Edgar Filing: CARRIZO OIL & GAS INC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________

FORM 10-Q

_________________________________________________



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

For the quarterly period ended June 30, 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 August 4, 2017 was 81,441,862.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016	2
	Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016	3
	Consolidated Statement of Shareholders’ Equity for the six months ended June 30, 2017	4
	Consolidated Statements of Cash Flows for the six months ended June 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	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43
Part II. Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	45
Signatures		47

Part I. Financial Information

Item 1. Consolidated Financial Statements (Unaudited)

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)



	June 30, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents		$2,228			$4,194
Accounts receivable, net	72,401			64,208
Derivative assets	15,283			1,237
Other current assets	5,486			3,349
Total current assets	95,398			72,988
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,475,131			1,294,667
Unproved properties, not being amortized	288,997			240,961
Other property and equipment, net	9,031			10,132
Total property and equipment, net	1,773,159			1,545,760
Deposit for pending acquisition of oil and gas properties	75,000			—
Other assets	20,262			7,579
Total Assets		$1,963,819			$1,626,327

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$68,215			$55,631
Revenues and royalties payable	45,860			38,107
Accrued capital expenditures	80,435			36,594
Accrued interest	22,076			22,016
Accrued lease operating expense	14,732			12,377
Derivative liabilities	2,012			22,601
Other current liabilities	25,730			24,633
Total current liabilities	259,060			211,959
Long-term debt	1,521,986			1,325,418
Asset retirement obligations	22,731			20,848
Derivative liabilities	13,652			27,528
Other liabilities	14,559			17,116
Total liabilities	1,831,988			1,602,869
Commitments and contingencies
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 65,835,820 issued and outstanding as of June 30, 2017 and 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016	658			651
Additional paid-in capital	1,677,930			1,665,891
Accumulated deficit	(1,546,757		)	(1,643,084		)
Total shareholders’ equity	131,831			23,458
Total Liabilities and Shareholders’ Equity		$1,963,819			$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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues
Crude oil		$142,806			$91,608			$270,898			$159,604
Natural gas liquids	7,786			6,063			15,211			9,503
Natural gas	15,891			9,653			31,729			19,479
Total revenues	166,483			107,324			317,838			188,586

Costs and Expenses
Lease operating	36,048			23,114			65,893			46,789
Production taxes	7,143			4,623			13,351			8,054
Ad valorem taxes	1,073			454			4,040			2,524
Depreciation, depletion and amortization	59,072			51,966			113,454			111,543
General and administrative, net	11,596			19,624			33,299			40,927
(Gain) loss on derivatives, net	(26,065		)	52,235			(51,381		)	41,682
Interest expense, net	21,106			19,010			41,677			37,723
Impairment of proved oil and gas properties	—			197,070			—			471,483
Other (income) expense, net	204			1,162			1,178			1,069
Total costs and expenses	110,177			369,258			221,511			761,794

Income (Loss) Before Income Taxes	56,306			(261,934		)	96,327			(573,208		)
Income tax expense	—			(192		)	—			(313		)
Net Income (Loss)		$56,306			($262,126	)		$96,327			($573,521	)

Net Income (Loss) Per Common Share
Basic		$0.86			($4.46	)		$1.47			($9.79	)
Diluted		$0.85			($4.46	)		$1.46			($9.79	)

Weighted Average Common Shares Outstanding
Basic	65,767			58,806			65,479			58,583
Diluted	65,908			58,806			65,866			58,583

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		Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of December 31, 2016	65,132,499		$651		$1,665,891			($1,643,084	)		$23,458
Stock-based compensation expense	—	—		12,063			—			12,063
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	703,321	7		(24		)	—			(17		)
Net income	—	—		—			96,327			96,327
Balance as of June 30, 2017	65,835,820		$658		$1,677,930			($1,546,757	)		$131,831

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)



	Six Months Ended June 30,
	2017			2016
Cash Flows From Operating Activities
Net income (loss)		$96,327			($573,521	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	113,454			111,543
Impairment of proved oil and gas properties	—			471,483
(Gain) loss on derivatives, net	(51,381		)	41,682
Cash received for derivative settlements, net	1,258			78,463
Stock-based compensation expense, net	3,596			22,414
Non-cash interest expense, net	2,074			2,064
Other, net	2,767			2,342
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(8,094		)	(1,392		)
Accounts payable	14,486			(19,200		)
Accrued liabilities	5,650			(8,776		)
Other assets and liabilities, net	(982		)	(1,063		)
Net cash provided by operating activities	179,155			126,039
Cash Flows From Investing Activities
Capital expenditures - oil and gas properties	(290,625		)	(239,861		)
Acquisitions of oil and gas properties	(16,533		)	—
Deposit for pending acquisition of oil and gas properties	(75,000		)	—
Proceeds from sales of oil and gas properties, net	18,201			14,637
Other, net	(2,479		)	(873		)
Net cash used in investing activities	(366,436		)	(226,097		)
Cash Flows From Financing Activities
Borrowings under credit agreement	919,097			290,652
Repayments of borrowings under credit agreement	(723,797		)	(229,652		)
Payments of debt issuance costs	(4,368		)	(1,150		)
Payment of commitment fee for pending issuance of preferred stock	(5,000		)	—
Other, net	(617		)	(552		)
Net cash provided by financing activities	185,315			59,298
Net Decrease in Cash and Cash Equivalents	(1,966		)	(40,760		)
Cash and Cash Equivalents, Beginning of Period	4,194			42,918
Cash and Cash Equivalents, End of Period		$2,228			$2,158

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 oil, NGLs, and gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Niobrara Formation in Colorado, the Utica Shale in Ohio, and the Marcellus Shale in Pennsylvania.

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.

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

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

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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. Currently, 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. The Company plans to adopt the guidance on the effective date of January 1, 2018.

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.

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.

Net Income (Loss) Per Common Share

Supplemental net income (loss) per common share information is provided below:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
	(In thousands, except per share amounts)
Net Income (Loss)		$56,306		($262,126	)		$96,327		($573,521	)
Basic weighted average common shares outstanding	65,767		58,806			65,479		58,583
Effect of dilutive instruments	141		—			387		—
Diluted weighted average common shares outstanding	65,908		58,806			65,866		58,583
Net Income (Loss) Per Common Share
Basic		$0.86		($4.46	)		$1.47		($9.79	)
Diluted		$0.85		($4.46	)		$1.46		($9.79	)

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The table below presents the dilutive and anti-dilutive weighted average common shares outstanding for the three and six months ended June 30, 2017 and 2016:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017	2016			2017	2016
	(In thousands)
Dilutive	141	—			387	—
Anti-dilutive	209	675	⁽¹	⁾	78	655	⁽¹	⁾


(1)	For the three and six months ended June 30, 2016, the Company reported a net loss. As a result, all potentially dilutive common shares outstanding were anti-dilutive.

3. Acquisitions of Oil and Gas Properties

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 close, 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 purchase price allocation for the Sanchez Acquisition is preliminary and subject to change based on final settlement of purchase price adjustments primarily related to net cash flows from the acquired wells 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 fourth quarter of 2017. 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		$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

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 has an effective date of May 1, 2017 and is expected to close on August 10, 2017. On June 28, 2017, the Company paid $75.0 million to the seller as a deposit, which was funded with borrowings under the Company’s

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revolving credit facility. The deposit is refundable only in specified circumstances if the transaction is not consummated. The remaining purchase price will be due at closing.

The Company has 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 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 and will not exceed $125.0 million.

The Company intends to fund the remaining purchase price due at closing with the net proceeds from the pending issuance and sale of Preferred Stock and warrants described below, the net proceeds from the common stock offering completed on July 3, 2017, which, pending the closing of the ExL Acquisition, were used to temporarily repay a portion of the borrowings outstanding under the revolving credit facility and the net proceeds from the senior notes offering completed on July 14, 2017, which, pending the closing of the ExL Acquisition, a portion was used to temporarily repay borrowings outstanding under the revolving credit facility and for general corporate purposes with the remainder temporarily invested in cash equivalents. See “Note 13. Subsequent Events” for details regarding the common stock and senior notes offerings completed in July 2017. Upon closing the ExL Acquisition, the Company will become the operator of the ExL Properties with an approximate 70% average working interest.

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) 250,000 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, for a cash purchase price equal to $970.00 per share of Preferred Stock purchased. 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 is expected to occur on August 10, 2017 contemporaneously with the closing of the ExL Acquisition and is subject to certain closing conditions, including the closing of the ExL Acquisition. The Company expects to receive net proceeds of approximately $236.2 million, net of commitment fees and offering costs, from the issuance and sale of the Preferred Stock and warrants. The Company will use the net proceeds to fund a portion of the purchase price of the ExL Acquisition. The Company also agreed to enter into a registration rights agreement with the GSO Funds at the closing of the private placement, pursuant to which the Company will agree to provide certain registration and other rights for the benefit of the GSO Funds.

4. Property and Equipment, Net

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



	June 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties, full cost method
Proved properties		$4,978,535			$4,687,416
Accumulated depreciation, depletion and amortization and impairments	(3,503,404		)	(3,392,749		)
Proved properties, net	1,475,131			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	253,787			211,067
Capitalized interest	35,210			29,894
Total unproved properties, not being amortized	288,997			240,961
Other property and equipment	23,284			23,127
Accumulated depreciation	(14,253		)	(12,995		)
Other property and equipment, net	9,031			10,132
Total property and equipment, net		$1,773,159			$1,545,760

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $12.43 and $13.41 for the three months ended June 30, 2017 and 2016, respectively, and $12.55 and $14.32 for the six months ended June 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 $1.9 million and $1.4 million for the three months ended June 30, 2017 and 2016, respectively, and $7.3 million and $5.8 million for the six months ended June 30, 2017 and 2016, respectively.

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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 $4.0 million and $4.9 million for the three months ended June 30, 2017 and 2016, respectively, and $7.8 million and $10.5 million for the six months ended June 30, 2017 and 2016, respectively.

Sales of Oil and Gas Properties

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.

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 six months ended June 30, 2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil from December 31, 2015 to June 30, 2016, the Company recognized impairments of proved oil and gas properties for the three and six months ended June 30, 2016. Details of the 12-Month Average Realized Price of crude oil for the three and six months ended June 30, 2017 and 2016 and the impairments of proved oil and gas properties for the three and six months ended June 30, 2016 are summarized in the table below:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017			2016
Impairment of proved oil and gas properties (in thousands)		$—		$197,070			$—		$471,483
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$44.98			$43.14		$39.60			$47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$46.80			$39.84		$46.80			$39.84
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period	4		%	(8	%)	18		%	(16	%)

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.

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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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands)
Income (loss) before income taxes		$56,306			($261,934	)		$96,327			($573,208	)
Income tax (expense) benefit at the statutory rate	(19,707		)	91,677			(33,714		)	200,623
State income tax (expense) benefit, net of U.S. federal income taxes	(1,017		)	1,665			(1,727		)	3,284
Tax shortfalls from stock-based compensation expense	(164		)	—			(2,756		)	—
(Increase) decrease in deferred tax assets valuation allowance	20,948			(93,522		)	38,317			(204,201		)
Other	(60		)	(12		)	(120		)	(19		)
Income tax expense		$—			($192	)		$—			($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 June 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 second 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 June 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 six months ended June 30, 2017, primarily as a result of current activity, a partial release of $20.9 million and $38.3 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 June 30, 2017 was $541.8 million. For the three and six months ended June 30, 2016, the Company recorded additional valuation allowance of $93.5 million and $204.2 million, respectively, primarily as a result of the impairments of proved oil and gas properties recognized discussed above.

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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6. Long-Term Debt

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



	June 30, 2017			December 31, 2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$282,300			$87,000
7.50% Senior Notes due 2020	600,000			600,000
Unamortized premium for 7.50% Senior Notes	898			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(6,796		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,841		)	(9,454		)
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,521,986			$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 June 30, 2017, had a borrowing base of $900.0 million, of which $800.0 million has been committed by lenders, with $282.3 million of borrowings outstanding at a weighted average interest rate of 3.44%. As of June 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 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, of which $800.0 million has been committed by lenders, 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 asset sales, (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 Additional Consideration (as defined in the revolving credit facility) payable pursuant to the ExL Acquisition 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 of Oil and Gas Properties” for further details of the ExL Acquisition.

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

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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 June 30, 2017, the ratio of Total Debt to EBITDA was 3.64 to 1.00 and the Current Ratio was 2.33 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 dispositions 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, mergers, asset dispositions, 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).

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. 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.

Stock-Based Compensation Plans

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

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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 June 30, 2017, there were 1,811,671 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 June 30, 2017, the Company does not have any outstanding stock options and all outstanding stock appreciation rights will be settled solely in cash.

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.

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 June 30, 2017, unrecognized compensation costs related to unvested restricted stock awards and units was $30.8 million and will be recognized over a weighted average period of 2.3 years.

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



	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
For the Six Months Ended June 30, 2017
Unvested restricted stock awards and units, beginning of period	1,111,710			$36.93
Granted	955,944			$26.43
Vested	(600,274	)		$39.48
Forfeited	(9,797	)		$29.22
Unvested restricted stock awards and units, end of period	1,457,583			$29.05

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 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 June 30, 2017 was $1.9 million, of which $0.1 million was classified as “Other current liabilities,” with the remaining $1.8 million 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 $1.8 million as of June 30, 2017, and will be recognized over a weighted average period of 1.5 years.

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The table below summarizes the activity for SARs for the six months ended June 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 Six Months Ended June 30, 2017
Outstanding, beginning of period	722,638			$23.69
Granted	342,440			$26.94
Exercised	(219,279	)		$17.28					$2.1
Forfeited	—		—
Expired	(79,721	)		$28.68
Outstanding, end of period	766,078			$26.46	3.9		$—
Vested, end of period	237,739			$25.11
Vested and exercisable, end of period	—			$25.11	2.9		$—

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 six months ended June 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 June 30, 2017, unrecognized compensation costs related to unvested performance shares was $3.2 million and will be recognized over a weighted average period of 1.9 years.

The table below summarizes performance share activity for the six months ended June 30, 2017:



	Performance Shares ⁽¹⁾		Weighted Average Grant Date Fair Value
For the Six Months Ended June 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 performance shares presented in the table above are the target performance shares. The actual number of common stock issued upon vesting may vary 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 performance shares that vested during the first quarter of 2017 with a multiplier of 164%.

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The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the six months ended June 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

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands)
Restricted stock awards and units		$5,024			$5,998			$10,873			$17,592
Stock appreciation rights	(3,783		)	4,988			(7,469		)	6,220
Performance shares	574			714			1,280			1,330
	1,815			11,700			4,684			25,142
Less: amounts capitalized to oil and gas properties	(233		)	(808		)	(1,088		)	(2,728		)
Total stock-based compensation expense, net		$1,582			$10,892			$3,596			$22,414

9. 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, 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.

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 these contracts in order to obtain a higher floor price, sub-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 of existing sold call options and therefore are presented on a net basis in the summary of open crude oil derivative positions below.

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Premiums: In lieu of receiving payments for premiums from its counterparties of sold call options, the Company has used the associated premium value to obtain higher fixed prices on fixed price swaps which were executed contemporaneously with those sold call options. The Company elected to defer payment of premiums associated with its three-way collars and purchased call options presented in the table below until the applicable contracts settle on a monthly basis.

The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX prices as of June 30, 2017:



Period	Type of Contract	Crude Oil Volumes (in Bbls/d)	Weighted Average Sub-Floor Price ($/Bbl)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q3 2017	Fixed Price Swaps	12,000				$53.71
Q4 2017	Fixed Price Swaps	9,000				$53.86
FY 2018	Three-Way Collars	6,000		$40.00		$50.00		$65.00
FY 2018	Net Sold Call Options	3,388						$71.33
FY 2019	Net Sold Call Options	3,875						$73.66
FY 2020	Net Sold Call Options	4,575					$75.98

The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of June 30, 2017:



Period	Type of Contract	Natural Gas Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q3 - Q4 2017	Fixed Price Swaps	20,000		$3.30
Q3 - Q4 2017	Sold Call Options	33,000				$3.00
FY 2018	Sold Call Options	33,000				$3.25
FY 2019	Sold Call Options	33,000				$3.25
FY 2020	Sold Call Options	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. Deferred premiums 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 its derivative instrument fair values executed with the same counterparty, along with deferred premiums, 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 our 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 or its counterparty’s parent company.

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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 are recorded in the period in which they are incurred and are netted with the derivative instrument fair value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, as well as deferred premium obligations, recorded in the Company’s consolidated balance sheets as of June 30, 2017 and December 31, 2016 are summarized below:



	June 30, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Derivative instruments		$20,457			($3,102	)		$17,355
Deferred premiums	—			(2,072		)	(2,072		)
Derivative assets-current		$20,457			($5,174	)		$15,283
Derivative instruments	11,345			(8,610		)	2,735
Deferred premiums	—			(1,124		)	(1,124		)
Other assets-non current		$11,345			($9,734	)		$1,611

Derivative instruments		($3,859	)		$3,102			($757	)
Deferred premiums	(3,327		)	2,072			(1,255		)
Derivative liabilities-current		($7,186	)		$5,174			($2,012	)
Derivative instruments	(15,564		)	8,610			(6,954		)
Deferred premiums	(7,822		)	1,124			(6,698		)
Derivative liabilities-non current		($23,386	)		$9,734			($13,652	)



	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Derivative instruments		$7,990			($6,753	)		$1,237
Deferred premiums	—			—			—
Derivative assets-current		$7,990			($6,753	)		$1,237
Derivative instruments	3,882			(3,882		)	—
Deferred premiums	—			—			—
Other assets-non current		$3,882			($3,882	)		$—

Derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premiums	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premiums	(2,569		)	—			(2,569		)
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

See “Note 10. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative positions.

-18-

(Gain) Loss on Derivatives, Net and Cash Received (Paid) for Derivative Settlements, Net

The Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of derivative instruments 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 are recognized in (gain) loss on derivatives, net in the Company’s consolidated statements of operations in the period in which the premium obligations are incurred. Cash flows are impacted to the extent that settlements under these contracts, including any deferred premiums, result in payments 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 derivative instruments and deferred premiums on the Company’s consolidated statements of operations for the three and six months ended June 30, 2017 and 2016 is summarized below:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017			2016
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		($29,736	)		$47,743		($48,163	)		$20,315
Natural gas	(3,883		)	4,417		(10,719		)	15,657
Deferred premiums	7,554			75		7,501			5,710
Total (Gain) Loss on Derivatives, Net		($26,065	)		$52,235		($51,381	)		$41,682

The effect of derivative instruments and deferred premiums on the Company’s consolidated statements of cash flows for the three and six months ended June 30, 2017 and 2016 are summarized below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$409			$30,122			$3,441			$81,384
Natural gas	(104		)	—			(1,253		)	—
Deferred premiums	(566		)	(2,822		)	(930		)	(2,921		)
Total Cash Received (Paid) for Derivative Settlements, Net		($261	)		$27,300			$1,258			$78,463

10. 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.

-19-

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 June 30, 2017 and December 31, 2016:



	June 30, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$20,090			$—
Derivative instrument liabilities		$—		($7,711	)		$—



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

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 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. 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 premiums 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 derivative instruments executed with the same counterparty, along with deferred premiums, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the six months ended June 30, 2017 and 2016.

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

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date 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.

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.

-20-

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.



	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020		$594,102		$603,000		$593,447		$624,750
6.25% Senior Notes due 2023	641,159		617,500		640,546		672,750
Other long-term debt due 2028	4,425		4,403		4,425		4,419

11. 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.

-21-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)



	June 30, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,882,550			$70,583			$—		($2,857,735	)		$95,398
Total property and equipment, net	38,260			1,735,056			3,800		(3,957		)	1,773,159
Investment in subsidiaries	(1,159,581		)	—			—		1,159,581			—
Other assets	20,107			75,155			—		—			95,262
Total Assets		$1,781,336			$1,880,794			$3,800		($1,702,111	)		$1,963,819

Liabilities and Shareholders’ Equity
Current liabilities		$104,105			$3,011,910			$3,800		($2,860,755	)		$259,060
Long-term liabilities	1,528,585			28,465			—		15,878			1,572,928
Total shareholders’ equity	148,646			(1,159,581		)	—		1,142,766			131,831
Total Liabilities and Shareholders’ Equity		$1,781,336			$1,880,794			$3,800		($1,702,111	)		$1,963,819



	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
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

-22-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)



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



	Three Months Ended June 30, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$129			$107,195			$—		$—			$107,324
Total costs and expenses	92,982			276,287			—		(11		)	369,258
Loss before income taxes	(92,853		)	(169,092		)	—		11			(261,934		)
Income tax expense	—			—			—		(192		)	(192		)
Equity in loss of subsidiaries	(169,092		)	—			—		169,092			—
Net loss		($261,945	)		($169,092	)		$—		$168,911			($262,126	)

-23-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)



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



	Six Months Ended June 30, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$244			$188,342			$—		$—			$188,586
Total costs and expenses	122,894			638,535			—		365			761,794
Loss before income taxes	(122,650		)	(450,193		)	—		(365		)	(573,208		)
Income tax expense	—			—			—		(313		)	(313		)
Equity in loss of subsidiaries	(450,193		)	—			—		450,193			—
Net loss		($572,843	)		($450,193	)		$—		$449,515			($573,521	)

-24-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended June 30, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities		($77,501	)		$256,656			$—		$—			$179,155
Net cash used in investing activities	(109,780		)	(364,887		)	—		108,231			(366,436		)
Net cash provided by financing activities	185,315			108,231			—		(108,231		)	185,315
Net decrease in cash and cash equivalents	(1,966		)	—			—		—			(1,966		)
Cash and cash equivalents, beginning of period	4,194			—			—		—			4,194
Cash and cash equivalents, end of period		$2,228			$—			$—		$—			$2,228



	Six Months Ended June 30, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities		$609			$125,430			$—			$—			$126,039
Net cash used in investing activities	(100,667		)	(224,656		)	(740		)	99,966			(226,097		)
Net cash provided by financing activities	59,298			99,226			740			(99,966		)	59,298
Net decrease in cash and cash equivalents	(40,760		)	—			—			—			(40,760		)
Cash and cash equivalents, beginning of period	42,918			—			—			—			42,918
Cash and cash equivalents, end of period		$2,158			$—			$—			$—			$2,158

-25-

12. Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2017		2016
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$39,603		$35,659

Non-cash investing activities:
Increase (decrease) in capital expenditure payables and accruals		$48,395		($23,198	)
Stock-based compensation expense capitalized to oil and gas properties	1,088		2,728
Asset retirement obligations capitalized to oil and gas properties	1,177		301

13. Subsequent Events

Common Stock Offering

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 plans to use the net proceeds of $222.5 million, net of offering costs, to fund a portion of the purchase price of the ExL Acquisition and for general corporate purposes. Pending the closing of the ExL Acquisition, the Company used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 3. Acquisitions of Oil and Gas Properties” for further details of the ExL Acquisition.

Senior Notes Offering

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 from 106.188% to 100% of the principal amount on July 15, 2023, plus accrued and unpaid interest. The Company intends to use the net proceeds of $245.5 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. Pending the closing of the ExL Acquisition, the Company used a portion of the net proceeds to temporarily repay borrowings outstanding under the revolving credit facility with the remainder used for general corporate purposes including temporarily invested in cash equivalents. If the ExL Acquisition is not completed by October 28, 2017, or if the purchase agreement for the ExL Acquisition is terminated at any time prior to the closing of the ExL Acquisition, the Company will be required to redeem the 8.25% Senior Notes at the initial offering price, plus accrued and unpaid interest. Additionally, if the Company determines such events are reasonably likely, the Company may, at its option, redeem the 8.25% Senior Notes at the initial offering price, plus accrued and unpaid interest. See “Note 3. Acquisitions of Oil and Gas Properties” for further details of the ExL Acquisition.

Hedging

In July 2017, the Company entered into the following crude oil derivative positions:



Period	Type of Contract	Crude Oil Volumes (in Bbls/d)	Weighted Average Sub-Floor Price ($/Bbl)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
FY 2018	Three-Way Collars	12,000		$38.75		$48.63		$58.23
FY 2019	Three-Way Collars	6,000		$40.00		$47.80		$61.45

In order to obtain a higher weighted average floor price, sub-floor price and/or ceiling price on these three-way collars, the Company incurred premiums of (i) $5.1 million for 6,000 Bbls/d for 2018, the payments for which are deferred until the applicable contracts settle on a monthly basis and (ii) $6.1 million for 6,000 Bbls/d for 2018-2019, the payments for which are deferred until the 2019 contracts settle on a monthly basis.

-26-

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 June 30, 2017 was 51,019 Boe/d, an increase of 23% from the three months ended June 30, 2016, primarily due to production from new wells in the Eagle Ford and Delaware Basin, the addition of production from the Sanchez Acquisition in late 2016, and an increase in Marcellus production due to improved netbacks.

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



	Three Months Ended June 30, 2017				June 30, 2017
	Drilled		Completed		Drilled But Uncompleted		Producing		Rig count
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Rig count
Eagle Ford	23	21.2	26	21.6	28	26.6	494	431.5	3
Delaware Basin	—	—	2	2.0	—	—	8	7.6	—
Niobrara	—	—	—	—	—	—	130	57.9	—
Marcellus	—	—	—	—	11	4.3	81	26.0	—
Utica and other	—	—	—	—	—	—	4	3.1	—
Total	23	21.2	28	23.6	39	30.9	717	526.1	3

Drilling and completion expenditures for the second quarter of 2017 were $148.4 million, of which 88% were in the Eagle Ford where, as of June 30, 2017, we were operating three rigs and two frac crews. Our current 2017 drilling and completion capital expenditure plan is $590.0 million to $610.0 million, which reflects the most recent estimate of expected activity as a result of the ExL Acquisition. 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 91% 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 for the three months ended June 30, 2017 of $56.3 million, or $0.85 per diluted share, as compared to a net loss for the three months ended June 30, 2016 of $262.1 million, or $4.46 per diluted share. The net income for the second quarter of 2017 as compared to the net loss for the second quarter of 2016 was driven primarily by higher production volumes and commodity prices in the second quarter of 2017 compared to the second quarter of 2016, no impairment of proved oil and gas properties during the second quarter of 2017 compared to the $197.1 million impairment of proved oil and gas properties recognized during the second quarter of 2016, as well as a gain on derivatives, net of $26.1 million in the second quarter of 2017 compared to a loss on derivatives, net of $52.2 million in the second quarter of 2016. See “—Results of Operations” below for further details.

Acquisition Activity

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 has an effective date of May 1, 2017 and is expected to close on August 10, 2017. On June 28, 2017, we paid $75.0 million to the seller as a deposit, which was funded with borrowings under our revolving credit facility. The deposit is refundable only in specified circumstances if the transaction is not consummated. The remaining purchase price will be due at closing.

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 of Oil and Gas Properties” for further details of the contingent payment.

-27-

We intend to fund the remaining purchase price due at closing with the net proceeds from the pending issuance and sale of Preferred Stock and warrants described below, the net proceeds from the common stock offering completed on July 3, 2017, which, pending the closing of the ExL Acquisition, were used to temporarily repay a portion of the borrowings outstanding under the revolving credit facility and the net proceeds from the senior notes offering completed on July 14, 2017, which, pending the closing of the ExL Acquisition, a portion was used to temporarily repay borrowings outstanding under the revolving credit facility and for general corporate purposes with the remainder temporarily invested in cash equivalents. See below for further discussion of the Preferred Stock and warrants, the common stock offering, and the issuance of the 8.25% Senior Notes. Upon closing the ExL Acquisition, we will become the operator of the ExL Properties with an approximate 70% average working interest.

Preferred Stock Purchase Agreement

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) 250,000 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, 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 is expected to occur on August 10, 2017 contemporaneously with the closing of the ExL Acquisition and is subject to certain closing conditions, including the closing of the ExL Acquisition. We expect to receive net proceeds of approximately $236.2 million, net of commitment fees and offering costs, from the issuance and sale of the Preferred Stock and warrants. We will use the net proceeds to fund a portion of the purchase price of the ExL Acquisition. We also agreed to enter into a registration rights agreement with the GSO Funds at the closing of the private placement, pursuant to which we will agree to provide certain registration and other rights for the benefit of the GSO Funds.

Amendments to Credit Agreement

On May 4, 2017, we entered into a ninth amendment to our 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 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, and (iii) increase the borrowing base from $600.0 million to $900.0 million, of which $800.0 million has been committed by lenders, until the next redetermination thereof. See “Note 6. Long-Term Debt” for further details.

On June 28, 2017, we entered into a tenth amendment to our 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, our 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 asset sales, (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 Additional Consideration (as defined in the revolving credit facility) payable pursuant to the ExL Acquisition 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 of Oil and Gas Properties” for further details of the ExL Acquisition.

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 plan to use the net proceeds of $222.5 million, net of offering costs, to fund a portion of the purchase price of the ExL Acquisition and for general corporate purposes. Pending the closing of the ExL Acquisition, we used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 3. Acquisitions of Oil and Gas Properties” for further details of the ExL Acquisition.

Senior Notes Offering

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 intend to use the net proceeds of $245.5 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. Pending the closing of the ExL Acquisition, we used a portion of the net proceeds to temporarily repay borrowings outstanding under the revolving credit facility with the remainder used for general corporate purposes including temporarily invested in cash equivalents. If the ExL Acquisition is not completed by October 28, 2017, or if the purchase agreement for the ExL Acquisition is terminated

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at any time prior to the closing of the ExL Acquisition, we will be required to redeem the 8.25% Senior Notes at the initial offering price, plus accrued and unpaid interest. Additionally, if we determine such events are reasonably likely, we may, at our option, redeem the 8.25% Senior Notes at the initial offering price, plus accrued and unpaid interest. See “Note 3. Acquisitions of Oil and Gas Properties” for further details of the ExL Acquisition and “Note 13. Subsequent Events” for further details of the senior notes offering.

Consideration of Asset Sales

We have recently begun efforts to sell our assets in the Marcellus, Utica, and Niobrara. Closing of these sales could take place by the end of this year. We believe that such sales would be strategically beneficial as they allow us to refine our focus on two high quality plays in the Eagle Ford and Delaware Basin as well as preserve future financial flexibility that would benefit us in light of the obligations incurred and expected to be incurred to fund the ExL Acquisition. There can be no assurance that we will be able to sell any of these assets in such time frame on acceptable terms or at all or receive any targeted aggregate gross proceeds.

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Results of Operations

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

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



	Three Months Ended June 30,				2017 Period Compared to 2016 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,060		2,179		881			40	%
NGLs (MBbls)	453		475		(22		)	(5	%)
Natural gas (MMcf)	6,775		6,757		18			—	%
Total barrels of oil equivalent (MBoe)	4,643		3,780		863			23	%

Daily production volumes by product -
Crude oil (Bbls/d)	33,629		23,942		9,687			40	%
NGLs (Bbls/d)	4,982		5,217		(235		)	(5	%)
Natural gas (Mcf/d)	74,451		74,248		203			—	%
Total barrels of oil equivalent (Boe/d)	51,019		41,533		9,486			23	%

Daily production volumes by region (Boe/d) -
Eagle Ford	38,055		30,233		7,822			26	%
Delaware Basin	2,151		489		1,662			340	%
Niobrara	2,694		2,775		(81		)	(3	%)
Marcellus	7,379		6,511		868			13	%
Utica and other	740		1,525		(785		)	(51	%)
Total barrels of oil equivalent (Boe/d)	51,019		41,533		9,486			23	%

Average realized prices -
Crude oil ($ per Bbl)		$46.67		$42.04		$4.63		11	%
NGLs ($ per Bbl)	17.19		12.76		4.43			35	%
Natural gas ($ per Mcf)	2.35		1.43		0.92			64	%
Total average realized price ($ per Boe)		$35.86		$28.39		$7.47		26	%

Revenues (In thousands) -
Crude oil		$142,806		$91,608		$51,198		56	%
NGLs	7,786		6,063		1,723			28	%
Natural gas	15,891		9,653		6,238			65	%
Total revenues		$166,483		$107,324		$59,159		55	%

Production volumes for the three months ended June 30, 2017 were 51,019 Boe/d, an increase of 23% from 41,533 Boe/d for the same period in 2016. The increase is primarily due to increased production from new wells in the Eagle Ford and Delaware Basin, the addition of production from the Sanchez Acquisition in late 2016 and an increase in Marcellus production due to improved netbacks. Revenues for the three months ended June 30, 2017 increased 55% to $166.5 million compared to $107.3 million for the same period in 2016 primarily due to increased production and higher commodity prices.

Lease operating expenses for the three months ended June 30, 2017 increased to $36.0 million ($7.76 per Boe) from $23.1 million ($6.11 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 acquired in the Sanchez Acquisition. The increase in lease operating expense per Boe is primarily due to the increased workover costs 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 $7.1 million (or 4.3% of revenues) for the three months ended June 30, 2017 from $4.6 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 revenues.

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Ad valorem taxes increased to $1.1 million for the three months ended June 30, 2017 from $0.5 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 second quarter of 2017 increased $7.1 million to $59.1 million ($12.72 per Boe) from the DD&A expense for the second quarter of 2016 of $52.0 million ($13.75 per Boe). The increase in DD&A expense is attributable to increased production, partially offset by the decrease in the DD&A rate per Boe. The DD&A rate per Boe decreased primarily due to the impairment of our proved oil and gas properties recorded during the third quarter of 2016, reductions in estimated future development costs primarily 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 June 30,
	2017		2016
	(In thousands)
DD&A of proved oil and gas properties		$57,695		$50,690
Depreciation of other property and equipment	612		665
Amortization of other assets	321		268
Accretion of asset retirement obligations	444		343
Total DD&A		$59,072		$51,966

We did not recognize an impairment of proved oil and gas properties for the three months ended June 30, 2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil from March 31, 2016 to June 30, 2016, we recognized an impairment of proved oil and gas properties for the three months ended June 30, 2016. Details of the 12-Month Average Realized Price of crude oil for the three months ended June 30, 2017 and 2016 and the impairment of proved oil and gas properties for the three months ended June 30, 2016 are summarized in the table below:



	Three Months Ended June 30,
	2017			2016
Impairment of proved oil and gas properties (in thousands)		$—		$197,070
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$44.98			$43.14
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$46.80			$39.84
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period	4		%	(8	%)

General and administrative expense, net decreased to $11.6 million for the three months ended June 30, 2017 from $19.6 million for the corresponding 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 three months ended June 30, 2017 compared to an increase in fair value for the three months ended June 30, 2016.

We recorded a gain on derivatives, net of $26.1 million and a loss on derivatives, net of $52.2 million for the three months ended June 30, 2017 and 2016, respectively. The components of our gain (loss) on derivatives, net were as follows:



	Three Months Ended June 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		$10,122			($47,743	)
Gain due to new derivative positions executed during the period	19,614			—
Loss due to deferred premiums	(7,554		)	(75		)
Natural gas derivative positions:
Gain (loss) due to downward (upward) shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period	3,883			(4,417		)
Gain (loss) on derivatives, net		$26,065			($52,235	)

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Interest expense, net for the three months ended June 30, 2017 was $21.1 million as compared to $19.0 million for the same period in 2016. The increase was due primarily to the increase in interest expense on our revolving credit facility as a result of increased borrowings in the second quarter of 2017 as compared to the second quarter of 2016 as well as the decrease in capitalized interest as a result of lower average balances of unevaluated leasehold and seismic costs for the second quarter of 2017 as compared to the second quarter of 2016. The components of our interest expense, net were as follows:



	Three Months Ended June 30,
	2017			2016
	(In thousands)
Interest expense on Senior Notes		$21,455			$21,455
Interest expense on revolving credit facility	2,261			989
Amortization of premiums and debt issuance costs	1,079			1,134
Other interest expense	298			260
Interest capitalized	(3,987		)	(4,828		)
Interest expense, net		$21,106			$19,010

The effective income tax rate for the second quarter of 2017 and 2016 was 0.0%. 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 June 30, 2017, as a result of current quarter activity, a partial release from the valuation allowance was needed to bring the net deferred tax assets to zero. For the three months ended June 30, 2016, we recorded additional valuation allowance primarily as a result of the impairments of proved oil and gas properties described above.

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Results of Operations

Six Months Ended June 30, 2017, Compared to the Six Months Ended June 30, 2016

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



	Six Months Ended June 30,				2017 Period Compared to 2016 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	5,656		4,527		1,129			25	%
NGLs (MBbls)	859		889		(30		)	(3	%)
Natural gas (MMcf)	13,803		13,130		673			5	%
Total barrels of oil equivalent (MBoe)	8,816		7,604		1,212			16	%

Daily production volumes by product -
Crude oil (Bbls/d)	31,250		24,874		6,376			26	%
NGLs (Bbls/d)	4,746		4,882		(136		)	(3	%)
Natural gas (Mcf/d)	76,260		72,141		4,119			6	%
Total barrels of oil equivalent (Boe/d)	48,706		41,779		6,927			17	%

Daily production volumes by region (Boe/d) -
Eagle Ford	35,332		30,602		4,730			15	%
Delaware Basin	2,284		315		1,969			625	%
Niobrara	2,729		2,980		(251		)	(8	%)
Marcellus	7,652		6,269		1,383			22	%
Utica and other	709		1,613		(904		)	(56	%)
Total barrels of oil equivalent (Boe/d)	48,706		41,779		6,927			17	%

Average realized prices -
Crude oil ($ per Bbl)		$47.90		$35.26		$12.64		36	%
NGLs ($ per Bbl)	17.71		10.69		7.02			66	%
Natural gas ($ per Mcf)	2.30		1.48		0.82			55	%
Total average realized price ($ per Boe)		$36.05		$24.80		$11.25		45	%

Revenues (In thousands) -
Crude oil		$270,898		$159,604		$111,294		70	%
NGLs	15,211		9,503		5,708			60	%
Natural gas	31,729		19,479		12,250			63	%
Total revenues		$317,838		$188,586		$129,252		69	%

Production volumes for the six months ended June 30, 2017 were 48,706 Boe/d, an increase of 17% from 41,779 Boe/d for the same period in 2016. The increase is primarily due to increased production from new wells in the Eagle Ford and Delaware Basin, the addition of production from the Sanchez Acquisition in late 2016, and an increase in Marcellus production due to improved netbacks, partially offset by normal production declines. Revenues for the six months ended June 30, 2017 increased 69% to $317.8 million from $188.6 million for the same period in 2016 primarily due to higher average realized crude oil prices as well as the increased production described above.

Lease operating expenses for the six months ended June 30, 2017 increased to $65.9 million ($7.47 per Boe) from $46.8 million ($6.15 per Boe) for the same period in 2016. The increase in lease operating expenses is primarily due to increased production from new wells in the Eagle Ford and Delaware Basin 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.

Production taxes increased to $13.4 million (or 4.2% of revenues) for the six months ended June 30, 2017 from $8.1 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 revenues. The decrease in production taxes as a percentage of revenues for the six months ended June 30, 2017 as compared to the same

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period in 2016 is primarily due to an increased proportion of total revenues attributable to Marcellus production, which is not subject to production taxes.

Ad valorem taxes increased to $4.0 million for the six months ended June 30, 2017 from $2.5 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 six months ended June 30, 2017 increased $1.9 million to $113.5 million ($12.87 per Boe) from $111.5 million ($14.67 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 in the third quarter of 2016, reductions in estimated future development costs primarily 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:



	Six Months Ended June 30,
	2017		2016
	(In thousands)
DD&A of proved oil and gas properties		$110,655		$108,893
Depreciation of other property and equipment	1,258		1,338
Amortization of other assets	672		641
Accretion of asset retirement obligations	869		671
Total DD&A		$113,454		$111,543

We did not recognize an impairment of proved oil and gas properties for the six months ended June 30, 2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil from December 31, 2015 to June 30, 2016, we recognized an impairment of proved oil and gas properties for the six months ended June 30, 2016. Details of the 12-Month Average Realized Price of crude oil for the six months ended June 30, 2017 and 2016 and the impairment of proved oil and gas properties for the six months ended June 30, 2016 are summarized in the table below:



	Six Months Ended June 30,
	2017			2016
Impairment of proved oil and gas properties (in thousands)		$—		$471,483
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$39.60			$47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$46.80			$39.84
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period	18		%	(16	%)

General and administrative expense, net decreased to $33.3 million for the six months ended June 30, 2017 from $40.9 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 six months ended June 30, 2017 compared to an increase in fair value for the six months ended June 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 $51.4 million and a loss on derivatives, net of $41.7 million for the six months ended June 30, 2017 and 2016, respectively. The components of our gain (loss) on derivatives, net were as follows:



	Six Months Ended June 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		$28,549			($16,512	)
Gain (loss) due to new derivative positions executed during the period	19,614			(3,803		)
Loss due to deferred premiums	(7,501		)	(5,612		)
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	10,719			—
Loss due to new derivative positions executed during the period	—			(15,657		)
Loss due to deferred premiums	—			(98		)
Gain (loss) on derivatives, net		$51,381			($41,682	)

Interest expense, net for the six months ended June 30, 2017 was $41.7 million as compared to $37.7 million for the same period in 2016. The increase was due primarily to the decrease in capitalized interest as a result of lower average balances of unevaluated leasehold and seismic costs and exploratory well costs for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 as well as an increase in interest expense on our revolving credit facility as a result of increased borrowings for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. The components of our interest expense, net were as follows:



	Six Months Ended June 30,
	2017			2016
	(In thousands)
Interest expense on Senior Notes		$42,910			$42,910
Interest expense on revolving credit facility	3,687			1,666
Amortization of debt issuance costs, premiums, and discounts	2,265			3,110
Other interest expense	583			514
Capitalized interest	(7,768		)	(10,477		)
Interest expense, net		$41,677			$37,723

The effective income tax rates for the six months ended June 30, 2017 and 2016 were 0.0% and (0.1%), respectively. 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 six months ended June 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 six months ended June 30, 2016, we recorded additional valuation allowance primarily as a result of impairments of proved oil and gas properties described above.

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Liquidity and Capital Resources

2017 Drilling and Completion Capital Expenditure Plan and Funding Strategy. Our 2017 drilling and completion capital expenditure plan is $590.0 million to $610.0 million, which reflects the most recent estimate of expected activity as a result of the ExL Acquisition. We currently intend to finance 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 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 and June 30, 2017 and for the six months ended June 30, 2017:



	Three Months Ended				Six Months Ended
	March 31, 2017		June 30, 2017		June 30, 2017
	(In thousands)
Drilling and completion
Eagle Ford		$111,472		$129,933		$241,405
Delaware Basin	10,360		11,727		22,087
All other regions	6,412		6,734		13,146
Total drilling and completion ⁽¹⁾	128,244		148,394		276,638
Leasehold and seismic ⁽¹⁾	14,516		34,447		48,963
Total ⁽²⁾		$142,760		$182,841		$325,601


(1)	Capital expenditures included in the table above exclude costs for acquisitions of oil and gas properties.


(2)	Our drilling and completion capital expenditure plan and the capital expenditures in the table above exclude capitalized general and administrative expense, interest 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 six months ended June 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 August 4, 2017, our revolving credit facility had a borrowing base of $900.0 million, of which $800.0 million has been committed by lenders, with no borrowings outstanding and $0.4 million in letters of credit issued, which reduce the amounts available under our revolving credit facility. Subsequent to June 30, 2017, borrowings outstanding under the revolving credit facility were temporarily repaid with net proceeds from the common stock offering and a portion of the net proceeds from the senior notes offering. See “Note 13. Subsequent Events” for details of the recent common stock offering and the issuance of the 8.25% Senior Notes. A portion of the purchase price due at closing for the ExL Acquisition will be funded from borrowings under the revolving credit facility. 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 recent ninth amendment and tenth 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 3. Acquisitions of Oil and Gas Properties” for details of the pending Preferred Stock and warrants issuance and “Note 13. Subsequent Events” for details of the recent common stock offering and the issuance of the 8.25% Senior Notes.


•	Asset sales. We may consider the sale of 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 sell such assets on terms that are acceptable to us. See “—General Overview—Consideration of Asset Sales” 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 $179.2 million and $126.0 million for the six months ended June 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 $366.4 million and $226.1 million for the six months ended June 30, 2017 and 2016, respectively. The change was due primarily to increased capital expenditures, cash paid for the Sanchez Acquisition and the deposit paid in connection with the pending ExL Acquisition, partially offset by increased proceeds from sales of oil and gas properties. The sales of oil and gas properties in 2017 were primarily related to the sale of a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million.

Net cash provided by financing activities was $185.3 million and $59.3 million for the six months ended June 30, 2017 and 2016, respectively. The change was due to 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 ninth amendment to the credit agreement governing the revolving credit facility and the commitment fee paid related to the pending issuance of 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 commodity 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.


•	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 August 4, 2017, we had the following crude oil derivative positions:



Period	Type of Contract	Crude Oil Volumes (in Bbls/d	Weighted Average Sub-Floor Price ($/Bbl)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q3 2017	Fixed Price Swaps	12,000				$53.71
Q4 2017	Fixed Price Swaps	9,000				$53.86
FY 2018	Three-Way Collars	18,000		$39.17		$49.08		$60.48
FY 2018	Net Sold Call Options	3,388						$71.33
FY 2019	Three-Way Collars	6,000		$40.00		$47.80		$61.45
FY 2019	Net Sold Call Options	3,875						$73.66
FY 2020	Net Sold Call Options	4,575					$75.98

As of August 4, 2017, we had the following natural gas derivative positions:



Period	Type of Contract	Natural Gas Volumes (in MMBtu/d	Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)
Q3 - Q4 2017	Fixed Price Swaps	20,000		$3.30
Q3 - Q4 2017	Sold Call Options	33,000				$3.00
FY 2018	Sold Call Options	33,000				$3.25
FY 2019	Sold Call Options	33,000				$3.25
FY 2020	Sold Call Options	33,000				$3.50

If cash flows from operations and borrowings under our revolving credit facility and the other sources of cash described under “—Sources and Uses of Cash” are insufficient to fund the remainder of our 2017 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our remaining 2017 capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Based on existing market conditions and our expected liquidity needs, among other

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factors, we may use a portion of our cash flows from operations, proceeds from asset sales, 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.

Contractual Obligations

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



	July - December 2017		2018		2019		2020		2021		2022 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$—		$600,000		$—		$936,725		$1,536,725
Cash interest on senior notes and other long-term debt ⁽²⁾	42,909		85,819		85,819		85,819		40,819		62,180		403,365
Cash interest and commitment fees on revolving credit facility ⁽³⁾	5,960		11,661		11,661		11,661		11,661		4,017		56,621
Capital leases	928		1,823		1,800		1,050		—		—		5,601
Operating leases	2,407		4,713		4,589		4,488		4,450		1,854		22,501
Drilling rig contracts ⁽⁴⁾	10,881		3,957		—		—		—		—		14,838
Delivery commitments ⁽⁵⁾	4,576		8,611		7,298		4,826		3,680		291		29,282
Asset retirement obligations and other ⁽⁶⁾	1,304		1,589		385		105		282		21,842		25,507
Total Contractual Obligations		$68,965		$118,173		$111,552		$707,949		$60,892		$1,026,909		$2,094,440


(1)	Long-term debt consists of the principal amounts of the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, 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 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 June 30, 2017 of 3.44%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of June 30, 2017, at the commitment fee rate of 0.375%. See“Note 6. Long-Term Debt” for details of the recent changes to our revolving credit facility.

(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. Subsequent to June 30, 2017, we entered into two new drilling rig contracts for terms of one and two years, as well as extended a current drilling rig contract for two years related to expected activity as a result of the ExL Acquisition. The gross contractual obligations for these drilling rig contracts are $37.2 million.

(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 June 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 June 30, 2017, had a borrowing base of $900.0 million, of which $800.0 million has been committed by lenders, with $282.3 million of borrowings outstanding at a weighted average interest rate of 3.44% 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. 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. See “Note 6. Long-Term Debt” for further details.

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On June 28, 2017, the Company 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. See “Note 6. Long-Term Debt” for further details.

See “Note 6. Long-Term Debt” for additional details of the senior secured revolving credit facility including 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.

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) 250,000 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 is expected to occur on August 10, 2017 contemporaneously with the closing of the ExL Acquisition and is subject to certain closing conditions, including the closing of the ExL Acquisition. We expect to receive net proceeds of approximately $236.2 million, net of commitment fees and offering costs, from the issuance and sale of the Preferred Stock and warrants. We will use the net proceeds to fund a portion of the purchase price of the ExL Acquisition. See “Note 3. Acquisitions of Oil and Gas Properties” for further details.

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 intend to use the net proceeds of $222.5 million, net of offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. Pending the closing of the ExL Acquisition, we used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 3. Acquisitions of Oil and Gas Properties” for further details of the ExL Acquisition.

Senior Notes Offering

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. Before July 15, 2020, we may, at our 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, we may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing from 106.188% to 100% of the principal amount on July 15, 2023, plus accrued and unpaid interest. In addition, prior to July 15, 2020, we may, at our option, redeem up to 35% of the aggregate principal amount of the 8.25% Senior Notes with the proceeds of certain equity offerings at a redemption price of 108.250% of the principal amount, plus accrued and unpaid interest. Prior to July 15, 2020, we may redeem all or part of the 8.25% Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium (as defined in the indenture governing the 8.25% Senior Notes). Holders of the 8.25% Senior Notes may require us to repurchase some or all of their 8.25% Senior Notes for cash in the event of a Change of Control (as defined in the indenture governing the 8.25% Senior Notes), at 101% of the principal amount plus accrued and unpaid interest. If the ExL Acquisition is not completed by October 28, 2017, or if the purchase agreement for the ExL Acquisition is terminated at any time prior to the closing of the ExL Acquisition, we will be required to redeem the 8.25% Senior Notes at the initial offering price, plus accrued and unpaid interest. Additionally, if we determine such events are reasonably likely, we may, at our option, redeem the 8.25% Senior Notes at the initial offering price, plus accrued and unpaid interest. See “Note 3. Acquisitions of Oil and Gas Properties” for further details of the ExL Acquisition.

The indenture governing our 8.25% Senior Notes, which is substantially similar to the indentures governing our 6.25% Senior Notes and 7.50% Senior Notes, contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: pay distributions on, purchase or redeem our common stock or other capital stock or redeem our 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 our assets; enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing our 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.

We intend to use the net proceeds of $245.5 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 and corporate purposes. Pending the closing of the ExL Acquisition, we used a portion of the net proceeds to temporarily repay borrowings outstanding under the revolving credit facility with the remainder used for general corporate purposes including temporarily invested in cash equivalents.

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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 103.75% until September 14, 2017, 101.875% beginning September 15, 2017 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, income taxes and commitments and contingencies. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2016 Annual Report. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our June 30, 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 June 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 June 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)
June 30, 2017 Actual	$46.80	$2.19	$525

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$51.69	$2.53	$943	$418
Crude Oil and Natural Gas -10%	$41.95	$1.84	$124	($401)

Crude Oil Price Sensitivity
Crude Oil +10%	$51.69	$2.19	$890	$365
Crude Oil -10%	$41.95	$2.19	$166	($359)

Natural Gas Price Sensitivity
Natural Gas +10%	$46.80	$2.53	$577	$52
Natural Gas -10%	$46.80	$1.84	$475	($50)

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.

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such as our potential for future growth. We also have estimated U.S. federal net operating loss carryforwards of $838.9 million as of June 30, 2017. Beginning in the third quarter of 2015, and continuing through the second 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 June 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 six months ended June 30, 2017, primarily as a result of current activity, a partial release of $20.9 million and $38.3 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 June 30, 2017 was $541.8 million. For the three and six months ended June 30, 2016, we recorded additional valuation allowance of $93.5 million and $204.2 million, respectively, primarily as a result of the impairments of proved oil and gas properties recognized discussed above.

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

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 crude oil and natural gas 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 June 30, 2017, our commodity derivative instruments consisted of fixed price swaps, three-way collars and purchased and sold call options. See “Note 9. Derivative Instruments” for further details of our crude oil and natural gas derivative positions as of June 30, 2017 and “Note 13. Subsequent Events—Hedging” for further details of the crude oil derivative positions entered into subsequent to June 30, 2017.

Forward-Looking Statements

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


•	our growth strategies;


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


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


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

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•	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;


•	our ability to consummate and finance the ExL Acquisition;


•	results of the ExL Properties;


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


•	possible future sales 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 sales;


•	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 of the ExL Acquisition to close, market conditions and other factors affecting our ability to complete the Preferred Stock and warrants issuance, integration and other acquisition risks, other factors affecting our ability to reach agreements or complete acquisitions or dispositions, actions by sellers and buyers, effects of purchase price adjustments, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture parties, results of exploration activities, the availability, market conditions and completion of land acquisitions and dispositions, costs of oilfield services, completion and connection of wells, and other factors detailed in this quarterly report.

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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 June 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 June 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

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.

We may not consummate the ExL Acquisition, and the closing of the related financings are not conditioned on its consummation.

There can be no assurances that the ExL Acquisition will be consummated on the terms described herein or at all, or that the consummation of the ExL Acquisition will not be delayed beyond the expected closing date. If we do not complete the ExL Acquisition, we will not have the opportunity to attempt to realize the benefits we believe the acquisition will afford us.

We have performed only a limited investigation of the ExL Properties. The completion of the ExL Acquisition is subject to specified closing conditions and to the right of one or both of the parties to terminate the transaction including in the event that more than specified adjustments to the purchase price are required. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the ExL Acquisition may not be completed. Some of these conditions are beyond our control, and we may elect not to take actions necessary to satisfy these conditions or to ensure that the transaction is not otherwise terminated.

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If the ExL Acquisition is not consummated, our management will have broad discretion in the application of the net proceeds of our recent equity offering and could apply the proceeds in ways that shareholders may not approve, which could also adversely affect the market price of our common stock. In addition, such application may not be as beneficial to us as the ExL Acquisition may have been. If the ExL Acquisition is delayed, not consummated or consummated on terms different from those described herein, the market price of our common stock may decline. Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationships with our business partners. In addition, pending the potential use of the proceeds of our recent equity offering to fund a portion of the purchase price for the ExL Acquisition, we used the proceeds of our recent equity offering to repay borrowings under our revolving credit facility. Our management will have broad discretion with respect to the use of future drawdowns on our revolving credit facility and may use these funds in ways that shareholders may not support, which could adversely affect the market price of our common stock.

The ExL Acquisition is not conditioned upon our receipt of any financing, and there can be no assurance that we will obtain the funds necessary to complete the ExL Acquisition on acceptable terms or at all. Failure to complete the ExL Acquisition could cause us to be in breach of the purchase and sale agreement, could result in our loss of our deposit paid upon execution of such agreement, litigation and other losses to us, and a decline in the market price of our common stock.

We may not be able to achieve the expected benefits of the ExL Acquisition and may have difficulty integrating with the ExL Acquisition.

Even if we consummate the ExL Acquisition, we may not be able to achieve the expected benefits of the ExL Acquisition. There can be no assurance that the ExL Acquisition will be beneficial to us. We may not be able to integrate and develop the ExL Properties without increases in costs, losses in revenues or other difficulties. Any unexpected costs or delays incurred in connection with the integration and development of the ExL Properties could have an adverse effect on our business, results of operations, financial condition and prospects, as well as the market price of our common stock.

Our assessment of ExL Properties to date has been limited and, even by the time of closing, it will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our assessment, we will not receive an independent reserve engineer report related to the ExL Properties. We may incur costs or experience problems related to the ExL Properties in the ExL Acquisition, and we may not have adequate recourse against ExL. Although we will inspect the properties being sold to us, inspections may not reveal all title, structural or environmental problems. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. Our ability to make specified claims against ExL in the ExL Acquisition generally expires over time and we may be left with no recourse for liabilities and other problems associated with the ExL Acquisition that we do not discover prior to the expiration date related to such matters under the purchase and sale agreement.

The market price of our common stock may decline as a result of the ExL Acquisition if, among other things, the integration and development of the ExL Properties is unsuccessful or if the liabilities, expenses, title, environmental and other defects, or transaction costs related to the ExL Acquisition are greater than expected or the ExL Properties do not yield the anticipated returns. The market price of our common stock may decline if we do not achieve the perceived benefits of the ExL Acquisition as rapidly or to the extent anticipated by us or by securities market participants or if the effect of the ExL Acquisition, including the obligations incurred to finance the ExL Acquisition, on our business results of operations or financial condition or prospects is not consistent with our expectations or those of securities market participants.

Upon consummation of the ExL Acquisition, our overall level of debt and Preferred Stock obligations will increase, which could adversely affect us.

Upon consummation of the ExL Acquisition, our overall debt level will increase after giving effect to the ExL Acquisition, our recent senior notes offering and borrowings to pay the deposit for the ExL Acquisition. In connection with the ExL Acquisition, we will issue Preferred Stock with an aggregate initial liquidation preference of $250.0 million that requires us, upon request of holders of a majority of the then-outstanding shares of Preferred Stock, to redeem the Preferred Stock, in whole or in part, on or after the seventh anniversary of its issuance and upon certain defaults and changes of control. After the completion of the ExL Acquisition, our level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:


•	we may not be able to obtain financing in the future on acceptable terms or at all for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;


•	less-levered competitors could have a competitive advantage because they have lower debt service requirements;


•	credit rating agencies could downgrade our credit ratings following the ExL Acquisition below currently expected levels; and

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•	we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our competitors.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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



Exhibit Number		Exhibit Description
2.1+	—	Purchase and Sale Agreement, dated as of June 28, 2017, by and among ExL Petroleum Management, LLC, ExL Petroleum Operating Inc., Carrizo Oil & Gas, Inc. and Carrizo (Permian) LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 28, 2017 (File No. 000-29187087)).
3.1	—	Articles of Amendment to Amended and Restated Articles of Incorporation of Carrizo Oil & Gas, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
3.2	—	Composite Articles of Incorporation of Carrizo Oil & Gas, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on May 16, 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)).
10.1	—	2017 Incentive Plan of Carrizo Oil & Gas, Inc. effective as of May 16, 2017 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
10.2	—	Form of Director Restricted Stock Unit Agreement under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
10.3	—	Form of Employee Restricted Stock Unit Agreement under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
10.4	—	Ninth Amendment to Credit Agreement, dated as of May 4, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 (File No. 000-29187-87)).
10.5	—	Tenth Amendment to Credit Agreement, dated as of June 28, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2017 (File No. 000-29187087)).
10.6+	—	Preferred Stock Purchase Agreement, dated as of June 28, 2017, by and between Carrizo Oil & Gas, Inc. and the Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2017 (File No. 000-29187087)).
*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.

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+	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:	August 9, 2017	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	August 9, 2017	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

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