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	2
	Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016	3
	Consolidated Statement of Shareholders’ Equity for the nine months ended September 30, 2017	4
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016	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	49
Item 4.	Controls and Procedures	49
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	50
Item 3.	Defaults Upon Senior Securities	50
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	51
Signatures		52

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
Assets
Current assets
Cash and cash equivalents		$5,092			$4,194
Accounts receivable, net	89,809			64,208
Other current assets	7,826			4,586
Total current assets	102,727			72,988
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,882,575			1,294,667
Unproved properties, not being amortized	740,205			240,961
Other property and equipment, net	10,538			10,132
Total property and equipment, net	2,633,318			1,545,760
Other assets	9,681			7,579
Total Assets		$2,745,726			$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$87,077			$55,631
Revenues and royalties payable	46,821			38,107
Accrued capital expenditures	111,485			36,594
Accrued interest	25,305			22,016
Accrued lease operating expense	16,394			12,377
Derivative liabilities	6,778			22,601
Other current liabilities	24,579			24,633
Total current liabilities	318,439			211,959
Long-term debt	1,701,439			1,325,418
Asset retirement obligations	24,671			20,848
Derivative liabilities	77,184			27,528
Other liabilities	21,914			17,116
Total liabilities	2,143,647			1,602,869
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			—
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
Additional paid-in capital	1,926,798			1,665,891
Accumulated deficit	(1,538,934		)	(1,643,084		)
Total shareholders’ equity	388,679			23,458
Total Liabilities and Shareholders’ Equity		$2,745,726			$1,626,327

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues
Crude oil		$152,101			$95,154			$422,999			$254,758
Natural gas liquids	12,467			5,616			27,678			15,119
Natural gas	16,711			10,407			48,440			29,886
Total revenues	181,279			111,177			499,117			299,763
Costs and Expenses
Lease operating	34,874			24,282			100,767			71,071
Production taxes	7,741			4,886			21,092			12,940
Ad valorem taxes	1,736			1,426			5,776			3,950
Depreciation, depletion and amortization	67,564			48,949			181,018			160,492
General and administrative, net	16,029			18,119			49,328			59,046
(Gain) loss on derivatives, net	24,377			(11,744		)	(27,004		)	29,938
Interest expense, net	20,673			21,190			62,350			58,913
Impairment of proved oil and gas properties	—			105,057			—			576,540
Other expense, net	462			499			1,640			1,568
Total costs and expenses	173,456			212,664			394,967			974,458
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	)
Dividends on preferred stock	(2,249		)	—			(2,249		)	—
Net Income (Loss) Attributable to Common Shareholders		$5,574			($101,174	)		$101,901			($674,695	)
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	)
Weighted Average Common Shares Outstanding
Basic	81,053			58,945			70,728			58,705
Diluted	81,138			58,945			71,147			58,705

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount
Balance as of December 31, 2016	65,132,499		$651		$1,665,891			($1,643,084	)		$23,458
Stock-based compensation expense	—	—		17,967			—			17,967
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	722,122	8		(36		)	—			(28		)
Sale of common stock, net of offering costs	15,600,000	156		222,222			—			222,378
Issuance of warrants	—	—		23,003			—			23,003
Dividends on preferred stock	—	—		(2,249		)	—			(2,249		)
Net income	—	—		—			104,150			104,150
Balance as of September 30, 2017	81,454,621		$815		$1,926,798			($1,538,934	)		$388,679

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2017			2016
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
Depreciation, depletion and amortization	181,018			160,492
Impairment of proved oil and gas properties	—			576,540
(Gain) loss on derivatives, net	(27,004		)	29,938
Cash received for derivative settlements, net	7,714			98,820
Stock-based compensation expense, net	8,462			30,834
Non-cash interest expense, net	2,961			3,105
Other, net	4,249			2,427
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(25,885		)	1,768
Accounts payable	14,748			(20,294		)
Accrued liabilities	11,970			(7,954		)
Other assets and liabilities, net	(1,786		)	(3,134		)
Net cash provided by operating activities	280,597			197,847
Cash Flows From Investing Activities
Capital expenditures	(433,561		)	(346,245		)
Acquisitions of oil and gas properties	(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			—
Other, net	(3,804		)	(661		)
Net cash used in investing activities	(1,104,959		)	(331,575		)
Cash Flows From Financing Activities
Issuance of senior notes	250,000			—
Borrowings under credit agreement	1,311,875			510,116
Repayments of borrowings under credit agreement	(1,183,275		)	(414,116		)
Payments of debt issuance costs and credit facility amendment fees	(8,964		)	(1,150		)
Sale of common stock, net of offering costs	222,378			—
Sale of preferred stock, net of issuance costs	236,404			—
Payment of dividends on preferred stock	(2,249		)	—
Other, net	(909		)	(805		)
Net cash provided by financing activities	825,260			94,045
Net Increase (Decrease) in Cash and Cash Equivalents	898			(39,683		)
Cash and Cash Equivalents, Beginning of Period	4,194			42,918
Cash and Cash Equivalents, End of Period		$5,092			$3,235

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

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Operations

Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and gas 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 (“2016 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

Stock Compensation. 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, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by 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. 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 as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, this portion 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 are now required to be presented in cash flows from 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

Business Combinations. In January 2017, the 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) of assets or businesses. ASU 2017-01 is to be applied on a

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prospective basis 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.

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. 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 the same period. Companies are required to use a full retrospective approach, meaning 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 of cash flows and related disclosures upon adoption. The Company plans to adopt the guidance on the effective date of January 1, 2018.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. 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 the impact of ASU 2016-02 which includes an analysis of existing contracts, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements and current accounting policies 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. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. 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 ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, 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 of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 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 the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.

The Company is currently assessing 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 the requirements of the new standard. Appropriate changes to business processes, systems or controls will be implemented to support recognition and disclosure under the new standard. Although its assessment is in progress, the Company currently does not expect the adoption of ASU 2014-09 to have a material impact on its consolidated financial statements because existing contractual 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.

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Net Income (Loss) Per Common Share

Supplemental net income (loss) 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 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. The 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:

	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

3. Acquisitions and Divestitures of Oil and Gas Properties

Acquisitions

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, Texas (the “ExL Properties”) for a purchase price of $648.0 million, 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, 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 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 payment (the “Contingent ExL Payment”) 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 determined that the Contingent ExL Payment is an embedded derivative and has reflected the liability at fair value in the consolidated financial statements. The fair value of the Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was $60.3 million and $52.3 million, respectively. 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 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

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determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Payment was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, 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 presents the purchase price and the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Preliminary Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	292,551
Unproved properties	443,194
Total oil and gas properties		$735,745
Total assets acquired		$735,851
Liabilities
Revenues and royalties payable		$5,036
Asset retirement obligations	153
Contingent ExL Payment	52,300
Total liabilities assumed		$57,489
Net Assets Acquired		$678,362

Included in the consolidated statements of operations for the three and nine months ended September 30, 2017 are total revenues of $14.0 million and income before income taxes of $11.4 million from the ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.

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 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
	(In thousands, except per share amounts)
Total revenues		$189,499		$115,065			$534,607		$305,074
Net Income (Loss) Attributable to Common Shareholders		$14,654		($106,598	)		$115,053		($688,902	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$0.18		($1.43	)		$1.63		($9.27	)
Diluted		$0.18		($1.43	)		$1.62		($9.27	)
Weighted Average Common Shares Outstanding
Basic	81,053		74,545			70,728		74,305
Diluted	81,138		74,545			71,147		74,305

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Sanchez Acquisition. On December 14, 2016, the Company completed its initial closing of the acquisition of oil and gas properties in the Eagle Ford Shale from Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation (the “Sanchez Acquisition”). The transaction had 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 price of $16.8 million was made for leases that were not conveyed to the Company. On January 9, 2017 and April 13, 2017, the Company paid $7.0 million and $9.8 million, respectively, for these outstanding leases when conveyed to 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 in the consolidated statements of operations for the three and nine months ended September 30, 2017 are total revenues of $9.1 million and $23.2 million, respectively, and income before income taxes of $4.0 million and $7.1 million, respectively, from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.

Divestitures

Potential 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 Company could also receive 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, respectively (the “Contingent Utica Consideration”). The Contingent Utica Consideration will be zero 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.

Other Assets. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million. The proceeds from this sale were recognized as a reduction of proved oil and gas properties.

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4. Property and Equipment, Net

As of September 30, 2017 and December 31, 2016, total property and equipment, net consisted of the following:

	September 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,452,201			$4,687,416
Accumulated depreciation, depletion and amortization and impairments	(3,569,626		)	(3,392,749		)
Proved properties, net	1,882,575			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	697,370			211,067
Capitalized interest	42,835			29,894
Total unproved properties, not being amortized	740,205			240,961
Other property and equipment	25,344			23,127
Accumulated depreciation	(14,806		)	(12,995		)
Other property and equipment, net	10,538			10,132
Total property and equipment, net		$2,633,318			$1,545,760

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

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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 significant, unusual or infrequent items for which income taxes are computed and recorded 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.

The Company’s income tax (expense) benefit differs from the income tax (expense) benefit 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 for net operating losses 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 September 30, 2017, driven primarily by the impairments of proved oil 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 potential 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,

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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, partial releases of $3.3 million and $41.6 million, respectively, from the valuation allowance was recorded 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, the Company 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 during these periods.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its 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 the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.

6. Long-Term Debt

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

	September 30, 2017			December 31, 2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$215,600			$87,000
7.50% Senior Notes due 2020	600,000			600,000
Unamortized premium for 7.50% Senior Notes	836			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(6,397		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,527		)	(9,454		)
8.25% Senior Notes due 2025	250,000			—
Unamortized debt issuance costs for 8.25% Senior Notes	(4,498		)	—
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,701,439			$1,325,418

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, had a borrowing base of $837.5 million, with an elected commitment amount of $800.0 million, and $215.6 million of borrowings outstanding at a weighted average interest rate of 3.45%. 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 have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

On May 4, 2017, 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

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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 amendment to its credit agreement governing the revolving credit facility to, among other things (i) amend the calculation of certain financial covenants to provide that EBITDA will be calculated on an annualized basis as 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, (iii) amend the definition of “Disqualified Capital Stock” to provide, among other things, that the Preferred Stock does not constitute “Disqualified Capital Stock” for purposes of the revolving credit facility, (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, 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, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility. See “Note 14. Subsequent Events” for further details of the eleventh amendment.

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

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

Ratio of Outstanding Borrowings and Letters of Credit 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%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	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 after giving pro forma effect to EBITDA for material acquisitions and dispositions 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, the ratio of Total Debt to EBITDA was 3.09 to 1.00 and the Current Ratio was 2.20 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).

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8.25% Senior Notes due 2025

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, 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

On June 28, 2017, the Company 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 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 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. 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 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	%

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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 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

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 the issuance date, with $213.4 million allocated to the Preferred Stock and $23.0 million allocated to 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

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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:

	Issuance Date Fair Value Assumptions
Exercise price	$16.08
Expected term (in years)	10.0
Expected volatility	62.9	%
Risk-free interest rate	2.2	%
Dividend yield	—	%

See “Note 11. Fair Value Measurements” for further discussion of the significant inputs used in the Preferred Stock and Warrants fair value calculations.

Preferred Stock Dividends and Accretion

In the third quarter of 2017, the Company declared and paid $2.2 million of dividends, in cash, to the holders of record 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.

9. Shareholders’ Equity and Stock-Based Compensation

Increase in Authorized Common Shares

At the Company’s annual meeting 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 shares of common stock from 90,000,000 to 180,000,000.

Sale of Common Stock

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 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. 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, may be issued. 

As of September 30, 2017, there were 1,750,275 common shares remaining 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. Restricted 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.

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

	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.

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, the Company granted 342,440 SARs under the Cash SAR Plan with a grant date fair value of $12.00 per SAR, or $4.1 million, to certain employees and independent contractors as part of its annual grant of long-term equity incentive awards. All of these SARs contain a service condition and performance condition. The performance condition has been met.

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The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the nine months ended September 30,2017:

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

Performance Shares. The Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. 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 performance period, the last day of which is also the vesting date. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of September 30, 2017, unrecognized compensation costs related to unvested performance shares 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.

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:

	Grant Date Fair Value Assumptions
Number of simulations	500,000
Expected term (in years)	2.98
Expected volatility	59.2	%
Risk-free interest rate	1.5	%
Dividend yield	—	%

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Stock-Based Compensation Expense, Net.Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash and performance shares is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties.

The Company recognized the following stock-based compensation expense, net for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Restricted stock awards and units		$5,311			$5,487			$16,184			$23,079
Stock appreciation rights	429			3,361			(7,040		)	9,581
Performance shares	581			722			1,861			2,052
	6,321			9,570			11,005			34,712
Less: amounts capitalized to oil and gas properties	(1,455		)	(1,150		)	(2,543		)	(3,878		)
Total stock-based compensation expense, net		$4,866			$8,420			$8,462			$30,834

10. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, basis swaps, three-way collars and purchased and sold call options, which are described below.

Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes.

Basis Swaps: The 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 of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed 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 between the fixed 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. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. The Company has incurred premiums on certain of these contracts 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 ceiling price. The payment of 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

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basis. When the Company has entered into three-way collars which span multiple years, 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 derivative positions at weighted average contract prices as of September 30, 2017:

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

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

		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

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. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability 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.

Counterparties to the Company’s derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds the Company’s unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral.

Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, 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 derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties and its counterparty’s parent company, as applicable.

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Contingent Consideration

The Company has entered into 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, the Company agreed to 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, 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 million in the consolidated financial statements. As of September 30, 2017, the estimated fair value of the Contingent ExL Payment was $60.3 million and was classified as non-current “Derivative liabilities” in the consolidated balance sheets.

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Derivative Assets and Liabilities

All derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. The deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the Company’s consolidated balance sheets as of September 30, 2017 and December 31, 2016 are summarized below:

	September 30, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$11,571			($8,757	)		$2,814
Deferred premium obligations	—			(879		)	(879		)
Other current assets		$11,571			($9,636	)		$1,935
Commodity derivative instruments	10,415			(9,867		)	548
Deferred premium obligations	—			(423		)	(423		)
Other assets-non current		$10,415			($10,290	)		$125
Commodity derivative instruments		($9,143	)		$8,757			($386	)
Deferred premium obligations	(7,271		)	879			(6,392		)
Derivative liabilities-current		($16,414	)		$9,636			($6,778	)
Commodity derivative instruments	(13,711		)	9,867			(3,844		)
Deferred premium obligations	(13,463		)	423			(13,040		)
Contingent ExL Payment	(60,300		)	—			(60,300		)
Derivative liabilities-non current		($87,474	)		$10,290			($77,184	)

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Commodity derivative instruments	3,882			(3,882		)	—
Deferred premium obligations	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Commodity derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premium obligations	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premium obligations	(2,569		)	—			(2,569		)
Contingent ExL Payment	—			—			—
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

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

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(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 contingent consideration are recognized as (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations on the Company’s consolidated statements of operations for the three and nine months ended September 30,2017 and 2016 is summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$8,409			($8,309	)		($39,754	)		$12,006
Natural gas	(2,183		)	(3,490		)	(12,902		)	12,167
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

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as 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 and 2016 are summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$6,500			$23,165			$9,941			$104,549
Natural gas	522			—			(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

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.

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016:

	September 30, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$3,362			$—
Derivative instrument liabilities		$—		($4,230	)		($60,300	)

	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$1,237			$—
Derivative instrument liabilities		$—		($45,552	)		$—

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 based on a third-party industry-standard pricing model using 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. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for 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 and 2016.

Contingent consideration. The Company determined that 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 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. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuation, including the related inputs, and analyzed changes in fair value measurements between periods. The fair value of the Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was a liability of $60.3 million and $52.3 million, respectively. As a result, 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 3 for the nine months ended September 30,2017 and 2016. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 10. Derivative Instruments” for further details of the contingent consideration.

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

The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured on a nonrecurring basis on the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to 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

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

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

See “Note 8. Preferred Stock and Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants.

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. 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.

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$594,439		$610,500		$593,447		$624,750
6.25% Senior Notes due 2023	641,473		659,750		640,546		672,750
8.25% Senior Notes due 2025	245,502		269,375		—		—
Other long-term debt due 2028	4,425		4,408		4,425		4,419

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.

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)

	September 30, 2017
	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
Total property and equipment, net	39,789			2,592,458			5,057		(3,986		)	2,633,318
Investment in subsidiaries	(1,097,703		)	—			—		1,097,703			—
Other assets	9,526			155			—		—			9,681
Total Assets		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726
Liabilities and Shareholders’ Equity
Current liabilities		$128,778			$3,687,474			$5,057		($3,502,870	)		$318,439
Long-term liabilities	1,716,898			92,431			—		15,879			1,825,208
Preferred stock	213,400			—			—		—			213,400
Total shareholders’ equity	405,524			(1,097,703		)	—		1,080,858			388,679
Total Liabilities and Shareholders’ Equity		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726

	December 31, 2016
	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
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	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 benefit	—			—		—		—			—
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		)
Net income attributable to common shareholders		$5,603			$61,878		$—		($61,907	)		$5,574

	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	)

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	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 benefit	—			—		—		—			—
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		)
Net income attributable to common shareholders		$101,971			$184,589		$—		($184,659	)		$101,901

	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	)

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30, 2017
	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
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
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$5,092			$—			$—		$—			$5,092

	Nine Months Ended September 30, 2016
	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
Net cash used in investing activities	(122,846		)	(331,351		)	(740		)	123,362			(331,575		)
Net cash provided by financing activities	94,045			122,622			740			(123,362		)	94,045
Net decrease in cash and cash equivalents	(39,683		)	—			—			—			(39,683		)
Cash and cash equivalents, beginning of period	42,918			—			—			—			42,918
Cash and cash equivalents, end of period		$3,235			$—			$—			$—			$3,235

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13. Supplemental Cash Flow Information

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

	Nine Months Ended September 30,
	2017		2016
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$59,389		$55,808
Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		$98,829		$7,316
Contingent ExL Payment	52,300		—
Stock-based compensation expense capitalized to oil and gas properties	2,543		3,878
Asset retirement obligations capitalized to oil and gas properties	2,761		766

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

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

Crude Oil Basis Swaps

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	6,000		$40.00		$49.00		$59.13
FY 2019	6,000		$40.00		$49.00		$59.14

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Eleventh Amendment to the Credit Agreement

On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof, (ii) increase the general basket available for restricted payments from $50.0 million to $75.0 million and (iii) 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 and Delaware Basin assets.

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

The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our 2016 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

Total production for the three months ended September 30,2017 was 55,224 Boe/d, an increase of 35% from the three months ended September 30,2016, primarily due to production from new wells in the Eagle Ford and Delaware Basin and the addition of production from the Sanchez Acquisition in the fourth quarter of 2016 and the ExL Acquisition in the third quarter of 2017.

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

	Three Months Ended September 30, 2017				September 30, 2017
	Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	24	19.8	19	17.7	32	27.2	512	448.7
Delaware Basin	5	3.8	3	2.4	7	5.6	26	21.8
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

Drilling and completion expenditures for the third quarter of 2017 were $165.0 million, of which 96% were in the Eagle Ford and Delaware Basin. As of September 30, 2017, we were operating two rigs 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 acreage in the Delaware Basin and Niobrara. The primary focus for our remaining 2017 drilling and completion capital expenditures is on the continued exploration and development of oil-focused plays, such as the Eagle Ford and Delaware Basin, where approximately 94%of our remaining 2017 drilling and completion capital expenditure plan is allocated. See “—Liquidity and Capital Resources—2017 Drilling and Completion Capital Expenditure Plan and Funding Strategy” for additional details.

Financial Results

We recorded 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 net income attributable to common shareholders for the third quarter of 2017 as compared to the net loss attributable to common shareholders for the third quarter of 2016 was driven primarily by higher production volumes and commodity prices in the third quarter of 2017 compared to the third quarter of 2016 and no impairment of proved oil and gas properties during the third quarter of 2017 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 to a gain on derivatives, net of $11.7 million in the third quarter of 2016. See “—Results of Operations” below for further details.

ExL Acquisition

On June 28, 2017, we 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, Texas (the “ExL Properties”) for a purchase price 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 to the seller as a deposit on June 28, 2017 and $601.0 million upon closing on August 10, 2017, which included preliminary purchase price adjustments primarily

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related to 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 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. 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.

Upon issuance of the 8.25% Senior Notes, in accordance with the credit agreement governing the 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. See “—Eleventh Amendment to the Credit Agreement” below for further discussion of our borrowing base.

Potential Divestitures

On August 31, 2017, 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

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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 amendment to our credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof, (ii) increase the general basket available for restricted payments from $50.0 million to $75.0 million and (iii) 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 and Delaware Basin assets.

Results of Operations

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

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

	Three Months Ended September 30,				2017 Period Compared to 2016 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,211		2,253		958			43	%
NGLs (MBbls)	623		435		188			43	%
Natural gas (MMcf)	7,476		6,372		1,104			17	%
Total barrels of oil equivalent (MBoe)	5,080		3,750		1,330			35	%
Daily production volumes by product -
Crude oil (Bbls/d)	34,903		24,488		10,415			43	%
NGLs (Bbls/d)	6,777		4,730		2,047			43	%
Natural gas (Mcf/d)	81,265		69,262		12,003			17	%
Total barrels of oil equivalent (Boe/d)	55,224		40,762		14,462			35	%
Daily production volumes by region (Boe/d) -
Eagle Ford	39,002		29,110		9,892			34	%
Delaware Basin	6,994		1,344		5,650			420	%
Niobrara	2,427		2,576		(149		)	(6	%)
Marcellus	6,120		6,811		(691		)	(10	%)
Utica and other	681		921		(240		)	(26	%)
Total barrels of oil equivalent (Boe/d)	55,224		40,762		14,462			35	%
Average realized prices -
Crude oil ($ per Bbl)		$47.37		$42.23		$5.14		12	%
NGLs ($ per Bbl)	20.01		12.91		7.10			55	%
Natural gas ($ per Mcf)	2.24		1.63		0.61			37	%
Total average realized price ($ per Boe)		$35.68		$29.65		$6.03		20	%
Revenues (In thousands) -
Crude oil		$152,101		$95,154		$56,947		60	%
NGLs	12,467		5,616		6,851			122	%
Natural gas	16,711		10,407		6,304			61	%
Total revenues		$181,279		$111,177		$70,102		63	%

Production volumes for the three months ended September 30,2017 were 55,224 Boe/d, an increase of 35% from 40,762 Boe/d for the same period in 2016. The increase is primarily due to production from new wells in the Eagle Ford and Delaware Basin and the addition of production from the Sanchez Acquisition in the fourth quarter of 2016 and the ExL Acquisition in the

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

Lease operating expenses for the three months ended September 30,2017 increased to $34.9 million ($6.86 per Boe) from $24.3 million ($6.48 per Boe) for the same period in 2016. The increase in lease operating expenses is primarily due to increased production. The increase in lease operating expense per Boe is primarily due to increased workover costs primarily on wells acquired in the Sanchez Acquisition as well as to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties.

Production taxes increased to $7.7 million (or 4.3% of revenues) for the three months ended September 30,2017 from $4.9 million (or 4.4% of revenues) for the same period in 2016 primarily as a result of the increase in crude oil, NGL, and natural gas revenues. The decrease in production taxes as a percentage of revenues is primarily due to a benefit in the third quarter of 2017 of lower actual production taxes than previously estimated in the Niobrara.

Ad valorem taxes increased to $1.7 million for the three months ended September 30,2017 from $1.4 million for the same period in 2016. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and Delaware Basin in 2016 and new wells acquired in the Sanchez Acquisition in December 2016.

Depreciation, depletion and amortization (“DD&A”) expense for the third quarter of 2017 increased $18.6 million to $67.6 million ($13.30 per Boe) from the DD&A expense for the third quarter of 2016 of $48.9 million ($13.05 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 the addition to proved oil and gas properties related to the ExL Acquisition, partially offset by the impairment of our 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 in the fourth quarter of 2016, and the addition of crude oil reserves in the fourth quarter of 2016. 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	%)

General and administrative expense, net decreased to $16.0 million for the three months ended September 30,2017 from $18.1 million for the corresponding period in 2016. The decrease was primarily due to a decrease in stock-based compensation expense, net resulting from a decrease in stock appreciation rights outstanding during the three months ended September 30,2017 due to exercises and expirations and a decrease in the fair value of stock appreciation rights for the three months ended September 30,2017 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.

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

	Three Months Ended September 30,
	2017			2016
	(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 new derivative positions executed during the period	842			—
Loss due to deferred premium obligations incurred	10,151			55
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		)
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	)

Interest expense, net for the three months ended September 30,2017 was $20.7 million as compared to $21.2 million for the same period in 2016. An increase in interest expense as a result of the $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in July 2017 and increased borrowings on our revolving credit facility in the third quarter of 2017 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. The components of our interest expense, net were as follows:

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

The effective income tax rates for the third quarter of 2017 and 2016 were 0.0% and 0.3%, respectively. This is as a result of a full valuation allowance against our net deferred tax assets driven primarily by the impairments of proved oil and gas properties we recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016. For the three months ended September 30,2017, as a result of current quarter activity, a partial release from the valuation allowance was recorded to bring the net deferred tax assets to zero. For the three months ended September 30,2016, we recorded an additional valuation allowance primarily as a result of the impairments of proved oil and gas properties described above.

For the three months ended September 30,2017, we declared and paid $2.2 million of dividends, in cash, to the holders of record 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.

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Results of Operations

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

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

	Nine Months Ended September 30,				2017 Period Compared to 2016 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	8,867		6,780		2,087			31	%
NGLs (MBbls)	1,482		1,324		158			12	%
Natural gas (MMcf)	21,279		19,502		1,777			9	%
Total barrels of oil equivalent (MBoe)	13,896		11,354		2,542			22	%
Daily production volumes by product -
Crude oil (Bbls/d)	32,481		24,744		7,737			31	%
NGLs (Bbls/d)	5,430		4,831		599			12	%
Natural gas (Mcf/d)	77,946		71,174		6,772			10	%
Total barrels of oil equivalent (Boe/d)	50,902		41,438		9,464			23	%
Daily production volumes by region (Boe/d) -
Eagle Ford	36,569		30,101		6,468			21	%
Delaware Basin	3,871		660		3,211			487	%
Niobrara	2,627		2,845		(218		)	(8	%)
Marcellus	7,136		6,451		685			11	%
Utica and other	699		1,381		(682		)	(49	%)
Total barrels of oil equivalent (Boe/d)	50,902		41,438		9,464			23	%
Average realized prices -
Crude oil ($ per Bbl)		$47.70		$37.57		$10.13		27	%
NGLs ($ per Bbl)	18.68		11.42		7.26			64	%
Natural gas ($ per Mcf)	2.28		1.53		0.75			49	%
Total average realized price ($ per Boe)		$35.92		$26.40		$9.52		36	%
Revenues (In thousands) -
Crude oil		$422,999		$254,758		$168,241		66	%
NGLs	27,678		15,119		12,559			83	%
Natural gas	48,440		29,886		18,554			62	%
Total revenues		$499,117		$299,763		$199,354		67	%

Production volumes for the nine months ended September 30,2017 were 50,902 Boe/d, an increase of 23% from 41,438 Boe/d for the same period in 2016. The increase is primarily due to production from new wells in the Eagle Ford and Delaware Basin and the addition of production from the Sanchez Acquisition in late 2016 and the ExL Acquisition in the third quarter of 2017, partially offset by normal production declines. Revenues for the nine months ended September 30,2017 increased 67% to $499.1 million from $299.8 million for the same period in 2016 primarily due to increased production and higher commodity prices.

Lease operating expenses for the nine months ended September 30,2017 increased to $100.8 million ($7.25 per Boe) from $71.1 million ($6.26 per Boe) for the same period in 2016. The increase in lease operating expenses is primarily due to increased production and increased workover costs primarily on wells recently acquired in the Sanchez Acquisition. The increase in lease operating expense per Boe is primarily due to the workover costs described above as well as to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties.

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

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revenues. The decrease in production taxes as a percentage of revenues is primarily due to a benefit in the nine months ended September 30,2017 of lower actual production taxes than previously estimated in Niobrara.

Ad valorem taxes increased to $5.8 million for the nine months ended September 30,2017 from $4.0 million for the same period in 2016. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and Delaware Basin in 2016 and new wells acquired in the Sanchez Acquisition in December 2016.

DD&A expense for the nine months ended September 30,2017 increased $20.5 million to $181.0 million ($13.03 per Boe) from $160.5 million ($14.14 per Boe) for the same period in 2016. The increase in DD&A expense is attributable to increased production, partially offset by the decrease in the DD&A rate per Boe. The decrease in the DD&A rate per Boe is due primarily to impairments of our proved oil and gas properties recorded during the nine months ended September 30, 2016, reductions in estimated future development costs as a result of reduced service costs that occurred in the fourth quarter of 2016, and the addition of crude oil reserves in the fourth quarter of 2016, partially offset by the allocation to proved oil and gas properties related to the ExL Acquisition. 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	%)

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

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We recorded 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 and 2016, respectively. The components of our (gain) loss on derivatives, net were as follows:

	Nine Months Ended September 30,
	2017			2016
	(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
(Gain) loss due to new derivative positions executed during the period	(11,420		)	1,797
Loss due to deferred premium obligations incurred	17,652			5,667
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		)	—
Loss due to new derivative positions executed during the period	—			12,167
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			—
(Gain) loss on derivatives, net		($27,004	)		$29,938

Interest expense, net for the nine months ended September 30,2017 was $62.4 million as compared to $58.9 million for the same period in 2016. The increase was due primarily to the interest expense on the $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in July 2017 and an increase in interest expense on our revolving credit facility as a result of increased borrowings for the nine months ended September 30,2017 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. The components of our interest expense, net were as follows:

	Nine Months Ended September 30,
	2017			2016
	(In thousands)
Interest expense on Senior Notes		$68,660			$64,364
Interest expense on revolving credit facility	5,656			2,827
Amortization of debt issuance costs, premiums, and discounts	3,381			4,296
Other interest expense	876			854
Capitalized interest	(16,223		)	(13,428		)
Interest expense, net		$62,350			$58,913

The effective income tax rate for the nine months ended September 30,2017 and 2016 was 0.0%. This is as a result of a full valuation allowance against our net deferred tax assets driven by the impairments of proved oil and gas properties we recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016. For the nine months ended September 30,2017, as a result of current year activity, a partial release from the valuation allowance was needed to bring the net deferred tax assets to zero. For the nine months ended September 30,2017, we recorded additional valuation allowance primarily as a result of impairments of proved oil and gas properties described above.

For the nine months ended September 30,2017, we declared and paid $2.2 million of dividends, in cash, to the holders of record 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.

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Liquidity and Capital Resources

2017 Drilling and Completion Capital Expenditure Plan and Funding Strategy. In November 2017, our 2017 drilling and completion capital expenditure plan was increased to $600.0 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. We currently intend to finance the remainder of our 2017 drilling and completion 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 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:

	Three Months Ended						Nine Months Ended
	March 31, 2017		June 30, 2017		September 30, 2017		September 30, 2017
	(In thousands)
Drilling and completion
Eagle Ford		$111,472		$129,933		$122,281		$363,686
Delaware Basin	10,360		11,727		36,055		58,142
All other regions	6,412		6,734		6,698		19,844
Total drilling and completion	128,244		148,394		165,034		441,672
Leasehold and seismic	14,516		34,447		11,819		60,782
Total Capital Expenditures (1)		$142,760		$182,841		$176,853		$502,454

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

Sources and Uses of Cash. Our primary use of cash is related to our drilling and completion capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the nine months ended September 30,2017, we funded our capital expenditures 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, our revolving credit facility had a borrowing base of 900.0 million, with an elected commitment amount of $800.0 million, with $297.1 million 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. 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.

• 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 of 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 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.

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Overview of Cash Flow Activities.Net cash provided by operating activities was $280.6 million and $197.8 million for the nine months ended September 30,2017 and 2016, respectively. The change was driven primarily by an increase in revenues as a result of higher production and commodity prices and a decrease in working capital requirements, partially offset by a decrease in the net cash received from 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 million for the nine months ended September 30,2017 and 2016, respectively. The change was due primarily to cash paid 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 divestitures of oil and gas properties in 2017 were primarily related to the divestiture of a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million.

Net cash provided by financing activities was $825.3 million and $94.0 million for the nine months ended September 30,2017 and 2016, respectively. The increase was due to net proceeds related to the issuance of the 8.25% Senior Notes, the sale of Preferred Stock, and the sale of common stock, and increased borrowings net of repayments under our revolving credit facility in 2017 as compared to 2016, partially offset by increased debt issuance costs related to the amendments to the credit agreement governing the revolving credit facility and 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 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. In connection with the ExL Acquisition, 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. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the contingent consideration associated with the ExL Acquisition 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 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 contingent consideration associated with the Marcellus Shale assets.

• Hedging. To manage our exposure to 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 a portion of our forecasted production.

As of November 6, 2017, we had the following outstanding derivative positions at weighted average contract 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

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

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

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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

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.

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Contractual Obligations

The following table sets forth estimates of our contractual obligations as of September 30, 2017 (in thousands):

	October - December 2017		2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt (1)		$—		$—		$—		$600,000		$—		$215,600		$904,425		$1,720,025
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 and commitment fees on revolving credit facility (3)	2,463		9,639		9,639		9,639		9,639		3,320		—		44,339
Capital leases	464		1,823		1,800		1,050		—		—		—		5,137
Operating leases	1,260		4,939		4,799		4,597		4,450		1,854		—		21,899
Drilling rig contracts (4)	11,006		23,170		8,881		—		—		—		—		43,057
Delivery commitments (5)	3,503		8,615		7,301		4,829		3,684		282		26		28,240
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

(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 refinanced on or prior to such time).

(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, the 8.25% Senior Notes due 2025 and other long-term debt due 2028.

(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 of 3.45%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of September 30, 2017, 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 which require delivery of a minimum volume 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. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas and NGLs.

(6) Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of September 30, 2017. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.

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, had a borrowing base of $837.5 million, with an elected commitment amount of $800.0 million, with $215.6 million of borrowings outstanding at a weighted average interest rate of 3.45% and $0.4 million in letters of credit outstanding. 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 refinanced on or prior to such time) and any outstanding borrowings are due.

Upon issuance of the 8.25% Senior Notes (described below), in accordance with the credit agreement governing the 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 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. 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.

On May 4, 2017, 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 amendment to the credit agreement governing the revolving credit facility to, among other things, amend certain financial and restricted payments covenants as well as amend certain definitions. On November 3, 2017, we entered into

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an eleventh amendment to the credit agreement governing the revolving credit facility to, among other things establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, and increase the general basket available for restricted payments.

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 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 shares of our common stock, with 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 of Preferred Stock purchased. 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 received net proceeds of approximately $236.4 million, net of 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

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 for the ExL Acquisition and for general corporate purposes.

8.25% Senior Notes due 2025

On July 14, 2017, we closed a public offering of $250.0 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 7.50% Senior Notes at redemption prices of 101.875% until September 14, 2018 and 100% beginning September 15, 2018 and thereafter, in each case plus accrued and unpaid interest. In connection with any redemption or repurchase of notes, we could enter into other transactions, which include refinancing of the 7.50% Senior Notes.

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, 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 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 contingent consideration and preferred stock. We evaluate subsequent events through the date the financial statements are issued.

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The table below presents various pricing scenarios to demonstrate the sensitivity of our September 30, 2017 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of September 30, 2017 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions 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 that may require revisions to estimates of proved reserves.

	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
September 30, 2017 Actual	$47.74	$2.41	$457
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$52.72	$2.72	$920	$463
Crude Oil and Natural Gas -10%	$42.77	$2.08	$—	($457)
Crude Oil Price Sensitivity
Crude Oil +10%	$52.72	$2.41	$858	$401
Crude Oil -10%	$42.77	$2.41	$62	($395)
Natural Gas Price Sensitivity
Natural Gas +10%	$47.74	$2.72	$519	$62
Natural Gas -10%	$47.74	$2.08	$395	($62)

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

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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, we have estimated U.S. federal net operating loss carryforwards of $913.1 million. 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, our calculated ownership change percentage increased, however, as of September 30, 2017, 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 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:

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• 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;

• commodity price risk management activities and the impact on our average realized prices;

• 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 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 Acquisition;

• results of the ExL 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;

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

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 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) 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 the ExL Acquisition, market conditions and other factors affecting our ability to pay dividends on or redeem the Preferred Stock, integration and other acquisition risks, other factors affecting our ability to

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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 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” of our 2016 Annual Report. Except as disclosed in this report, there have been no material changes from the disclosure made in our 2016 Annual Report regarding our exposure to certain market risks.

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 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 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Except as disclosed below, there were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our 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

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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.

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.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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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	—	Statement of Resolutions Establishing Series of 8.875% Redeemable Preferred Stock of Carrizo Oil & Gas, Inc., filed with the Secretary of State of the State of Texas and effective August 10, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
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.

+ 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.

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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Carrizo Oil & Gas, Inc. (Registrant)
Date:	November 8, 2017	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)
Date:	November 8, 2017	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

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EX-10.3

Exhibit 10.3

ELEVENTH AMENDMENT

TO

CREDIT AGREEMENT

DATED AS OF NOVEMBER 3, 2017

AMONG

CARRIZO OIL & GAS, INC.,
AS BORROWER,

THE GUARANTORS PARTY HERETO,

WELLS FARGO BANK, NATIONAL ASSOCIATION,
AS ADMINISTRATIVE AGENT,

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK

AND ROYAL BANK OF CANADA,

AS CO-SYNDICATION AGENTS,

COMPASS BANK AND SG AMERICAS SECURITIES, LLC,

AS CO-DOCUMENTATION AGENTS

AND

THE LENDERS PARTY HERETO

WELLS FARGO SECURITIES, LLC, CITIGROUP GLOBAL MARKETS INC.

AND CAPITAL ONE, NATIONAL ASSOCIATION,

AS JOINT LEAD ARRANGERS AND BOOKRUNNERS

ELEVENTH AMENDMENT TO CREDIT AGREEMENT

THIS ELEVENTH AMENDMENT TO CREDIT AGREEMENT (this “Eleventh Amendment”) dated as of November 3, 2017, among CARRIZO OIL & GAS, INC., a Texas corporation (the “Borrower”); each of the undersigned guarantors (the “Guarantors”); the Lenders listed on the signature pages hereto; and WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

WHEREAS, the Borrower, the Administrative Agent, the Lenders and the other Agents party thereto are parties to that certain Credit Agreement dated as of January 27, 2011 (as amended by that certain First Amendment dated as of March 26, 2012, that certain Resignation, Consent and Appointment Agreement dated as of April 20, 2012, that certain Second Amendment dated as of September 4, 2012, that certain Third Amendment dated as of September 27, 2012, that certain Fourth Amendment dated as of October 9, 2013, that certain Fifth Amendment dated as of October 7, 2014, that certain Sixth Amendment dated as of May 5, 2015, that certain Seventh Amendment dated as of October 30, 2015, that certain Eighth Amendment dated as of May 3, 2016, that certain Ninth Amendment dated as of May 4, 2017, that certain Tenth Amendment dated as of June 28, 2017, and as otherwise amended, supplemented or modified, the “Credit Agreement”), pursuant to which the Lenders have made certain credit and other financial accommodations available to and on behalf of the Borrower.

WHEREAS, the Borrower has requested that the Lenders amend certain provisions of the Credit Agreement, and the Lenders are willing to do so on the terms and subject to the conditions set forth herein.

NOW, THEREFORE, to induce the Administrative Agent and the Lenders to enter into this Eleventh Amendment, and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Eleventh Amendment. Unless otherwise indicated, all section and article references in this Eleventh Amendment refer to sections and articles of the Credit Agreement.

Section 2.Amendments to Credit Agreement.

2.1Amendments to Section 1.02: Section 1.02 is hereby amended by adding, amending or restating, as the case may be, the following defined terms as follows:

“Agreement” means this Credit Agreement, as amended by that certain First Amendment dated as of March 26, 2012, that certain Resignation, Consent and Appointment Agreement dated as of April 20,

2012, that certain Second Amendment dated as of September 4, 2012, that certain Third Amendment dated as of September 27, 2012, that certain Fourth Amendment dated as of October 9, 2013, that certain Fifth Amendment dated as of October 7, 2014, that certain Sixth Amendment dated as of May 5, 2015, that certain Seventh Amendment dated as of October 30, 2015, that certain Eighth Amendment dated as of May 3, 2016, that certain Ninth Amendment dated as of May 4, 2017, that certain Tenth Amendment dated as of June 28, 2017, that certain Eleventh Amendment dated as of November 3, 2017, and as the same may from time to time be further amended, modified, supplemented or restated.

“Utilization Percentage” means, as of any day, the fraction expressed as a percentage, the numerator of which is the sum of the Revolving Credit Exposures on such day, and the denominator of which is the Borrowing Base in effect on such day.

2.2Amendment to Section 6.02(b). Section 6.02(b) is hereby amended by deleting such Section in its entirety and replacing it with the following:

“(b)    With respect to Loans made and/or Letters of Credit issued on the Effective Date, the representations and warranties of the Borrower and the Guarantors set forth in this Agreement and in the other Loan Documents shall be true and correct on and as of the Effective Date, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the Effective Date, such representations and warranties shall continue to be true and correct as of such specified earlier date, and (ii) with respect to any Borrowing or issuance, amendment, renewal or extension of any Letter of Credit after the Effective Date, the representations and warranties of the Borrower and the Guarantors set forth in this Agreement and in the other Loan Documents shall be true and correct in all material respects (except for those which have a materiality qualifier, which shall be true and correct as so qualified) on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date.”

2.3Amendment to Section 9.04(a)(viii). Section 9.04(a)(viii) is hereby amended by (a) deleting the figure “$10,000,000” in each instance of its use and replacing it with the figure “$15,000,000” and (b) deleting the figure “$50,000,000” in each instance of its use and replacing it with the Figure “$75,000,000”.

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Section 3.Borrowing Base. From and after the Eleventh Amendment Effective Date, the Borrowing Base is $900,000,000 and the Aggregate Elected Commitment Amount is $800,000,000, which Borrowing Base and Aggregate Elected Commitment Amount shall remain in effect until with respect to the Borrowing Base, the next Scheduled Redetermination or the Borrowing Base is otherwise redetermined or adjusted in accordance with the Credit Agreement and with respect to the Aggregate Elected Commitment Amount any adjustment pursuant to Section 2.07A. Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to Section 2.07(e), Section 8.12(c) or Section 9.11. Each of the Borrower, on the one hand, and the Administrative Agent and the Lenders, on the other hand, agree that the redetermination of the Borrowing Base pursuant to this Section 3 shall constitute the Scheduled Redetermination for November 1, 2017. This Section 3 constitutes notice of the redetermined Borrowing Base in accordance with Section 2.07(d) of the Credit Agreement.

Section 4.Conditions Precedent. This Eleventh Amendment shall become effective on the date when each of the following conditions is satisfied (or waived in accordance with Section 12.02) (such date, the “Eleventh Amendment Effective Date”):

4.1The Administrative Agent shall have received, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

4.2The Administrative Agent shall have received from all of the Lenders, the Borrower and the Guarantors, counterparts (in such number as may be requested by the Administrative Agent) of this Eleventh Amendment signed on behalf of such Person.

4.3No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Eleventh Amendment.

4.4The Administrative Agent shall have received such other documents as the Administrative Agent or its counsel may reasonably require in connection with the transactions contemplated hereby.

The Administrative Agent is hereby authorized and directed to declare this Eleventh Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 4 or the waiver of such conditions as permitted in Section 12.02. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.

Section 5.Miscellaneous.

5.1Confirmation. The provisions of the Credit Agreement, as amended by this Eleventh Amendment, shall remain in full force and effect following the effectiveness of this Eleventh Amendment.

5.2Ratification and Affirmation; Representations and Warranties. Each Credit Party hereby (a) acknowledges the terms of this Eleventh Amendment; (b) ratifies and affirms (i) its

- 3 -

obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby, and (ii) that the Liens created by the Loan Documents to which it is a party are valid and continuing and secure the Obligations in accordance with the terms thereof, after giving effect to this Eleventh Amendment; and (c) represents and warrants to the Lenders that on and as of the date hereof, and immediately after giving effect to the terms of this Eleventh Amendment (i) all of the representations and warranties of the Borrower and the Guarantors contained in the Loan Documents are true and correct in all material respects, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date, and (ii) no Default or Event of Default has occurred and is continuing.

5.3Loan Document. This Eleventh Amendment is a Loan Document.

5.4Counterparts. This Eleventh Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Eleventh Amendment by electronic transmission shall be effective as delivery of a manually executed counterpart hereof.

5.5NO ORAL AGREEMENT. THIS ELEVENTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.

5.6GOVERNING LAW. THIS ELEVENTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

5.7Payment of Expenses. In accordance with Section 12.03, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of-pocket costs and reasonable expenses incurred in connection with this Eleventh Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

5.8Severability. Any provision of this Eleventh Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

5.9Successors and Assigns. This Eleventh Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[SIGNATURES BEGIN NEXT PAGE]

- 4 -

IN WITNESS WHEREOF, the parties hereto have caused this Eleventh Amendment to be duly executed as of the date first written above.

BORROWER:    CARRIZO OIL & GAS, INC.

By: /s/ David L. Pitts    

David L. Pitts
Vice President and Chief Financial Officer

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

GUARANTORS:

BANDELIER PIPELINE HOLDING, LLC,

CARRIZO (EAGLE FORD) LLC,

CARRIZO (MARCELLUS) LLC,

CARRIZO (MARCELLUS) WV LLC,

CARRIZO MARCELLUS HOLDING INC.,

CARRIZO (NIOBRARA) LLC,

CARRIZO (PERMIAN) LLC,

CARRIZO (UTICA) LLC,

CLLR, INC.,

HONDO PIPELINE, INC.,

And

MESCALERO PIPELINE, LLC,

By: /s/ David L. Pitts    

David L. Pitts

Vice President

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

LENDERS:    WELLS FARGO BANK,

NATIONAL ASSOCIATION,

as Administrative Agent and a Lender

By: /s/ Greg Smothers    

Name: Greg Smothers    

Title: Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

CITIBANK, N.A.,

as a Lender

By: /s/ Peter Kardos    

Name: Peter Kardos    

Title: Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

CAPITALONE, NATIONAL ASSOCIATION,

as a Lender

By: /s/ Robert James    

Name: Robert James    

Title: Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

ROYAL BANK OF CANADA,

as a Lender

By: /s/ Jay T. Sartain    

Name: Jay T. Sartain    

Title: Authorized Signatory    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK,

as a Lender

By: /s/ Page Dillehunt    

Name: Page Dillehunt    

Title: Managing Director    

By: /s/ Ting Lee    

Name: Ting Lee    

Title: Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

SOCIETE GENERALE,

as a Lender

By: /s/ Elena Robciuc    

Name: Elena Robciuc    

Title: Managing Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

COMPASS BANK,

as a Lender

By: /s/ Kari McDaniel    

Name: Kari McDaniel    

Title: Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

BMO HARRIS BANK, N.A.,

as a Lender

By: /s/ James V. Ducote    

Name: James V. Ducote    

Title: Managing Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

PNC BANK, NATIONAL ASSOCIATION,

as a Lender

By: /s/ Daniel Winters    

Name: Daniel Winters    

Title: Assistant Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

THE BANK OF NOVA SCOTIA,

as a Lender

By: /s/ Alan Dawson    

Name: Alan Dawson    

Title: Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

GOLDMAN SACHS BANK USA,

as a Lender

By: /s/ Chris Lam    

Name: Chris Lam    

Title: Authorized Signatory    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

BANK OF AMERICA, N.A.,

as a Lender

By: /s/ Robert E. McKaig    

Name: Robert E. McKaig    

Title: Managing Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

ABN AMRO CAPITAL USA LLC,

as a Lender

By: /s/ Darrell Holley    

Name: Darrell Holley    

Title: Managing Director    

By: /s/ Michaela Braun    

Name: Michaela Braun    

Title: Director    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By: /s/ George E. McKean    

Name: George E. McKean    

Title: Senior Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

CREDIT SUISSE AG,

CAYMAN ISLANDS BRANCH,

as a Lender

By: /s/ Nupur Kumar    

Name: Nupur Kumar    

Title: Authorized Signatory    

By: /s/ Lea Baerlocher    

Name: Lea Baerlocher    

Title: Authorized Signatory    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

IBERIABANK,

as a Lender

By: /s/ Stacy Goldstein    

Name: Stacy Goldstein    

Title: Senior Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

ASSOCIATED BANK, N.A.,

as a Lender

By: /s/ Brian Caddell    

Name: Brian Caddell    

Title: Senior Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

COMERICA BANK,

as a Lender

By: /s/ William B. Robinson    

Name: William B. Robinson    

Title: Senior Vice President    

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

REGIONS BANK,

as a Lender

By: /s/ Kelly L. Elmore III    

Name: Kelly L. Elmore III

Title: Managing Director

Signature Page to Eleventh Amendment to Credit Agreement

Carrizo Oil & Gas, Inc.

EX-31.1

Exhibit 31.1

CERTIFICATION

PRINCIPAL EXECUTIVE OFFICER

I, S.P. Johnson, IV, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 8, 2017	/s/ S.P. Johnson, IV
		S.P. Johnson, IV President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

PRINCIPAL FINANCIAL OFFICER

I, David L. Pitts, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 8, 2017	/s/ David L. Pitts
		David L. Pitts Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson, IV, President and Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

1. the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 8, 2017	/s/ S.P. Johnson, IV
		S.P. Johnson, IV President and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, David L. Pitts, Vice President and Chief Financial Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

1. the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 8, 2017	/s/ David L. Pitts
		David L. Pitts Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 03, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Entity Registrant Name	CARRIZO OIL & GAS INC
Entity Central Index Key	0001040593
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		81,454,621

XML

Consolidated Balance Sheets - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 5,092,000	$ 4,194,000
Accounts receivable, net	89,809,000	64,208,000
Derivative assets, current
Other current assets	7,826,000	4,586,000
Total current assets	102,727,000	72,988,000
Oil and gas properties, full cost method
Proved properties, net	1,882,575,000	1,294,667,000
Unproved properties, not being amortized	740,205,000	240,961,000
Other property and equipment, net	10,538,000	10,132,000
Total property and equipment, net	2,633,318,000	1,545,760,000
Other assets	9,681,000	7,579,000
Total Assets	2,745,726,000	1,626,327,000
Current liabilities
Accounts payable	87,077,000	55,631,000
Revenues and royalties payable	46,821,000	38,107,000
Accrued capital expenditures	111,485,000	36,594,000
Accrued interest	25,305,000	22,016,000
Accrued Lease Operating Expense	16,394,000	12,377,000
Derivative liabilities	6,778,000	22,601,000
Other current liabilities	24,579,000	24,633,000
Total current liabilities	318,439,000	211,959,000
Long-term debt	1,701,439,000	1,325,418,000
Asset retirement obligations	24,671,000	20,848,000
Derivative liabilities, noncurrent	77,184,000	27,528,000
Other liabilities	21,914,000	17,116,000
Liabilities	2,143,647,000	1,602,869,000
Commitments and contingencies
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	213,400,000	0
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	815,000	651,000
Additional paid-in capital	1,926,798,000	1,665,891,000
Accumulated deficit	(1,538,934,000)	(1,643,084,000)
Total shareholders’ equity	388,679,000	23,458,000
Total Liabilities and Shareholders’ Equity	$ 2,745,726,000	$ 1,626,327,000

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	180,000,000	90,000,000
Common stock, shares issued (in shares)	81,454,621	65,132,499
Common stock, shares outstanding (in shares)	81,454,621	65,132,499
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.00
Preferred Stock, Shares Authorized	10,000,000	0
Preferred Stock, Shares Issued	250,000	0
Preferred Stock, Shares Outstanding	250,000	0

XML

Consolidated Statements Of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Crude oil revenues	$ 152,101	$ 95,154	$ 422,999	$ 254,758
Natural gas liquids revenues	12,467	5,616	27,678	15,119
Natural gas revenues	16,711	10,407	48,440	29,886
Total revenues	181,279	111,177	499,117	299,763
Costs and Expenses
Lease operating	34,874	24,282	100,767	71,071
Production taxes	7,741	4,886	21,092	12,940
Ad valorem taxes	1,736	1,426	5,776	3,950
Depreciation, depletion and amortization	67,564	48,949	181,018	160,492
General and administrative, net	16,029	18,119	49,328	59,046
(Gain) loss on derivatives, net	24,377	(11,744)	(27,004)	29,938
Interest expense, net	20,673	21,190	62,350	58,913
Impairment of proved oil and gas properties	0	105,057	0	576,540
Other (income) expense, net	462	499	1,640	1,568
Total Costs and Expenses	173,456	212,664	394,967	974,458
Income (Loss) Before Income Taxes	7,823	(101,487)	104,150	(674,695)
Income tax benefit	0	313	0	0
Net Income (loss)	7,823	(101,174)	104,150	(674,695)
Dividends on preferred stock	(2,249)	0	(2,249)	0
Net Income (Loss) Attributable to Common Shareholders	$ 5,574	$ (101,174)	$ 101,901	$ (674,695)
Net Income (Loss) Per Common Share
Income (loss) per share, basic (in dollars per share)	$ 0.07	$ (1.72)	$ 1.44	$ (11.49)
Income (loss) per share, diluted (in dollars per share)	$ 0.07	$ (1.72)	$ 1.43	$ (11.49)
Weighted Average Common Shares Outstanding
Basic (in shares)	81,053	58,945	70,728	58,705
Diluted (in shares)	81,138	58,945	71,147	58,705

XML

Consolidated Statements Of Shareholders' Equity - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]
BALANCE at Dec. 31, 2016	$ 23,458	$ 651	$ 1,665,891	$ (1,643,084)
BALANCE, shares at Dec. 31, 2016		65,132,499
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation expense	17,967		17,967
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	(28)	$ 8	(36)
Issuance of common stock upon grants of restricted stock awards, net of forfeitures, and vestings of restricted stock units and performance shares, shares		722,122
Sale of common stock, net of offering costs	222,378	$ 156	222,222
Common stock offerings, shares		15,600,000
Proceeds from Issuance of Warrants	23,003		23,003
Dividends on preferred stock	(2,249)		2,249
Net Income (loss)	104,150			104,150
BALANCE at Sep. 30, 2017	$ 388,679	$ 815	$ 1,926,798	$ (1,538,934)
BALANCE, shares at Sep. 30, 2017		81,454,621

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Net income (loss)	$ 104,150	$ (674,695)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	181,018	160,492
Impairment of proved oil and gas properties	0	576,540
(Gain) loss on derivatives, net	(27,004)	29,938
Cash received for derivative settlements, net	7,714	98,820
Stock-based compensation expense, net	8,462	30,834
Non-cash interest expense, net	2,961	3,105
Other, net	4,249	2,427
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(25,885)	1,768
Accounts payable	14,748	(20,294)
Accrued liabilities	11,970	(7,954)
Other assets and liabilities, net	(1,786)	(3,134)
Net cash provided by operating activities	280,597	197,847
Cash Flows From Investing Activities
Capital expenditures	(433,561)	(346,245)
Acquisitions of oil and gas properties	(692,006)	0
Proceeds from sales of oil and gas properties, net	18,212	15,331
Deposit for pending divestiture of oil and gas properties	6,200	0
Other, net	(3,804)	(661)
Net cash used in investing activities	(1,104,959)	(331,575)
Cash Flows From Financing Activities
Issuance of senior notes	250,000	0
Borrowings under credit agreement	1,311,875	510,116
Repayments of borrowings under credit agreement	(1,183,275)	(414,116)
Payments of debt issuance costs	(8,964)	(1,150)
Sale of common stock, net of offering costs	222,378	0
Sale of preferred stock, net of commitment fees and offerings costs	236,404	0
Dividends on preferred stock	(2,249)	0
Other, net	(909)	(805)
Net cash provided by financing activities	825,260	94,045
Dividends on preferred stock	2,249	0
Net Increase (Decrease) in Cash and Cash Equivalents	898	(39,683)
Cash and Cash Equivalents, Beginning of Period	4,194	42,918
Cash and Cash Equivalents, End of Period	$ 5,092	$ 3,235

XML

Nature Of Operations

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature Of Operations

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 gas 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 (“2016 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.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

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

Stock Compensation. 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, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by 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. 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 as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, this portion 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 are now required to be presented in cash flows from 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

Business Combinations. In January 2017, the 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) of assets or businesses. ASU 2017-01 is to be applied on a prospective basis 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.

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. 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 the same period. Companies are required to use a full retrospective approach, meaning 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 of cash flows and related disclosures upon adoption. The Company plans to adopt the guidance on the effective date of January 1, 2018.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. 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 the impact of ASU 2016-02 which includes an analysis of existing contracts, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements and current accounting policies 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. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. 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 ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, 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 of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 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 the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.

The Company is currently assessing 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 the requirements of the new standard. Appropriate changes to business processes, systems or controls will be implemented to support recognition and disclosure under the new standard. Although its assessment is in progress, the Company currently does not expect the adoption of ASU 2014-09 to have a material impact on its consolidated financial statements because existing contractual 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.

Net Income (Loss) Per Common Share

Supplemental net income (loss) 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 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. The 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:

	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

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Acquisitions

9 Months Ended

Sep. 30, 2017

Acquisitions [Abstract]

Acquisitions Disclosures

3. Acquisitions and Divestitures of Oil and Gas Properties

Acquisitions

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, Texas (the “ExL Properties”) for a purchase price of $648.0 million, 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, 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 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 payment (the “Contingent ExL Payment”) 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 determined that the Contingent ExL Payment is an embedded derivative and has reflected the liability at fair value in the consolidated financial statements. The fair value of the Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was $60.3 million and $52.3 million, respectively. 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 the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Payment was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, 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 presents the purchase price and the preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Preliminary Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	292,551
Unproved properties	443,194
Total oil and gas properties		$735,745
Total assets acquired		$735,851
Liabilities
Revenues and royalties payable		$5,036
Asset retirement obligations	153
Contingent ExL Payment	52,300
Total liabilities assumed		$57,489
Net Assets Acquired		$678,362

Included in the consolidated statements of operations for the three and nine months ended September 30, 2017 are total revenues of $14.0 million and income before income taxes of $11.4 million from the ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.

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 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
	(In thousands, except per share amounts)
Total revenues		$189,499		$115,065			$534,607		$305,074
Net Income (Loss) Attributable to Common Shareholders		$14,654		($106,598	)		$115,053		($688,902	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$0.18		($1.43	)		$1.63		($9.27	)
Diluted		$0.18		($1.43	)		$1.62		($9.27	)
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. On December 14, 2016, the Company completed its initial closing of the acquisition of oil and gas properties in the Eagle Ford Shale from Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation (the “Sanchez Acquisition”). The transaction had 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 price of $16.8 million was made for leases that were not conveyed to the Company. On January 9, 2017 and April 13, 2017, the Company paid $7.0 million and $9.8 million, respectively, for these outstanding leases when conveyed to 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 in the consolidated statements of operations for the three and nine months ended September 30, 2017 are total revenues of $9.1 million and $23.2 million, respectively, and income before income taxes of $4.0 million and $7.1 million, respectively, from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction through September 30, 2017.

Divestitures

Potential 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 Company could also receive 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, respectively (the “Contingent Utica Consideration”). The Contingent Utica Consideration will be zero 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.

Other Assets. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million. The proceeds from this sale were recognized as a reduction of proved oil and gas properties.

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Property And Equipment, Net

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Property And Equipment, Net

4. Property and Equipment, Net

As of September 30, 2017 and December 31, 2016, total property and equipment, net consisted of the following:

	September 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,452,201			$4,687,416
Accumulated depreciation, depletion and amortization and impairments	(3,569,626		)	(3,392,749		)
Proved properties, net	1,882,575			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	697,370			211,067
Capitalized interest	42,835			29,894
Total unproved properties, not being amortized	740,205			240,961
Other property and equipment	25,344			23,127
Accumulated depreciation	(14,806		)	(12,995		)
Other property and equipment, net	10,538			10,132
Total property and equipment, net		$2,633,318			$1,545,760

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

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Income Taxes

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

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 significant, unusual or infrequent items for which income taxes are computed and recorded 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.

The Company’s income tax (expense) benefit differs from the income tax (expense) benefit 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 for net operating losses 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 September 30, 2017, driven primarily by the impairments of proved oil 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 potential 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 as a result of current activity, partial releases of $3.3 million and $41.6 million, respectively, from the valuation allowance was recorded 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, the Company 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 during these periods.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its 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 the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.

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Long-Term Debt

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt

6. Long-Term Debt

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

	September 30, 2017			December 31, 2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$215,600			$87,000
7.50% Senior Notes due 2020	600,000			600,000
Unamortized premium for 7.50% Senior Notes	836			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(6,397		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,527		)	(9,454		)
8.25% Senior Notes due 2025	250,000			—
Unamortized debt issuance costs for 8.25% Senior Notes	(4,498		)	—
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,701,439			$1,325,418

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, had a borrowing base of $837.5 million, with an elected commitment amount of $800.0 million, and $215.6 million of borrowings outstanding at a weighted average interest rate of 3.45%. 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 have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

On May 4, 2017, 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 amendment to its credit agreement governing the revolving credit facility to, among other things (i) amend the calculation of certain financial covenants to provide that EBITDA will be calculated on an annualized basis as 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, (iii) amend the definition of “Disqualified Capital Stock” to provide, among other things, that the Preferred Stock does not constitute “Disqualified Capital Stock” for purposes of the revolving credit facility, (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, 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, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility. See “Note 14. Subsequent Events” for further details of the eleventh amendment.

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

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

Ratio of Outstanding Borrowings and Letters of Credit 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%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	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 after giving pro forma effect to EBITDA for material acquisitions and dispositions 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, the ratio of Total Debt to EBITDA was 3.09 to 1.00 and the Current Ratio was 2.20 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).

8.25% Senior Notes due 2025

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.

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

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, 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.

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Preferred Stock

9 Months Ended

Sep. 30, 2017

Preferred Stock [Abstract]

Preferred Stock

8. Preferred Stock

On June 28, 2017, the Company 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 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 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. 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 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 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

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 the issuance date, with $213.4 million allocated to the Preferred Stock and $23.0 million allocated to 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:

	Issuance Date Fair Value Assumptions
Exercise price	$16.08
Expected term (in years)	10.0
Expected volatility	62.9	%
Risk-free interest rate	2.2	%
Dividend yield	—	%

See “Note 11. Fair Value Measurements” for further discussion of the significant inputs used in the Preferred Stock and Warrants fair value calculations.

Preferred Stock Dividends and Accretion

In the third quarter of 2017, the Company declared and paid $2.2 million of dividends, in cash, to the holders of record of the Preferred Stock on September 1, 2017 for the period from issuance through September 15, 2017.

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Shareholders' Equity and Stock Incentive Plans

9 Months Ended

Sep. 30, 2017

Shareholders' Equity and Stock Incentive Plans [Abstract]

Shareholders' Equity and Share-based Payments

9. Shareholders’ Equity and Stock-Based Compensation

Increase in Authorized Common Shares

At the Company’s annual meeting 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 shares of common stock from 90,000,000 to 180,000,000.

Sale of Common Stock

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 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. 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, may be issued. 

As of September 30, 2017, there were 1,750,275 common shares remaining 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. Restricted 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:

	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.

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, the Company granted 342,440 SARs under the Cash SAR Plan with a grant date fair value of $12.00 per SAR, or $4.1 million, to certain employees and independent contractors as part of its annual grant of long-term equity incentive awards. All of these SARs contain a service condition and performance condition. The performance condition has been met.

The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the nine months ended September 30,2017:

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

Performance Shares. The Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. 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 performance period, the last day of which is also the vesting date. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of September 30, 2017, unrecognized compensation costs related to unvested performance shares 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.

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:

	Grant Date Fair Value Assumptions
Number of simulations	500,000
Expected term (in years)	2.98
Expected volatility	59.2	%
Risk-free interest rate	1.5	%
Dividend yield	—	%

Stock-Based Compensation Expense, Net.Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash and performance shares is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties.

The Company recognized the following stock-based compensation expense, net for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Restricted stock awards and units		$5,311			$5,487			$16,184			$23,079
Stock appreciation rights	429			3,361			(7,040		)	9,581
Performance shares	581			722			1,861			2,052
	6,321			9,570			11,005			34,712
Less: amounts capitalized to oil and gas properties	(1,455		)	(1,150		)	(2,543		)	(3,878		)
Total stock-based compensation expense, net		$4,866			$8,420			$8,462			$30,834

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Derivative Instruments

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

10. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, basis swaps, three-way collars and purchased and sold call options, which are described below.

Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes.

Basis Swaps: The 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 of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed 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 between the fixed 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. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. The Company has incurred premiums on certain of these contracts 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 ceiling price. The payment of 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. When the Company has entered into three-way collars which span multiple years, 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 derivative positions at weighted average contract prices as of September 30, 2017:

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

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

		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

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. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability 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.

Counterparties to the Company’s derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds the Company’s unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral.

Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, 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 derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties and its counterparty’s parent company, as applicable.

Contingent Consideration

The Company has entered into 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, the Company agreed to 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, 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 million in the consolidated financial statements. As of September 30, 2017, the estimated fair value of the Contingent ExL Payment was $60.3 million and was classified as non-current “Derivative liabilities” in the consolidated balance sheets.

Derivative Assets and Liabilities

All derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. The deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the Company’s consolidated balance sheets as of September 30, 2017 and December 31, 2016 are summarized below:

	September 30, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$11,571			($8,757	)		$2,814
Deferred premium obligations	—			(879		)	(879		)
Other current assets		$11,571			($9,636	)		$1,935
Commodity derivative instruments	10,415			(9,867		)	548
Deferred premium obligations	—			(423		)	(423		)
Other assets-non current		$10,415			($10,290	)		$125
Commodity derivative instruments		($9,143	)		$8,757			($386	)
Deferred premium obligations	(7,271		)	879			(6,392		)
Derivative liabilities-current		($16,414	)		$9,636			($6,778	)
Commodity derivative instruments	(13,711		)	9,867			(3,844		)
Deferred premium obligations	(13,463		)	423			(13,040		)
Contingent ExL Payment	(60,300		)	—			(60,300		)
Derivative liabilities-non current		($87,474	)		$10,290			($77,184	)

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Commodity derivative instruments	3,882			(3,882		)	—
Deferred premium obligations	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Commodity derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premium obligations	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premium obligations	(2,569		)	—			(2,569		)
Contingent ExL Payment	—			—			—
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

See “Note 11. Fair Value Measurements” for additional details 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 contingent consideration are recognized as (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations on the Company’s consolidated statements of operations for the three and nine months ended September 30,2017 and 2016 is summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$8,409			($8,309	)		($39,754	)		$12,006
Natural gas	(2,183		)	(3,490		)	(12,902		)	12,167
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

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as 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 and 2016 are summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$6,500			$23,165			$9,941			$104,549
Natural gas	522			—			(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

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 assets and liabilities measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016:

	September 30, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$3,362			$—
Derivative instrument liabilities		$—		($4,230	)		($60,300	)

	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$1,237			$—
Derivative instrument liabilities		$—		($45,552	)		$—

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 based on a third-party industry-standard pricing model using 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. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for 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 and 2016.

Contingent consideration. The Company determined that 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 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. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuation, including the related inputs, and analyzed changes in fair value measurements between periods. The fair value of the Contingent ExL Payment as of September 30, 2017 and August 10, 2017 was a liability of $60.3 million and $52.3 million, respectively. As a result, 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 3 for the nine months ended September 30,2017 and 2016. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 10. Derivative Instruments” for further details of the contingent consideration.

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

The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured on a nonrecurring basis on the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to 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. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

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

See “Note 8. Preferred Stock and Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants.

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. 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.

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$594,439		$610,500		$593,447		$624,750
6.25% Senior Notes due 2023	641,473		659,750		640,546		672,750
8.25% Senior Notes due 2025	245,502		269,375		—		—
Other long-term debt due 2028	4,425		4,408		4,425		4,419

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Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2017

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

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
	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
Total property and equipment, net	39,789			2,592,458			5,057		(3,986		)	2,633,318
Investment in subsidiaries	(1,097,703		)	—			—		1,097,703			—
Other assets	9,526			155			—		—			9,681
Total Assets		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726
Liabilities and Shareholders’ Equity
Current liabilities		$128,778			$3,687,474			$5,057		($3,502,870	)		$318,439
Long-term liabilities	1,716,898			92,431			—		15,879			1,825,208
Preferred stock	213,400			—			—		—			213,400
Total shareholders’ equity	405,524			(1,097,703		)	—		1,080,858			388,679
Total Liabilities and Shareholders’ Equity		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726

	December 31, 2016
	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
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	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 benefit	—			—		—		—			—
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		)
Net income attributable to common shareholders		$5,603			$61,878		$—		($61,907	)		$5,574

	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	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	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 benefit	—			—		—		—			—
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		)
Net income attributable to common shareholders		$101,971			$184,589		$—		($184,659	)		$101,901

	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	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30, 2017
	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
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
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$5,092			$—			$—		$—			$5,092

	Nine Months Ended September 30, 2016
	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
Net cash used in investing activities	(122,846		)	(331,351		)	(740		)	123,362			(331,575		)
Net cash provided by financing activities	94,045			122,622			740			(123,362		)	94,045
Net decrease in cash and cash equivalents	(39,683		)	—			—			—			(39,683		)
Cash and cash equivalents, beginning of period	42,918			—			—			—			42,918
Cash and cash equivalents, end of period		$3,235			$—			$—			$—			$3,235

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Elements [Abstract]

Cash Flow, Supplemental Disclosures

13. Supplemental Cash Flow Information

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

	Nine Months Ended September 30,
	2017		2016
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$59,389		$55,808
Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		$98,829		$7,316
Contingent ExL Payment	52,300		—
Stock-based compensation expense capitalized to oil and gas properties	2,543		3,878
Asset retirement obligations capitalized to oil and gas properties	2,761		766

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Subsequent Events

9 Months Ended

Sep. 30, 2017

Subsequent Events [Abstract]

Subsequent Events

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

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

Crude Oil Basis Swaps

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	6,000		$40.00		$49.00		$59.13
FY 2019	6,000		$40.00		$49.00		$59.14

Eleventh Amendment to the Credit Agreement

On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof, (ii) increase the general basket available for restricted payments from $50.0 million to $75.0 million and (iii) 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 and Delaware Basin assets.

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Summary of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

New Accounting Pronouncements

Recently Adopted Accounting Pronouncement

Stock Compensation. 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, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by 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. 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 as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, this portion 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 are now required to be presented in cash flows from 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

Business Combinations. In January 2017, the 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) of assets or businesses. ASU 2017-01 is to be applied on a prospective basis 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.

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. 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 the same period. Companies are required to use a full retrospective approach, meaning 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 of cash flows and related disclosures upon adoption. The Company plans to adopt the guidance on the effective date of January 1, 2018.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. 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 the impact of ASU 2016-02 which includes an analysis of existing contracts, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements and current accounting policies 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. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. 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 ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, 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 of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 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 the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements.

The Company is currently assessing 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 the requirements of the new standard. Appropriate changes to business processes, systems or controls will be implemented to support recognition and disclosure under the new standard. Although its assessment is in progress, the Company currently does not expect the adoption of ASU 2014-09 to have a material impact on its consolidated financial statements because existing contractual 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.

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Schedule of Supplemental Net Income Per Common Share

Supplemental net income (loss) 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	)

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The 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:

	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

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2017

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

Business Acquisition, Pro Forma Information [Table Text Block]

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 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
	(In thousands, except per share amounts)
Total revenues		$189,499		$115,065			$534,607		$305,074
Net Income (Loss) Attributable to Common Shareholders		$14,654		($106,598	)		$115,053		($688,902	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$0.18		($1.43	)		$1.63		($9.27	)
Diluted		$0.18		($1.43	)		$1.62		($9.27	)
Weighted Average Common Shares Outstanding
Basic	81,053		74,545			70,728		74,305
Diluted	81,138		74,545			71,147		74,305

ExL Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

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

	Preliminary Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	292,551
Unproved properties	443,194
Total oil and gas properties		$735,745
Total assets acquired		$735,851
Liabilities
Revenues and royalties payable		$5,036
Asset retirement obligations	153
Contingent ExL Payment	52,300
Total liabilities assumed		$57,489
Net Assets Acquired		$678,362

Sanchez Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

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

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Property And Equipment, Net (Tables)

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Schedule of Property and Equipment

As of September 30, 2017 and December 31, 2016, total property and equipment, net consisted of the following:

	September 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,452,201			$4,687,416
Accumulated depreciation, depletion and amortization and impairments	(3,569,626		)	(3,392,749		)
Proved properties, net	1,882,575			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	697,370			211,067
Capitalized interest	42,835			29,894
Total unproved properties, not being amortized	740,205			240,961
Other property and equipment	25,344			23,127
Accumulated depreciation	(14,806		)	(12,995		)
Other property and equipment, net	10,538			10,132
Total property and equipment, net		$2,633,318			$1,545,760

Schedule of Impairment of Oil and Gas Properties

etails 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	%)

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Schedule Of Effective Income Tax Rate Reconciliation

The Company’s income tax (expense) benefit differs from the income tax (expense) benefit 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			$—			$—

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

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

	September 30, 2017			December 31, 2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$215,600			$87,000
7.50% Senior Notes due 2020	600,000			600,000
Unamortized premium for 7.50% Senior Notes	836			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(6,397		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,527		)	(9,454		)
8.25% Senior Notes due 2025	250,000			—
Unamortized debt issuance costs for 8.25% Senior Notes	(4,498		)	—
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,701,439			$1,325,418

Interest and Commitment Fee Rates

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

Ratio of Outstanding Borrowings and Letters of Credit 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%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	0.500%

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Preferred Stock (Tables)

9 Months Ended

Sep. 30, 2017

Preferred Stock Disclosure [Abstract]

Schedule of Preferred Stock Dividends Paid in Common Stock

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 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	%

Schedule of Preferred Stock Redemption Premiums

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	%

Warrants, Valuation Assumptions

The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:

	Issuance Date Fair Value Assumptions
Exercise price	$16.08
Expected term (in years)	10.0
Expected volatility	62.9	%
Risk-free interest rate	2.2	%
Dividend yield	—	%

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Shareholders' Equity and Stock Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2017

Shareholders' Equity and Stock Incentive Plans [Abstract]

Schedule of Restricted Stock Awards and Restricted Stock Units Activity

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

	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

Schedule of Stock Appreciation Rights Award Activity

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		$—

Schedule of Stock Appreciation Rights Valuation Assumptions

The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the nine months ended September 30,2017:

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

Schedule of Performance Shares Award Unvested Activity

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

Schedule of Performance Share Award Valuation Assumptions

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:

	Grant Date Fair Value Assumptions
Number of simulations	500,000
Expected term (in years)	2.98
Expected volatility	59.2	%
Risk-free interest rate	1.5	%
Dividend yield	—	%

Schedule of Stock-based Compensation, net

The Company recognized the following stock-based compensation expense, net for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Restricted stock awards and units		$5,311			$5,487			$16,184			$23,079
Stock appreciation rights	429			3,361			(7,040		)	9,581
Performance shares	581			722			1,861			2,052
	6,321			9,570			11,005			34,712
Less: amounts capitalized to oil and gas properties	(1,455		)	(1,150		)	(2,543		)	(3,878		)
Total stock-based compensation expense, net		$4,866			$8,420			$8,462			$30,834

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position

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

	September 30, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$11,571			($8,757	)		$2,814
Deferred premium obligations	—			(879		)	(879		)
Other current assets		$11,571			($9,636	)		$1,935
Commodity derivative instruments	10,415			(9,867		)	548
Deferred premium obligations	—			(423		)	(423		)
Other assets-non current		$10,415			($10,290	)		$125
Commodity derivative instruments		($9,143	)		$8,757			($386	)
Deferred premium obligations	(7,271		)	879			(6,392		)
Derivative liabilities-current		($16,414	)		$9,636			($6,778	)
Commodity derivative instruments	(13,711		)	9,867			(3,844		)
Deferred premium obligations	(13,463		)	423			(13,040		)
Contingent ExL Payment	(60,300		)	—			(60,300		)
Derivative liabilities-non current		($87,474	)		$10,290			($77,184	)

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Commodity derivative instruments	3,882			(3,882		)	—
Deferred premium obligations	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Commodity derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premium obligations	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premium obligations	(2,569		)	—			(2,569		)
Contingent ExL Payment	—			—			—
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

Schedule of (Gain) Loss on Derivative Instruments

The effect of derivative instruments and deferred premium obligations on the Company’s consolidated statements of operations for the three and nine months ended September 30,2017 and 2016 is summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$8,409			($8,309	)		($39,754	)		$12,006
Natural gas	(2,183		)	(3,490		)	(12,902		)	12,167
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

Schedule Of Cash Received For Derivatives [Table Text Block]

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 and 2016 are summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$6,500			$23,165			$9,941			$104,549
Natural gas	522			—			(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

Crude Oil [Member] | Basis Swap [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

Crude Oil Basis Swaps

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

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

Crude Oil Basis Swaps

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

Crude Oil [Member] | Three-way Collars [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

Crude Oil Three-Way Collars

		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 Three-Way Collars

		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

Crude Oil [Member] | Swaps [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

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 [Member] | Call Option [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

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 [Member] | Swaps [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

Natural Gas Fixed Price Swaps

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

Natural Gas [Member] | Call Option [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

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

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016:

	September 30, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$3,362			$—
Derivative instrument liabilities		$—		($4,230	)		($60,300	)

	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$1,237			$—
Derivative instrument liabilities		$—		($45,552	)		$—

Schedule of Carrying Value and Estimated Fair Value of Debt Instruments

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.

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$594,439		$610,500		$593,447		$624,750
6.25% Senior Notes due 2023	641,473		659,750		640,546		672,750
8.25% Senior Notes due 2025	245,502		269,375		—		—
Other long-term debt due 2028	4,425		4,408		4,425		4,419

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Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2017

Condensed Consolidating Financial Information [Abstract]

Schedule Of Condensed Consolidating Balance Sheets

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)

	September 30, 2017
	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
Total property and equipment, net	39,789			2,592,458			5,057		(3,986		)	2,633,318
Investment in subsidiaries	(1,097,703		)	—			—		1,097,703			—
Other assets	9,526			155			—		—			9,681
Total Assets		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726
Liabilities and Shareholders’ Equity
Current liabilities		$128,778			$3,687,474			$5,057		($3,502,870	)		$318,439
Long-term liabilities	1,716,898			92,431			—		15,879			1,825,208
Preferred stock	213,400			—			—		—			213,400
Total shareholders’ equity	405,524			(1,097,703		)	—		1,080,858			388,679
Total Liabilities and Shareholders’ Equity		$2,464,600			$2,682,202			$5,057		($2,406,133	)		$2,745,726

	December 31, 2016
	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
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

Schedule Of Condensed Consolidating Statements Of Operations

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	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 benefit	—			—		—		—			—
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		)
Net income attributable to common shareholders		$5,603			$61,878		$—		($61,907	)		$5,574

	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	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	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 benefit	—			—		—		—			—
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		)
Net income attributable to common shareholders		$101,971			$184,589		$—		($184,659	)		$101,901

	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	)

Schedule Of Condensed Consolidating Statements Of Cash Flows

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30, 2017
	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
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
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$5,092			$—			$—		$—			$5,092

	Nine Months Ended September 30, 2016
	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
Net cash used in investing activities	(122,846		)	(331,351		)	(740		)	123,362			(331,575		)
Net cash provided by financing activities	94,045			122,622			740			(123,362		)	94,045
Net decrease in cash and cash equivalents	(39,683		)	—			—			—			(39,683		)
Cash and cash equivalents, beginning of period	42,918			—			—			—			42,918
Cash and cash equivalents, end of period		$3,235			$—			$—			$—			$3,235

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2017		2016
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$59,389		$55,808
Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		$98,829		$7,316
Contingent ExL Payment	52,300		—
Stock-based compensation expense capitalized to oil and gas properties	2,543		3,878
Asset retirement obligations capitalized to oil and gas properties	2,761		766

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Subsequent Events (Tables) - Crude Oil [Member]

9 Months Ended

Sep. 30, 2017

Basis Swap [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

Crude Oil Basis Swaps

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

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

Crude Oil Basis Swaps

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

Three-way Collars [Member]

Derivative [Line Items]

Schedule of Derivative Instruments

Crude Oil Three-Way Collars

		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 Three-Way Collars

		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

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Summary of Significant Accounting Policies (Narrative) (Details)	9 Months Ended
	Sep. 30, 2017 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions	$ 15,700,000
Tax Adjustments Retained Earnings Effect	$ 0.0

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Summary of Significant Accounting Policies (Schedule of Earnings Per Share Reconciliation) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
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	0	419	0
Diluted weighted average common shares outstanding	81,138	58,945	71,147	58,705
Net Income (Loss) - basic (in dollars per share)	$ 0.07	$ (1.72)	$ 1.44	$ (11.49)
Net Income (Loss) - diluted (in dollars per share)	$ 0.07	$ (1.72)	$ 1.43	$ (11.49)

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Summary of Significant Accounting Policies (Schedule of Antidilutive Shares Excluded from Earnings Per Share) (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Effect of dilutive instruments	85	0	419	0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	882	698	120	664

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Acquisitions (Narrative) (Details)	3 Months Ended			9 Months Ended
	Sep. 30, 2017 USD ($) $ / shares $ / bbls shares	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) $ / shares	Sep. 30, 2016 USD ($)	Aug. 31, 2017 USD ($)	Aug. 10, 2017 USD ($)	Jun. 28, 2017 USD ($)	Dec. 31, 2016 USD ($) $ / shares	Dec. 14, 2016 USD ($)
Business Acquisition [Line Items]
Payments to acquire oil and gas property				$ 692,006,000	$ 0
Business Combination, Contingent Consideration, Liability	$ 60,300,000			$ 60,300,000			$ 52,300,000
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 0.01			$ 0.01					$ 0.00
Issuance of warrants to purchase Common Stock | shares	2,750,000
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares	$ 16.08			16.08
Cash purchase price per share of Preferred Stock | $ / shares	$ 970.00			$ 970.00
Payment of commitment fee for pending issuance of preferred stock				$ 5,000,000
Deposit for pending divestiture of oil and gas properties				6,200,000	0
Proceeds from sales of oil and gas properties, net				18,212,000	$ 15,331,000
Senior Secured Revolving Credit Facility [Member]
Business Acquisition [Line Items]
Long-term Line of Credit	$ 215,600,000			215,600,000					$ 87,000,000
Sanchez Acquisition [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property		$ 9,800,000	$ 7,000,000
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	9,100,000			23,200,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	4,000,000			$ 7,100,000
Deferred Purchase Price										$ 16,800,000
ExL Acquisition [Member]
Business Acquisition [Line Items]
Agreed upon Purchase Price of Oil and Gas Property and Equipment	648,000,000
Payments to acquire oil and gas property	$ 601,000,000	$ 75,000,000
Contingent Consideration Arrangement, Threshold Price per Bbl for Additional Payments for Acquisition | $ / bbls	50.00
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High								$ 125,000,000
Percentage of Working Interest Subsequent to Acquisition	70.00%			70.00%
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual				$ 14,000,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual				$ 11,400,000
ExL Acquisition [Member] | Maximum [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Payments for Acquisition	$ 50,000,000
ExL Acquisition [Member] | Minimum [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Payments for Acquisition	0
Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High						$ 15,000,000
Sale Price of Oil and Gas Property and Equipment						$ 62,000,000
Deposit for pending divestiture of oil and gas properties	6,200,000
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	$ 5,000,000
Utica Shale Divestiture [Member] | FY 2018 [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls	50.00
Utica Shale Divestiture [Member] | FY 2019 [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls	53.00
Utica Shale Divestiture [Member] | FY 2020 [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls	56.00
Delaware Basin [Member]
Business Acquisition [Line Items]
Proceeds from sales of oil and gas properties, net			$ 15,300,000

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Acquisitions (Schedule of Consideration Paid for Assets Acquired and Liabilities Assumed) (Table) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Aug. 10, 2017	Dec. 14, 2016
Acquisitions - Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract]
Business Combination, Current Assets		$ 106	$ 477
Business Combination, Proved Oil and Gas Properties		292,551	99,938
Business Combination, Unproved Oil and Gas Properties		443,194	74,536
Business Combination, Oil and Gas Properties		735,745	174,474
Business Combination, Assets		735,851	174,951
Business Combination, Current Liabilities		5,036	1,442
Business Combination, Current Liabilities, Other			323
Business Combination, Noncurrent Liabilities		153	2,054
Business Combination, Contingent Consideration, Liability	$ 60,300	52,300
Business Combination, Noncurrent Liabilities, Other			1,078
Business Combination, Liabilities		57,489	4,897
Business Combination, Assets Acquired and Liabilities Assumed, Net		$ 678,362	$ 170,054

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Acquisitions Acquisitions (Pro Forma Information) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Acquisitions - Results of Operations [Abstract]
Business Acquisition, Pro Forma Revenue	$ 189,499	$ 115,065	$ 534,607	$ 305,074
Business Acquisition, Pro Forma Net Income (Loss)	$ 14,654	$ (106,598)	$ 115,053	$ (688,902)
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 0.18	$ (1.43)	$ 1.63	$ (9.27)
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 0.18	$ (1.43)	$ 1.62	$ (9.27)
Weighted Average Basic Shares Outstanding, Pro Forma	81,053	74,545	70,728	74,305
Pro Forma Weighted Average Shares Outstanding, Diluted	81,138	74,545	71,147	74,305

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Property and Equipment, Net (Narrative) (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) $ / Boe	Sep. 30, 2016 USD ($) $ / Boe	Sep. 30, 2017 USD ($) $ / Boe	Sep. 30, 2016 USD ($) $ / Boe
Property, Plant and Equipment [Line Items]
Average depreciation, depletion and amortization, per Boe | $ / Boe	13.04	12.72	12.73	13.79
Internal costs capitalized, Oil and Gas producing activities	$ 3.3	$ 2.7	$ 10.6	$ 8.5
Capitalized interest	$ 8.5	$ 2.9	$ 16.2	$ 13.4
Reserves discount factor			10.00%

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Property And Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Proved properties	$ 5,452,201	$ 4,687,416
Accumulated depreciation, depletion and amortization and impairments	(3,569,626)	(3,392,749)
Proved properties, net	1,882,575	1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	697,370	211,067
Capitalized interest	42,835	29,894
Total unproved properties, not being amortized	740,205	240,961
Other property and equipment	25,344	23,127
Accumulated depreciation	(14,806)	(12,995)
Other property and equipment, net	10,538	10,132
Total property and equipment, net	$ 2,633,318	$ 1,545,760

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Property and Equipment, Net (Schedule of Impairment of Oil and Gas Properties) (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) $ / bbls	Sep. 30, 2016 USD ($) $ / bbls	Sep. 30, 2017 USD ($) $ / bbls	Sep. 30, 2016 USD ($) $ / bbls	Jun. 30, 2017 $ / bbls	Dec. 31, 2016 $ / bbls	Jun. 30, 2016 $ / bbls	Dec. 31, 2015 $ / bbls
Impairment Of Oil And Gas Properties [Line Items]
Impairment of proved oil and gas properties | $	$ 0	$ 105,057	$ 0	$ 576,540
Change in price used in ceiling test calculation	2.00%	(4.00%)	21.00%	(19.00%)
Crude Oil [Member]
Impairment Of Oil And Gas Properties [Line Items]
Average Realized Price | $ / bbls	47.74	38.36	47.74	38.36	46.80	39.60	39.84	47.24

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Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Jan. 01, 2017
Income Taxes [Line Items]
U.S. federal statutory corporate pretax rate			35.00%
Deferred Tax Assets, Net	$ 0		$ 0
Tax Adjustments, Settlements, and Unusual Provisions			15,700,000
Tax Adjustments Retained Earnings Effect			0.0
Deferred Tax Assets, Valuation Allowance	(538,520,000)		(538,520,000)		$ (580,100,000)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	$ (3,253,000)	$ 36,696,000	$ (41,570,000)	$ 240,897,000

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
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)	0	(3,029)	0
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	3,253	(36,696)	41,570	(240,897)
Other	5	914	(115)	895
Income tax benefit	$ 0	$ 313	$ 0	$ 0

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Long-Term Debt (Narrative) (Details)	2 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) Rate	Nov. 03, 2017 USD ($)	Jul. 14, 2017 USD ($)	May 04, 2017 USD ($)	Dec. 31, 2016 USD ($)
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 900,000,000	$ 837,500,000	$ 600,000,000	$ 837,500,000
Line of Credit Facility, Elected Borrowing Capacity	800,000,000	800,000,000		800,000,000
Line of credit facility amount outstanding		$ 215,600,000		$ 215,600,000				$ 87,000,000
Debt, Weighted Average Interest Rate		3.45%		3.45%
Letters of credit outstanding amount		$ 415,000		$ 415,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000,000,000		$ 1,000,000,000
Ratio of total debt to EBITDA		3.09
Line of Credit Facility, Commitment Fee Percentage	0.375%		0.50%
Utilization of lender commitments	50.00%
Consolidated Cash Balance Threshold							$ 50,000,000
Credit Facility Availability Threshold							20.00%
Reduction of Borrowing Capacity due to Issuance of Senior Notes						25.00%
Pre-Tax SEC PV10 Reserve Value Percentage | Rate				90.00%
Federal funds rate plus percentage		0.50%		0.50%
Adjusted LIBO rate plus percentage		1.00%		1.00%
Current Ratio		2.20		2.20
Senior Secured Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA	4.00	4.00
Adjusted ratio of total debt to EBITDA							3.50
Senior Secured Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current Ratio		1.00		1.00
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.50%		7.50%
Long term debt		$ 600,000,000		$ 600,000,000				600,000,000
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						8.25%
Debt Instrument, Face Amount						$ 250,000,000
Proceeds from Issuance of Debt		245,400,000
Change of control repurchase price percentage						101.00%
Long term debt		$ 250,000,000		$ 250,000,000				$ 0
Subsequent Event [Member] | Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity					$ 900,000,000
Line of Credit Facility, Elected Borrowing Capacity					$ 800,000,000
Prior to July 15, 2020 [Member] | 8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount						100.00%
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount						106.188%
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount						100.00%

XML

Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 1,701,439	$ 1,325,418
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility amount outstanding	215,600	87,000
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Long term debt	600,000	600,000
Debt instrument, unamortized premium	836	1,020
Unamortized Debt Issuance Expense	(6,397)	(7,573)
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long term debt	650,000	650,000
Unamortized Debt Issuance Expense	(8,527)	(9,454)
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long term debt	250,000	0
Unamortized Debt Issuance Expense	(4,498)	0
Other Long Term Debt [Member]
Debt Instrument [Line Items]
Long term debt	$ 4,425	$ 4,425

XML

Long-Term Debt (Interest and Commitment Fee Rates) (Details)	9 Months Ended
	Sep. 30, 2017
Less than 25 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.00%
Margin for eurodollar loans	2.00%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Greater than or equal to 25 percent but less than 50 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.25%
Margin for eurodollar loans	2.25%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Greater than or equal to 50 percent but less than 75 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.50%
Margin for eurodollar loans	2.50%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Greater than or equal to 75 percent but less than 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.75%
Margin for eurodollar loans	2.75%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Greater than or equal to 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	2.00%
Margin for eurodollar loans	3.00%
Line of Credit Facility, Commitment Fee Percentage	0.50%

XML

Preferred Stock (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		8.875%
Preferred Stock, Percent of Ownership to be Able to Vote		50.00%
Preferred Stock, Prohibited Distributions		$ 15,000
Maximum Preferred Stock Shares Redeemable Within the First Year	50,000	50,000
Preferred Stock, Redemption Amount	$ 250,000	$ 250,000
Preferred Stock, Redemption Premium, Percentage		104.4375%
Preferred Stock, Shares Issued	250,000	250,000		0
Proceeds from Issuance of Preferred Stock and Preference Stock		$ 213,400
Dividends on preferred stock	$ 2,249	$ 2,249	$ 0
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01		$ 0.00
Issuance of warrants to purchase Common Stock	2,750,000
Class of Warrant or Right, Term	10 years
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 16.08	16.08
Cash purchase price per share of Preferred Stock	970.00	$ 970.00
Payment of Commitment Fees for Preferred Stock		$ (5,000)
Sale of preferred stock, net of commitment fees and offerings costs		$ 236,404	$ 0
Temporary Equity, Liquidation Preference Per Share	$ 1,000	$ 1,000
Proceeds from Issuance of Warrants		$ 23,003
On or before the seventh anniversary of the Preferred Stock Issuance Date [Domain]
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		12.00%
After August 10, 2024 [Domain]
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		12.00%
Libor Rate to Calculate Preferred Stock Dividend Rate		10.00%

XML

Preferred Stock (Schedule of Dividends Paid in Common Stock) (Details)	Sep. 30, 2017 Rate
Preferred Stock Dividend Paid in Common Stock First Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	100.00%
Preferred Stock Dividend Paid in Common Stock Second Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	75.00%
Preferred Stock Dividend Paid in Common Stock Third Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	50.00%

XML

Preferred Stock Preferred Stock (Schedule of Preferred Stock Redemption Premiums) (Details)	9 Months Ended
	Sep. 30, 2017
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	104.4375%
Preferred Stock Redemption Fourth Year [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	104.4375%
Preferred Stock Redemption Fifth Year [Member] [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	102.21875%
Preferred Stock Redemption Sixth Year [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	100.00%

XML

Preferred Stock (Warrants Valuation Assumptions) (Details)	9 Months Ended
	Sep. 30, 2017 $ / shares
Preferred Stock (Warrants Valuation Assumptions) [Abstract]
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 16.08
Fair Value Assumptions, Expected Term	10 years
Fair Value Assumptions, Expected Volatility Rate	62.90%
Fair Value Assumptions, Risk Free Interest Rate	2.20%
Fair Value Assumptions, Expected Dividend Rate	0.00%

XML

Shareholders' Equity and Stock Incentive Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Jul. 03, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares authorized (in shares)	180,000,000			180,000,000		90,000,000
Number of Shares Available for Grant	2,675,000			2,675,000
Ratio of stock based compensation shares to common shares				1.35
Common stock offerings, shares	15,600,000
Sale of Stock, Price Per Share							$ 14.28
Sale of common stock, net of offering costs	$ 222,400			$ 222,378	$ 0
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio of stock based compensation shares to common shares				1.00
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested Awards, Compensation Cost Not yet Recognized	26,300			$ 26,300
Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition				2 years 1 month 7 days
Granted Shares/Units		206,548		1,020,465
Fair Value of Shares Issued		$ 5,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period				629,397
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested Awards, Compensation Cost Not yet Recognized	1,300			$ 1,300
Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition				1 year 3 months 19 days
Fair Value of Shares Issued			$ 4,100
Liability For Cash Stock Appreciation Rights				$ 2,300		$ 11,500
Liability For Cash Stock Appreciation Rights, Classified As Other Accrued Liabilities				0		10,000
Liability For Cash Stock Appreciation Rights Remainder, Classified As Other Long Term Liabilities				$ 2,300		$ 1,500
SARs, Granted			342,440	342,440
Share-based Compensation Arrangement by Share-based Payment Award, Non-option, Grants in Period, Weight Average Grant Date Price			$ 12.00
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested Awards, Compensation Cost Not yet Recognized	$ 2,700			$ 2,700
Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition				1 year 9 months 19 days
Granted Shares/Units			46,787	46,787
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			$ 35.14
Fair Value of Shares Issued			$ 1,600
Vesting period, in years				3 years
Performance shares vested per TSR ranking			92,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			56,342	56,342
Vesting percentage of target performance shares granted			164.00%
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Rights Percentage Range				200.00%
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Rights Percentage Range				0.00%
Annual Grant of Long-Term Equity Incentive Awards [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted Shares/Units			695,658
Fair Value of Shares Issued			$ 18,800
Grant of Long-Term Equity Incentive Awards in Lieu of Annual Cash Bonus [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted Shares/Units			44,465
Fair Value of Shares Issued			$ 1,200
2017 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Available for Grant	1,750,275			1,750,275

XML

Shareholders' Equity and Stock Incentive Plans (Summary of Restricted Stock Award and Unit Activity) (Details) - Restricted Stock Awards And Units [Member] - $ / shares	3 Months Ended	9 Months Ended
	Jun. 30, 2017	Sep. 30, 2017
Restricted Stock Awards and Units [Abstract]
Unvested Shares/Units, Beginning of Period		1,111,710
Granted Shares/Units	206,548	1,020,465
Vested Shares/Units		(629,397)
Forfeited Shares/Units		(12,922)
Unvested Shares/Units, End of Period		1,489,856
Weighted Average Grant Date Fair Value [Abstract]
Grant Date Fair Value, Beginning of Period (USD per share)		$ 36.93
Granted, Grant Date Fair Value (USD per share)		25.63
Vested, Grant Date Fair Value (USD per share)		39.58
Forfeited, Grant Date Fair Value (USD per share)		29.11
Grant Date Fair Value, End of Period (USD per share)		$ 28.14

XML

Shareholders' Equity and Stock Incentive Plans (Summary of SARs Activity) (Details) - Stock Appreciation Rights (SARs) [Member] - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2017	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
SARs, Outstanding, Beginning of period	722,638	722,638
SARs, Granted	342,440	342,440
SARs, Exercised		(219,279)
SARs, Forfeitures		0
SARs, Expirations		131,561
SARs, Outstanding, End of period		714,238
SARs, Vested, End of Period		185,899
SARs, Exercisable, End of Period		0
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Weighted Average Exercise Price [Roll Forward]
Weighted Average Exercise Prices, Outstanding, Beginning of Period	$ 23.69	$ 23.69
Weighted Average Exercise Prices, Granted		26.94
Weighted Average Exercise Prices, Exercised		17.28
Weighted Average Exercise Prices, Forfeitures		0.00
Weighted Average Exercise Prices, Expired		24.19
Weighted Average Exercise Prices, Outstanding, End of Period		27.12
Weighted Average Exercise Prices, Vested, End of Period		27.30
Weighted Average Exercise Prices, Exercisable, End of Period		$ 27.30
Cash paid at exercises, Stock Appreciation Rights		$ 2.1
Weighted Average Remaining Life, Outstanding, End of Period		4 years
Weighted Average Remaining Life, Exercisable, End of Period		3 years 6 months
Aggregate Intrinsic Value, Outstanding, End of Period		$ 0.0
Aggregate Intrinsic Value, Exercisable, End of Period		$ 0.0

XML

Shareholders' Equity and Stock Incentive Plans (Summary of SARs Fair Value Assumptions) (Details) - Stock Appreciation Rights (SARs) [Member]	9 Months Ended
	Sep. 30, 2017 Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Term	4 years 2 months 26 days
Expected Volatility Rate	54.30%
Risk-free Interest Rate	1.80%
Dividend Yield	0.00%

XML

Shareholders' Equity and Stock Incentive Plans (Summary of Performance Share Award Activity) (Details) - Performance Shares [Member] - $ / shares	3 Months Ended	9 Months Ended
	Mar. 31, 2017	Sep. 30, 2017
Performance Share Awards
Unvested Shares/Units, Beginning of Period	154,510	154,510
Granted Shares/Units	46,787	46,787
Vested Shares/Units	(56,342)	(56,342)
Forfeited Shares/Units		0
Unvested Shares/Units, End of Period		144,955
Weighted Average Grant Date Fair Value [Abstract]
Grant Date Fair Value, Beginning of Period (USD per share)	$ 58.44	$ 58.44
Granted, Grant Date Fair Value (USD per share)		35.14
Vested, Grant Date Fair Value (USD per share)		68.15
Forfeited, Grant Date Fair Value (USD per share)		0.00
Grant Date Fair Value, End of Period (USD per share)		$ 47.14

XML

Shareholders' Equity and Stock Incentive Plans (Summary of Performance Share Awards Fair Value Assumptions) (Details) - Performance Shares [Member]	9 Months Ended
	Sep. 30, 2017 Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of simulations performed	500,000
Expected Term	2 years 11 months 23 days
Expected Volatility Rate	59.20%
Risk-free Interest Rate	1.50%
Dividend Yield	0.00%

XML

Shareholders' Equity and Stock Incentive Plans (Schedule of Share-Based Compensation Expense) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Allocated Share-based Compensation Expense	$ 6,321	$ 9,570	$ 11,005	$ 34,712
Less: amounts capitalized	(1,455)	(1,150)	(2,543)	(3,878)
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	4,866	8,420	8,462	30,834
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Allocated Share-based Compensation Expense	5,311	5,487	16,184	23,079
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Allocated Share-based Compensation Expense	429	3,361	(7,040)	9,581
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Allocated Share-based Compensation Expense	$ 581	$ 722	$ 1,861	$ 2,052

XML

Derivative Instruments (Narrative) (Details) $ in Thousands	3 Months Ended
	Sep. 30, 2017 USD ($) bbl / d $ / bbls	Aug. 10, 2017 USD ($)	Jun. 28, 2017 USD ($)	Sep. 30, 2016 USD ($)
Derivative [Line Items]
Contingent Consideration, Liability, Acquisition Date Fair Value | $	$ 52,300	$ 52,300		$ 0
Business Combination, Contingent Consideration, Liability | $	$ 60,300	$ 52,300
Three-way Collars [Member] | FY 2018 [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	18,000
Weighted Average Floor Price ($/Bbls) | $ / bbls	49.08
Weighted Average Ceiling Price ($/Bbls) | $ / bbls	60.48
Swaps [Member] | FY 2018 [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Weighted Average Floor Price ($/Bbls) | $ / bbls	49.55
ExL Acquisition [Member]
Derivative [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High | $			$ 125,000
Contingent Consideration Arrangement, Threshold Price per Bbl for Additional Payments for Acquisition | $ / bbls	50.00
ExL Acquisition [Member] | Maximum [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Potential Additional Payments for Acquisition | $	$ 50,000

XML

Derivative Instruments (Schedule of Crude Oil Derivative Positions) (Details) - Crude Oil [Member]	Nov. 06, 2017 bbl / d $ / bbls	Oct. 30, 2017 bbl / d $ / bbls	Oct. 26, 2017 bbl / d $ / bbls	Sep. 30, 2017 bbl / d $ / bbls
Swaps [Member] | Q4 2017 [Domain]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				15,000
Weighted Average Floor Price ($/Bbls)				53.44
Swaps [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				6,000
Weighted Average Floor Price ($/Bbls)				49.55
Basis Swap [Member] | Q4 2017 [Domain]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				15,000
Weighted Average Floor Price ($/Bbls)				4.13
Basis Swap [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				6,000
Weighted Average Floor Price ($/Bbls)				2.91
Three-way Collars [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				18,000
Weighted Average Sub-Floor Price ($/Bbls)				39.17
Weighted Average Floor Price ($/Bbls)				49.08
Weighted Average Ceiling Price ($/Bbls)				60.48
Three-way Collars [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				6,000
Weighted Average Sub-Floor Price ($/Bbls)				40.00
Weighted Average Floor Price ($/Bbls)				47.80
Weighted Average Ceiling Price ($/Bbls)				61.45
Call Option [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				3,388
Weighted Average Ceiling Price ($/Bbls)				71.33
Call Option [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				3,875
Weighted Average Ceiling Price ($/Bbls)				73.66
Call Option [Member] | FY 2020 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				4,575
Weighted Average Ceiling Price ($/Bbls)				75.98
Subsequent Event [Member] | Basis Swap [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			6,000
Weighted Average Floor Price ($/Bbls)			(0.10)
Subsequent Event [Member] | Three-way Collars [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		6,000
Weighted Average Sub-Floor Price ($/Bbls)		40.00
Weighted Average Floor Price ($/Bbls)		49.00
Weighted Average Ceiling Price ($/Bbls)		59.13
Subsequent Event [Member] | Three-way Collars [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Weighted Average Sub-Floor Price ($/Bbls)	40.00
Weighted Average Floor Price ($/Bbls)	49.00
Weighted Average Ceiling Price ($/Bbls)	59.14

XML

Derivative Instruments (Schedule of Natural Gas Derivative Positions) (Details) - Natural Gas [Member]	Sep. 30, 2017 MMBTU / d $ / MMBTU
Swaps [Member] | Q4 2017 [Domain]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	20,000
Weighted Average Floor Price ($/MMBtu) | $ / MMBTU	3.30
Call Option [Member] | Q4 2017 [Domain]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.00
Call Option [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
Call Option [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
Call Option [Member] | FY 2020 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.50

XML

Derivative Instruments (Schedule of Derivative Instruments in Statement of Financial Position) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets, current
Derivative liabilities, current	(6,778)	(22,601)
Derivative liabilities, noncurrent	(77,184)	(27,528)
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	11,571	7,990
Derivative Asset, Deferred Premiums, Gross Asset	0	0
Derivative Asset, Gross Asset	11,571	7,990
Derivative Asset, Fair Value, Gross Liability	(8,757)	(6,753)
Derivative Asset, Deferred Premiums, Gross Liability	(879)	0
Derivative Asset, Gross Liability	(9,636)	(6,753)
Derivative, Fair Value, Net	2,814	1,237
Derivative Deferred Premium, Net	(879)	0
Derivative assets, current	1,935	1,237
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,415	3,882
Derivative Asset, Deferred Premiums, Gross Asset	0	0
Derivative Asset, Gross Asset	10,415	3,882
Derivative Asset, Fair Value, Gross Liability	(9,867)	(3,882)
Derivative Asset, Deferred Premiums, Gross Liability	(423)	0
Derivative Asset, Gross Liability	(10,290)	(3,882)
Derivative, Fair Value, Net	548	0
Derivative Deferred Premium, Net	(423)	0
Derivative assets, noncurrent	125	0
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	(386)	(20,593)
Derivative Deferred Premium, Net	(6,392)	(2,008)
Derivative Liability, Fair Value, Gross Liability	(9,143)	(27,346)
Derivative Liability, Deferred Premiums, Gross Liability	(7,271)	(2,008)
Derivative Liability, Gross Liability	(16,414)	(29,354)
Derivative Liability, Fair Value, Gross Asset	8,757	6,753
Derivative Liability, Deferred Premiums, Gross Asset	879	0
Derivative Liability, Gross Asset	9,636	6,753
Derivative liabilities, current	(6,778)	(22,601)
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	(3,844)	(24,959)
Derivative Deferred Premium, Net	(13,040)	(2,569)
Business Combination, Contingent Consideration, Liability	(60,300)	0
Derivative Liability, Fair Value, Gross Liability	(13,711)	(28,841)
Derivative Liability, Deferred Premiums, Gross Liability	(13,463)	(2,569)
Derivative Liability, Contingent Payment, Gross Liability	(60,300)	0
Derivative Liability, Gross Liability	(87,474)	(31,410)
Derivative Liability, Fair Value, Gross Asset	9,867	3,882
Derivative Liability, Deferred Premiums, Gross Asset	(423)	0
Derivative Liability, Contingent Payment, Gross Asset	0	0
Derivative Liability, Gross Asset	10,290	3,882
Derivative liabilities, noncurrent	$ (77,184)	$ (27,528)

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Derivative Instruments (Schedule of (Gain) Loss on Derivative Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Gain (Loss), Commodity [Line Items]
(Gain) loss on derivatives, net	$ 24,377	$ (11,744)	$ (27,004)	$ 29,938
Gain (Loss) on Embedded Derivative, Net	8,000	0	8,000	0
Crude Oil [Member]
Derivative Instruments, Gain (Loss), Commodity [Line Items]
(Gain) loss on derivatives, net	8,409	(8,309)	(39,754)	12,006
Natural Gas [Member]
Derivative Instruments, Gain (Loss), Commodity [Line Items]
(Gain) loss on derivatives, net	(2,183)	(3,490)	(12,902)	12,167
Deferred Premiums On Derivative Instruments [Member]
Derivative Instruments, Gain (Loss), Commodity [Line Items]
(Gain) loss on derivatives, net	$ 10,151	$ 55	$ 17,652	$ 5,765

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Derivative Instruments Derivative Instruments (Schedule of Cash Received for Derivative Settlements) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule Of Cash Received For Derivatives [Line Items]
Cash received for derivative settlements, net	$ 6,456	$ 20,357	$ 7,714	$ 98,820
Net Cash Received Paid For Embedded Derivative	0	0	0	0
Crude Oil [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Cash received for derivative settlements, net	6,500	23,165	9,941	104,549
Natural Gas [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Cash received for derivative settlements, net	522	0	(731)	0
Deferred Premiums On Derivative Instruments [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Cash received for derivative settlements, net	$ (566)	$ (2,808)	$ (1,496)	$ (5,729)

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Fair Value Measurements (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Aug. 10, 2017
Fair Value Disclosures [Abstract]
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount		$ 0		$ 0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount	$ 0	0	$ 0	0
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	0	0	0	0
Business Combination, Contingent Consideration, Liability	60,300,000		60,300,000		$ 52,300,000
Gain (Loss) on Embedded Derivative, Net	$ 8,000,000	$ 0	$ 8,000,000	$ 0

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Fair Value Measurements (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 0	$ 0
Derivative Liability	0	0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	3,362	1,237
Derivative Liability	(4,230)	(45,552)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	$ (60,300)	$ 0

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Fair Value Measurements (Schedule of Carrying Value and Estimated Fair Value of Debt Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
7.50% Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	$ 600,000	$ 600,000
7.50% Senior Notes [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	594,439	593,447
7.50% Senior Notes [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	610,500	624,750
6.25% Senior Notes [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	641,473	640,546
6.25% Senior Notes [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	659,750	672,750
8.25% Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	250,000	0
8.25% Senior Notes [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	245,502	0
8.25% Senior Notes [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	269,375	0
Other Long Term Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	4,425	4,425
Other Long Term Debt [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	4,425	4,425
Other Long Term Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long term debt	$ 4,408	$ 4,419

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Condensed Consolidating Financial Information (Narrative) (Details)	Sep. 30, 2017
Condensed Consolidating Financial Information [Abstract]
Voting interest of the subsidiary owned by the registrant	100.00%

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Condensed Balance Sheet Statements, Captions [Line Items]
Total current assets	$ 102,727,000	$ 72,988,000
Total property and equipment, net	2,633,318,000	1,545,760,000
Investment in subsidiaries	0	0
Other assets	9,681,000	7,579,000
Total Assets	2,745,726,000	1,626,327,000
Current liabilities	318,439,000	211,959,000
Long-term liabilities	1,825,208,000	1,390,910,000
Preferred Stock	213,400,000	0
Total shareholders’ equity	388,679,000	23,458,000
Total Liabilities and Shareholders’ Equity	2,745,726,000	1,626,327,000
Eliminations [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Total current assets	(3,499,850,000)	(2,726,355,000)
Total property and equipment, net	(3,986,000)	(3,916,000)
Investment in subsidiaries	1,097,703,000	1,282,292,000
Other assets	0	0
Total Assets	(2,406,133,000)	(1,447,979,000)
Current liabilities	(3,502,870,000)	(2,729,375,000)
Long-term liabilities	15,879,000	15,878,000
Preferred Stock	0	0
Total shareholders’ equity	1,080,858,000	1,265,518,000
Total Liabilities and Shareholders’ Equity	(2,406,133,000)	(1,447,979,000)
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Total current assets	3,512,988,000	2,735,830,000
Total property and equipment, net	39,789,000	42,181,000
Investment in subsidiaries	(1,097,703,000)	(1,282,292,000)
Other assets	9,526,000	7,423,000
Total Assets	2,464,600,000	1,503,142,000
Current liabilities	128,778,000	114,805,000
Long-term liabilities	1,716,898,000	1,348,105,000
Preferred Stock	213,400,000	0
Total shareholders’ equity	405,524,000	40,232,000
Total Liabilities and Shareholders’ Equity	2,464,600,000	1,503,142,000
Combined Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Total current assets	89,589,000	63,513,000
Total property and equipment, net	2,592,458,000	1,503,695,000
Investment in subsidiaries	0	0
Other assets	155,000	156,000
Total Assets	2,682,202,000	1,567,364,000
Current liabilities	3,687,474,000	2,822,729,000
Long-term liabilities	92,431,000	26,927,000
Preferred Stock	0	0
Total shareholders’ equity	(1,097,703,000)	(1,282,292,000)
Total Liabilities and Shareholders’ Equity	2,682,202,000	1,567,364,000
Combined Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Total current assets	0	0
Total property and equipment, net	5,057,000	3,800,000
Investment in subsidiaries	0	0
Other assets	0	0
Total Assets	5,057,000	3,800,000
Current liabilities	5,057,000	3,800,000
Long-term liabilities	0	0
Preferred Stock	0	0
Total shareholders’ equity	0	0
Total Liabilities and Shareholders’ Equity	$ 5,057,000	$ 3,800,000

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Condensed Income Statements, Captions [Line Items]
Total revenues	$ 181,279	$ 111,177	$ 499,117	$ 299,763
Total costs and expenses	173,456	212,664	394,967	974,458
Income (loss) before income taxes	7,823	(101,487)	104,150	(674,695)
Income tax (expense) benefit	0	313	0	0
Equity (deficit) in income of subsidiaries	0	0	0	0
Net Income (loss)	7,823	(101,174)	104,150	(674,695)
Dividends on preferred stock	(2,249)	0	(2,249)	0
Net Income (Loss) Attributable to Common Shareholders	5,574	(101,174)	101,901	(674,695)
Eliminations [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	0	0	0	0
Total costs and expenses	29	66	70	431
Income (loss) before income taxes	(29)	(66)	(70)	(431)
Income tax (expense) benefit	0	313	0	0
Equity (deficit) in income of subsidiaries	(61,878)	72,975	(184,589)	523,168
Net Income (loss)	(61,907)	73,222	(184,659)	522,737
Dividends on preferred stock	0	0	0	0
Net Income (Loss) Attributable to Common Shareholders	(61,907)	73,222	(184,659)	522,737
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	35	105	291	349
Total costs and expenses	54,061	28,551	80,660	151,445
Income (loss) before income taxes	(54,026)	(28,446)	(80,369)	(151,096)
Income tax (expense) benefit	0	0	0	0
Equity (deficit) in income of subsidiaries	61,878	(72,975)	184,589	(523,168)
Net Income (loss)	7,852	(101,421)	104,220	(674,264)
Dividends on preferred stock	2,249	0	2,249	0
Net Income (Loss) Attributable to Common Shareholders	5,603	(101,421)	101,971	(674,264)
Combined Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	181,244	111,072	498,826	299,414
Total costs and expenses	119,366	184,047	314,237	822,582
Income (loss) before income taxes	61,878	(72,975)	184,589	(523,168)
Income tax (expense) benefit	0	0	0	0
Equity (deficit) in income of subsidiaries	0	0	0	0
Net Income (loss)	61,878	(72,975)	184,589	(523,168)
Dividends on preferred stock	0	0	0	0
Net Income (Loss) Attributable to Common Shareholders	61,878	(72,975)	184,589	(523,168)
Combined Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Income Statements, Captions [Line Items]
Total revenues	0	0	0	0
Total costs and expenses	0	0	0	0
Income (loss) before income taxes	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Equity (deficit) in income of subsidiaries	0	0	0	0
Net Income (loss)	0	0	0	0
Dividends on preferred stock	0	0	0	0
Net Income (Loss) Attributable to Common Shareholders	$ 0	$ 0	$ 0	$ 0

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 280,597	$ 197,847
Net cash provided by (used in) investing activities	(1,104,959)	(331,575)
Net cash provided by (used in) financing activities	825,260	94,045
Net Increase (Decrease) in Cash and Cash Equivalents	898	(39,683)
Cash and Cash Equivalents, Beginning of Period	4,194	42,918
Cash and Cash Equivalents, End of Period	5,092	3,235
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	0	0
Net cash provided by (used in) investing activities	726,029	123,362
Net cash provided by (used in) financing activities	(726,029)	(123,362)
Net Increase (Decrease) in Cash and Cash Equivalents	0	0
Cash and Cash Equivalents, Beginning of Period	0	0
Cash and Cash Equivalents, End of Period	0	0
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(95,529)	(10,882)
Net cash provided by (used in) investing activities	(728,833)	(122,846)
Net cash provided by (used in) financing activities	825,260	94,045
Net Increase (Decrease) in Cash and Cash Equivalents	898	(39,683)
Cash and Cash Equivalents, Beginning of Period	4,194	42,918
Cash and Cash Equivalents, End of Period	5,092	3,235
Combined Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	376,126	208,729
Net cash provided by (used in) investing activities	(1,102,155)	(331,351)
Net cash provided by (used in) financing activities	726,029	122,622
Net Increase (Decrease) in Cash and Cash Equivalents	0	0
Cash and Cash Equivalents, Beginning of Period	0	0
Cash and Cash Equivalents, End of Period	0	0
Combined Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	0	0
Net cash provided by (used in) investing activities	0	(740)
Net cash provided by (used in) financing activities	0	740
Net Increase (Decrease) in Cash and Cash Equivalents	0	0
Cash and Cash Equivalents, Beginning of Period	0	0
Cash and Cash Equivalents, End of Period	$ 0	$ 0

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Supplemental Cash Flow Information (Supplemental Cash Flow Disclosures) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Aug. 10, 2017
Supplemental Cash Flow Elements [Abstract]
Interest Paid, Net			$ 59,389	$ 55,808
Change in capital expenditure payables and accruals			98,829	7,316
Contingent Consideration, Liability, Acquisition Date Fair Value	$ 52,300	$ 0	52,300	0	$ 52,300
Stock-based compensation expense capitalized to oil and gas properties	$ 1,455	$ 1,150	2,543	3,878
Asset retirements obligations capitalized to oil and gas properties			$ 2,761	$ 766

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Subsequent Events (Narrative) (Details)	3 Months Ended	9 Months Ended
	Dec. 31, 2017 USD ($) $ / MMBTU	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Nov. 03, 2017 USD ($)	Oct. 05, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)
Subsequent Event [Line Items]
Deposit for pending divestiture of oil and gas properties		$ 6,200,000	$ 0
Senior Secured Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity		837,500,000				$ 900,000,000	$ 600,000,000
Line of Credit Facility, Elected Borrowing Capacity		800,000,000				$ 800,000,000
Restricted Payments Basket		$ 50,000,000
Senior Secured Revolving Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 900,000,000
Line of Credit Facility, Elected Borrowing Capacity				800,000,000
Restricted Payments Basket				$ 75,000,000
Marcellus Shale Divestiture [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Sale Price of Oil and Gas Property and Equipment	$ 84,000,000
Deposit for pending divestiture of oil and gas properties	6,300,000
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	3,000,000
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High					$ 7,500,000
Marcellus Shale Divestiture [Member] | Minimum [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	$ 0
Marcellus Shale Divestiture [Member] | FY 2018 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Contingent Consideration Arrangement, Threshold Price per MMBtu for Additional Payments from Divestiture | $ / MMBTU	3.13
Marcellus Shale Divestiture [Member] | FY 2019 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Contingent Consideration Arrangement, Threshold Price per MMBtu for Additional Payments from Divestiture | $ / MMBTU	3.18
Marcellus Shale Divestiture [Member] | FY 2020 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Contingent Consideration Arrangement, Threshold Price per MMBtu for Additional Payments from Divestiture | $ / MMBTU	3.30

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Subsequent Events, Derivative Instruments (Schedule of Crude Oil Derivative Positions) (Details) - Crude Oil [Member]	Nov. 06, 2017 bbl / d $ / bbls	Oct. 30, 2017 bbl / d $ / bbls	Oct. 26, 2017 bbl / d $ / bbls	Sep. 30, 2017 bbl / d $ / bbls
Three-way Collars [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				18,000
Weighted Average Sub-Floor Price ($/Bbls)				39.17
Weighted Average Floor Price ($/Bbls)				49.08
Weighted Average Ceiling Price ($/Bbls)				60.48
Three-way Collars [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				6,000
Weighted Average Sub-Floor Price ($/Bbls)				40.00
Weighted Average Floor Price ($/Bbls)				47.80
Weighted Average Ceiling Price ($/Bbls)				61.45
Basis Swap [Member] | Q4 2017 [Domain]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				15,000
Weighted Average Floor Price ($/Bbls)				4.13
Basis Swap [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				6,000
Weighted Average Floor Price ($/Bbls)				2.91
Swaps [Member] | Q4 2017 [Domain]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				15,000
Weighted Average Floor Price ($/Bbls)				53.44
Swaps [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				6,000
Weighted Average Floor Price ($/Bbls)				49.55
Call Option [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				3,388
Weighted Average Ceiling Price ($/Bbls)				71.33
Call Option [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d				3,875
Weighted Average Ceiling Price ($/Bbls)				73.66
Subsequent Event [Member] | Three-way Collars [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		6,000
Weighted Average Sub-Floor Price ($/Bbls)		40.00
Weighted Average Floor Price ($/Bbls)		49.00
Weighted Average Ceiling Price ($/Bbls)		59.13
Subsequent Event [Member] | Three-way Collars [Member] | FY 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
Weighted Average Sub-Floor Price ($/Bbls)	40.00
Weighted Average Floor Price ($/Bbls)	49.00
Weighted Average Ceiling Price ($/Bbls)	59.14
Subsequent Event [Member] | Basis Swap [Member] | FY 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			6,000
Weighted Average Floor Price ($/Bbls)			(0.10)