UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~FORM 10-Q~~

FORM 10-Q



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

For the quarterly period ended ~~September 30, 2018~~March 31, 2019



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

For the transition period from to

Commission File Number: 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)



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

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

(713) 328-1000

(Registrant’s telephone number)

____________________________________________________________

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

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

~~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

Securities registered pursuant to Section 12(b) of the Act:



Common Stock, $0.01 par value	CRZO	NASDAQ Global Select Market
(Title of class)	(Trading Symbol)	(Name of exchange on which registered)

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of ~~November 2, 2018~~May 3, 2019 was ~~91,625,532.~~92,504,440.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018	2
	Consolidated Statements of Income for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	3
	Consolidated ~~Statement~~Statements of Shareholders’ Equity for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018	4
	Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3327
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4737
Item 4.	Controls and Procedures	4839
Part II. Other Information
Item 1.	Legal Proceedings	4940
Item 1A.	Risk Factors	4940
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4940
Item 3.	Defaults Upon Senior Securities	4940
Item 4.	Mine Safety Disclosures	4940
Item 5.	Other Information	4940
Item 6.	Exhibits	5040
Signatures		5141

Part I. Financial Information

Item 1. Consolidated Financial Statements (Unaudited)

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)


	September 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018
Assets
Current assets
Cash and cash equivalents		$2,415			$9,540			$2,173			$2,282
Accounts receivable, net	128,780			107,441			94,944			99,723
Derivative assets	10,258			—			10,858			39,904
Other current assets	9,636			5,897			9,669			8,460
Total current assets	151,089			122,878			117,644			150,369
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	2,124,767			1,965,347			2,514,178			2,333,470
Unproved properties, not being amortized	579,275			660,287			665,957			673,833
Other property and equipment, net	10,885			10,176			11,880			11,221
Total property and equipment, net	2,714,927			2,635,810			3,192,015			3,018,524
Deposit for pending acquisition of oil and gas properties	21,500			—
Other assets	23,482			19,616
Deferred income taxes							179,146			—
Operating lease right-of-use assets							71,965			—
Other long-term assets							13,222			16,207
Total Assets		$2,910,998			$2,778,304			$3,573,992			$3,185,100

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$147,670			$74,558			$122,941			$98,811
Revenues and royalties payable	52,975			52,154			46,027			49,003
Accrued capital expenditures	117,556			119,452			99,597			60,004
Accrued interest	23,748			28,362			23,314			18,377
Derivative liabilities	162,895			57,121			75,994			55,205
Current operating lease liabilities							35,543			—
Other current liabilities	50,918			41,175			46,508			40,609
Total current liabilities	555,762			372,822			449,924			322,009
Long-term debt	1,327,689			1,629,209			1,714,764			1,633,591
Asset retirement obligations	17,071			23,497			21,521			18,360
Derivative liabilities	102,103			112,332
Long-term operating lease liabilities							42,468			—
Deferred income taxes	4,699			3,635			7,945			8,017
Other liabilities	8,703			51,650
Other long-term liabilities							30,417			47,797
Total liabilities	2,016,027			2,193,145			2,267,039			2,029,774
Commitments and contingencies
Preferred stock
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of September 30, 2018 and 250,000 issued and outstanding as of December 31, 2017	173,629			214,262
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 200,000 issued and outstanding as of March 31, 2019 and December 31, 2018							175,223			174,422
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 91,619,733 issued and outstanding as of September 30, 2018 and 81,454,621 issued and outstanding as of December 31, 2017	916			815
Common stock, $0.01 par value, 180,000,000 shares authorized; 92,503,562 issued and outstanding as of March 31, 2019 and 91,627,738 issued and outstanding as of December 31, 2018							925			916
Additional paid-in capital	2,132,253			1,926,056			2,130,989			2,131,535
Accumulated deficit	(1,411,827		)	(1,555,974		)	(1,000,184		)	(1,151,547		)
Total shareholders’ equity	721,342			370,897			1,131,730			980,904
Total Liabilities and Shareholders’ Equity		$2,910,998			$2,778,304			$3,573,992			$3,185,100

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Revenues
Crude oil		$254,525			$152,101			$679,242			$422,999			$202,744			$194,919
Natural gas liquids	33,798			12,467			71,969			27,678			16,837			16,902
Natural gas	15,052			16,711			41,417			48,440			13,459			13,459
Total revenues	303,375			181,279			792,628			499,117			233,040			225,280

Costs and Expenses
Lease operating	41,022			34,874			115,446			100,767			42,031			39,273
Production taxes	14,516			7,741			37,578			21,092
Ad valorem taxes	2,588			1,736			8,201			5,776
Production and ad valorem taxes													14,894			12,548
Depreciation, depletion and amortization	80,108			67,564			217,005			181,018			75,322			64,467
General and administrative, net	12,811			16,029			58,368			49,328			24,732			27,292
(Gain) loss on derivatives, net	55,388			24,377			152,698			(27,004		)
Loss on derivatives, net													83,284			29,596
Interest expense, net	15,406			20,673			46,522			62,350			16,451			15,517
Loss on extinguishment of debt	—			—			8,676			—			—			8,676
Other (income) expense, net	(690		)	462			2,305			1,640
Other expense, net													4,358			100
Total costs and expenses	221,149			173,456			646,799			394,967			261,072			197,469

Income Before Income Taxes	82,226			7,823			145,829			104,150
Income tax expense	(880		)	—			(1,682		)	—
Income (Loss) Before Income Taxes													(28,032		)	27,811
Income tax (expense) benefit													179,395			(319		)
Net Income		$81,346			$7,823			$144,147			$104,150			$151,363			$27,492
Dividends on preferred stock	(4,457		)	(2,249		)	(13,794		)	(2,249		)	(4,360		)	(4,863		)
Accretion on preferred stock	(771		)	—			(2,264		)	—			(801		)	(753		)
Loss on redemption of preferred stock	—			—			(7,133		)	—			—			(7,133		)
Net Income Attributable to Common Shareholders		$76,118			$5,574			$120,956			$101,901			$146,202			$14,743

Net Income Attributable to Common Shareholders Per Common Share
Basic		$0.88			$0.07			$1.45			$1.44			$1.59			$0.18
Diluted		$0.85			$0.07			$1.42			$1.43			$1.58			$0.18

Weighted Average Common Shares Outstanding
Basic	86,727			81,053			83,461			70,728			91,740			81,542
Diluted	89,039			81,138			85,221			71,147			92,292			82,578

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)


	Common Stock			Additional Paid-in Capital				Accumulated Deficit				Total Shareholders’ Equity			Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount						Accumulated Deficit			Shares				Amount			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
Balance as of December 31, 2018															91,627,738		$916		$2,131,535			($1,151,547	)		$980,904
Stock-based compensation expense															—	—		4,624			—			4,624
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares															875,824	9		(9		)	—			—
Dividends on preferred stock															—	—		(4,360		)	—			(4,360		)
Accretion on preferred stock															—	—		(801		)	—			(801		)
Net income															—	—		—			151,363			151,363
Balance as of March 31, 2019															92,503,562		$925		$2,130,989			($1,000,184	)		$1,131,730

Balance as of December 31, 2017	81,454,621		$815	Additional Paid-in Capital			$1,926,056				($1,555,974	Total Shareholders’ Equity	)		$370,897	81,454,621		$815			$1,926,056			($1,555,974	)		$370,897
Stock-based compensation expense	—	—		15,701				—				15,701			—	—		5,647			—			5,647
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares, net of forfeitures	665,112	6		(75		)		—				(69		)
Sale of common stock, net of offering costs	9,500,000	95		213,762				—				213,857
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares															610,940	6		(12		)	—			(6		)
Dividends on preferred stock	—	—		(13,794		)		—				(13,794		)	—	—		(4,863		)	—			(4,863		)
Accretion on preferred stock	—	—		(2,264		)		—				(2,264		)	—	—		(753		)	—			(753		)
Loss on redemption of preferred stock	—	—		(7,133		)		—				(7,133		)	—	—		(7,133		)	—			(7,133		)
Net income	—	—		—				144,147				144,147			—	—		—			27,492			27,492
Balance as of September 30, 2018	91,619,733		$916		$2,132,253				($1,411,827	)			$721,342
Balance as of March 31, 2018															82,065,561		$821		$1,918,942			($1,528,482	)		$391,281

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

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2019			2018
Cash Flows From Operating Activities
Net income		$144,147			$104,150			$151,363			$27,492
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	217,005			181,018			75,322			64,467
(Gain) loss on derivatives, net	152,698			(27,004		)
Cash received (paid) for derivative settlements, net	(64,710		)	7,714
Loss on derivatives, net							83,284			29,596
Cash paid for commodity derivative settlements, net							(2,638		)	(14,365		)
Loss on extinguishment of debt	8,676			—			—			8,676
Stock-based compensation expense, net	13,786			8,462			4,115			3,518
Deferred income taxes	1,063			—
Deferred income tax (benefit) expense							(179,218		)	193
Non-cash interest expense, net	1,878			2,961			603			662
Other, net	4,100			4,249			1,364			(2,689		)
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(12,763		)	(25,885		)	(4,309		)	10,738
Accounts payable	10,863			14,748			(14,385		)	15,526
Accrued liabilities	(9,336		)	11,970			10,568			(4,317		)
Other assets and liabilities, net	(2,115		)	(1,786		)	(966		)	(773		)
Net cash provided by operating activities	465,292			280,597			125,103			138,724
Cash Flows From Investing Activities
Capital expenditures	(662,459		)	(433,561		)	(171,042		)	(234,685		)
Acquisitions of oil and gas properties	—			(692,006		)	8,222			—
Deposit (paid for pending acquisition) received for pending divestiture of oil and gas properties	(21,500		)	6,200
Proceeds from divestitures of oil and gas properties	377,693			18,212			3,107			342,359
Other, net	(2,687		)	(3,804		)	(880		)	(87		)
Net cash used in investing activities	(308,953		)	(1,104,959		)
Net cash provided by (used in) investing activities							(160,593		)	107,587
Cash Flows From Financing Activities
Issuance of senior notes	—			250,000
Redemptions of senior notes and other long-term debt	(330,435		)	—
Redemptions of senior notes							—			(326,010		)
Redemption of preferred stock	(50,030		)	—			—			(50,030		)
Borrowings under credit agreement	2,415,208			1,311,875			470,632			694,260
Repayments of borrowings under credit agreement	(2,396,671		)	(1,183,275		)	(389,920		)	(563,860		)
Payments of debt issuance costs and credit facility amendment fees	(627		)	(8,964		)
Sale of common stock, net of offering costs	213,857			222,378
Sale of preferred stock, net of issuance costs	—			236,404
Payments of credit facility amendment fees							(613		)	(150		)
Payments of dividends on preferred stock	(13,794		)	(2,249		)	(4,360		)	(4,863		)
Cash paid for settlements of contingent consideration arrangements, net							(40,000		)	—
Other, net	(972		)	(909		)	(358		)	(313		)
Net cash provided by (used in) financing activities	(163,464		)	825,260			35,381			(250,966		)
Net Increase (Decrease) in Cash and Cash Equivalents	(7,125		)	898
Net Decrease in Cash and Cash Equivalents							(109		)	(4,655		)
Cash and Cash Equivalents, Beginning of Period	9,540			4,194			2,282			9,540
Cash and Cash Equivalents, End of Period		$2,415			$5,092			$2,173			$4,885

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

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Operations

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

~~Consolidated Financial Statements~~

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”) 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~~Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

Significant Accounting Policies

The Company’s significant accounting policies are described in ~~this Quarterly Report on Form 10-Q should be read in conjunction with~~“Note 2. Summary of Significant Accounting Policies” of the ~~Company’s audited~~Notes to Consolidated Financial Statements ~~and related notes included~~ in ~~the Company’s~~its Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 (“~~2017~~2018 Annual Report”).

2. ~~Summary of Significant Accounting Policies~~ and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 2018 Annual Report.

Recently Adopted Accounting Standards

~~Revenue From Contracts with Customers~~Leases.. Effective January 1, ~~2018,~~2019, the Company adopted ASU No. ~~2014-09, Revenue From Contracts With Customers~~2016-02, Leases (Topic ~~606)~~842) (“ASC ~~606”~~842”), using the modified retrospective ~~method~~approach and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information for the three and nine months ended September 30, 2017 has not been recast and continues to be reported under the accounting standards in effect for that period. Additionally, adoption of ASC 606 did not impact net income attributable to common shareholders and the Company does not expect that it will do so in future periods.

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

Three Months Ended September 30, 2018
Under ASC 606 Under ASC 605 Increase % Increase
(In thousands)
Revenues
Crude oil
$254,525

$254,382

$143
0.1 %
Natural gas liquids 33,798
32,018
1,780
5.6 %
Natural gas 15,052
14,280
772
5.4 %
Total revenues 303,375
300,680
2,695
0.9 %

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

Income Before Income Taxes
$82,226

$82,226

$—
— %

Nine Months Ended September 30, 2018
Under ASC 606 Under ASC 605 Increase % Increase
(In thousands)
Revenues
Crude oil
$679,242

$678,834

$408
0.1 %
Natural gas liquids 71,969
68,253
3,716
5.4 %
Natural gas 41,417
39,439
1,978
5.0 %
Total revenues 792,628
786,526
6,102
0.8 %

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

Income Before Income Taxes
$145,829

$145,829

$—
— %

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

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

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

~~Recently Issued Accounting Pronouncements~~

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

The Company is in the process of reviewing and determining the contracts to which ASU 2016-02 applies with the assistance of a third party consultant. These include contracts such as non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements, and contracts for the use of vehicles and well equipment. The Company continues to review current accounting policies, controls, processes, and disclosures that will change as a result of adopting the new standard. Based upon its initial assessment, the Company ~~expects~~implemented policy elections and practical expedients which include the ~~adoption~~following:

package of ASU 2016-02 will result in: (i) an increase in assets and liabilities due to the required recognition of ROU assets and corresponding lease liabilities, (ii) increases in depreciation, depletion and amortization and interest expense, (iii) decreases in lease operating and general and administrative expense and (iv) additional disclosures, however, the full impact to the Company’s consolidated financial statements and related disclosures is still being evaluated. Currently,practical expedients which allows the Company ~~plans~~ to ~~make certain elections allowing the Company not to reassess~~avoid reassessing contracts that commenced prior to adoption ~~to continue applying its current~~that were properly evaluated under legacy lease accounting ~~policy for land easements, and not to recognize~~guidance;

excluding ROU assets orand lease liabilities for ~~short-term leases. The Company plans~~leases with terms that are less than one year;

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

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

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

As a result of ~~January 1, 2019. As permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements,~~adopting ASC 842, the Company ~~does not expect to adjust comparative-period financial statements.~~

~~Revenue Recognition~~

~~The Company’s revenues are comprised solely~~recorded lease liabilities of ~~revenues from customers~~approximately $75.2 million and ~~include the sale~~associated ROU assets of crude oil, NGLs, and natural gas. The Company believes that the disaggregation of revenue into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors basedapproximately $69.1 million on its single geographic location. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days of the end of the production month. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in “Accounts receivable, net” in the consolidated balance sheets. ~~As of September 30, 2018~~The difference between the lease liabilities and December 31, 2017, receivables from contracts with customers were $100.2 million and $85.6 million, respectively. Taxes assessed by governmental authorities on crude oil, NGL, and natural gas sales are presented separately from such revenues in the consolidated statements of income.

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

~~Natural gas and NGL sales.~~ ~~Natural gas is delivered~~due to a ~~midstream processing entity at~~rent holiday and lease build-out incentives that were recorded as deferred lease liabilities under legacy lease accounting guidance. The adoption of ASC 842 did not materially change the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. The Company evaluates whether it is the principal or agent in the transaction and has concluded it is the principal and the purchasers of the NGLs and residue gas are the customers. Revenue is recognized on a gross basis, with gathering, processing and transportation fees recognized as lease operating expense in theCompany’s consolidated statements of income ~~as the Company maintains control throughout processing.~~or consolidated statements of cash flows. See “Note 5. Leases” for further discussion.

~~Transaction Price Allocated to Remaining Performance Obligations~~. Subsequent Events

The Company ~~applied~~evaluates subsequent events through the ~~practical expedient in ASC 606 exempting~~date the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation, therefore, future volumesfinancial statements are ~~wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.~~issued. See “Note 15. Subsequent Events” for further discussion.

~~Net Income Attributable to Common Shareholders Per Common Share~~

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

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017

(In thousands, except
per share amounts)
Net Income
$81,346

$7,823

$144,147

$104,150
Dividends on preferred stock (4,457 ) (2,249 ) (13,794 ) (2,249 )
Accretion on preferred stock (771 ) —
(2,264 ) —
Loss on redemption of preferred stock —
—
(7,133 ) —
Net Income Attributable to Common Shareholders
$76,118

$5,574

$120,956

$101,901

Basic weighted average common shares outstanding 86,727
81,053
83,461
70,728
Dilutive effect of restricted stock and performance shares 1,272
85
967
253
Dilutive effect of common stock warrants 1,040
—
793
166
Diluted weighted average common shares outstanding 89,039
81,138
85,221
71,147

Net Income Attributable to Common Shareholders Per Common Share
Basic
$0.88

$0.07

$1.45

$1.44
Diluted
$0.85

$0.07

$1.42

$1.43

The computation of diluted net income attributable to common shareholders per common share excluded restricted stock, performance shares and common stock warrants that were anti-dilutive. The following table presents the weighted average anti-dilutive securities for the periods presented:

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

3. Acquisitions and Divestitures of Oil and Gas Properties

2019 Acquisitions and Divestitures

The Company did not have any material acquisitions or divestitures for the three months ended March 31, 2019.

2018 Acquisitions and Divestitures

Devon Acquisition. On August 13, 2018, the Company entered into a purchase and sale agreement with Devon Energy Production Company, L.P. (“Devon”), a subsidiary of Devon Energy Corporation, to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas (the ~~“Devon~~��Devon Properties”) for an agreed upon price of $215.0 million, with an effective date of April 1, 2018, subject to customary purchase price adjustments (the “Devon Acquisition”). The Company paid $21.5 million as a deposit on August 13, 2018, ~~and~~ $183.4 million upon initial closing on October 17, 2018, ~~which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date,~~and received $8.3 million as a post-closing adjustment on March 28, 2019, for an ~~estimated~~ aggregate purchase price of ~~$204.9~~$196.6 million. ~~The final purchase price remains subject to post-closing adjustments.~~

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

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

The Devon Acquisition ~~will be~~was accounted for as a business ~~combination.~~combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The ~~Company has not completed its initial~~following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed ~~based on their estimated acquisition date fair values. The Company will disclose the allocation~~as of the ~~purchase price as well as other related disclosures~~acquisition date.



	Preliminary Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$216
Oil and gas properties
Proved properties	47,118
Unproved properties	150,253
Total oil and gas properties		$197,587
Total assets acquired		$197,587

Liabilities
Revenues and royalties payable		$786
Asset retirement obligations	170
Total liabilities assumed		$956
Net Assets Acquired		$196,631

Included in ~~its Annual Report on Form 10-K~~the consolidated statements of income for the ~~year~~three months ended ~~December~~March 31, ~~2018.~~

~~Delaware Basin Divestiture.~~ ~~On July 11, 2018,~~2019 are total revenues of $4.4 million and net income attributable to common shareholders of $2.7 million from the Company closed on the divestiture of certain non-operated assets in the Delaware Basin for an agreed upon price of $30.0 million, with an effective date of May 1, 2018, subject to customary purchase price adjustments. The Company received $31.4 million upon closing on July 11, 2018 and paid $0.5 million upon post-closing on October 22, 2018, for aggregate net proceeds of $30.9 million.Devon Acquisition.

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

Niobrara Divestiture. On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. The Company received $14.0 million as a deposit on November 20, 2017, $122.6 million upon closing on January 19, 2018, and paid $1.0 million ~~upon~~as a post-closing adjustment on August 14, 2018, for aggregate net proceeds of $135.6 million. As part of this divestiture, the Company agreed to a contingent consideration arrangement (the “Contingent Niobrara Consideration”), which was determined to be an embedded derivative. As a result, the asset is recorded at fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value between periods recognized in the consolidated statements of income in the period in which the changes occur. See “Note ~~10.~~12. Derivative Instruments” and “Note ~~11.~~13. Fair Value Measurements” for further ~~details.~~discussion.

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

~~2017 Acquisitions and Divestitures~~

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

The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included forward oil and gas price curves, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included forward oil and gas price curves, volatility factors, and a risk adjusted discount rate. See “Note 11. Fair Value Measurements” for further details.

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



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

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

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

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

$14,016

$167,764

$14,016

Net Income Attributable to Common Shareholders
$57,466

$11,393

$134,317

$11,393

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

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
(In thousands, except per share amounts)
Total revenues
$189,499

$534,607
Net Income Attributable to Common Shareholders
$14,654

$115,053

Net Income Attributable to Common Shareholders Per Common Share
Basic
$0.18

$1.63
Diluted
$0.18

$1.62

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

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

Effective August 2008, the Company’s wholly-owned subsidiary, Carrizo (Marcellus) LLC, entered into a joint venture with ACP II Marcellus LLC (“ACP II”), an affiliate of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP, together with its affiliates, “Avista”). There have been no revenues, expenses, or operating cash flows in the Avista Marcellus joint venture during the years ended December 31, 2015, 2016 and 2017 or during the nine months ended September 30, 2018. The Avista Marcellus joint venture agreements terminated during the third quarter of 2018 in connection with the sale of the remaining immaterial assets.

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

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

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

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

~~2016 Acquisitions and Divestitures~~

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

~~The Company did not have any material divestitures in 2016.~~

4. Property and Equipment, Net

As of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, total property and equipment, net consisted of the following:


	September 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018
	(In thousands)						(In thousands)
Oil and gas properties, full cost method
Proved properties		$5,988,301			$5,615,153			$6,533,028			$6,278,321
Accumulated depreciation, depletion and amortization and impairments	(3,863,534		)	(3,649,806		)	(4,018,850		)	(3,944,851		)
Proved properties, net	2,124,767			1,965,347			2,514,178			2,333,470
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	516,537			612,589			595,217			608,830
Capitalized interest	62,738			47,698			70,740			65,003
Total unproved properties, not being amortized	579,275			660,287			665,957			673,833
Other property and equipment	28,134			25,625			30,550			29,191
Accumulated depreciation	(17,249		)	(15,449		)	(18,670		)	(17,970		)
Other property and equipment, net	10,885			10,176			11,880			11,221
Total property and equipment, net		$2,714,927			$2,635,810			$3,192,015			$3,018,524

Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was ~~$13.29~~$13.27 and ~~$13.04~~$13.73 for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017, respectively, and $13.57 and $12.73 for the nine months ended September 30, 2018 and 2017, respectively.~~2018.

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration, and development activities totaling ~~$2.9~~$9.1 million and ~~$3.3~~$6.6 million for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017, respectively, and $15.6 million and $10.6 million for the nine months ended September 30, 2018 and 2017, respectively.~~2018.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling ~~$8.5~~$9.0 million and $10.4 million for the three months ended ~~September 30, 2018~~March 31, 2019 and ~~2017~~2018.

5. Leases

The Company determines if an arrangement is a lease at inception of the contract and, ~~$27.6 million and $16.2 million~~if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the ~~nine~~lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.

Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.

Types of Leases

The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.

Drilling Rigs. The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.

Office Space. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years. The Company has determined that it cannot conclude with reasonable

certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative, net” in its consolidated statements of income.

Well Equipment. The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating expense” in the Company’s statements of income.

The tables below, which present the components of lease costs, supplemental balance sheet information, and supplemental cash flow information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.

The table below presents the components of the Company’s lease costs for the three months ended ~~September 30, 2018~~March 31, 2019.



	Three Months Ended March 31, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs
Amortization of right-of-use assets ⁽¹⁾		$374
Interest on lease liabilities ⁽²⁾	145
Operating lease costs ⁽³⁾	14,080
Short-term lease costs ⁽⁴⁾	218
Variable lease costs ⁽⁵⁾	102
Total lease costs		$14,919


(1)	Included as a component of “Depletion, depreciation and amortization” in the consolidated statements of income.


(2)	Included as a component of “Interest expense, net” in the consolidated statements of income.


(3)	Approximately $11.5 million are costs associated with drilling rigs and are capitalized to “Oil and gas properties” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative, net” and “Lease operating expense” in the consolidated statements of income.


(4)	Short-term lease costs are primarily associated with certain well equipment that have lease terms for less than one year and are components of “Lease operating expense” in the consolidated statements of income.


(5)	Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.

The table below presents supplemental balance sheet information for the Company’s leases as of March 31, 2019.



	March 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$71,965

Current operating lease liabilities		$35,543
Long-term operating lease liabilities	42,468
Total operating lease liabilities		$78,011

Financing leases:
Other property and equipment, at cost		$7,810
Accumulated depreciation	(4,759		)
Other property and equipment, net		$3,051

Current financing lease liabilities ⁽¹⁾		$1,829
Long-term financing lease liabilities ⁽²⁾	1,549
Total financing lease liabilities		$3,378


(1)	Included in “Other current liabilities” in the consolidated balance sheets.


(2)	Included in “Other long-term liabilities” in the consolidated balance sheets.

The table below presents supplemental cash flow information for the Company’s leases for the three months ended March 31, 2019.



	Three Months Ended March 31, 2019
	(In thousands)
Supplemental Cash Flow Information
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$2,575
Investing cash flows from operating leases		$13,596
Operating cash flows from financing leases		$145
Financing cash flows from financing leases		$453

ROU assets obtained in exchange for lease liabilities
Operating leases		$11,153
Financing leases		$1,082

The table below presents the weighted average remaining lease terms and ~~2017, respectively.~~weighted average discount rates for the Company’s leases as of March 31, 2019.



	March 31, 2019
Weighted Average Remaining Lease Term (In years)
Operating leases	4.5 years
Financing leases	2.4 years

Weighted Average Discount Rate
Operating leases	8.0	%
Financing leases	13.8	%

The table below presents the maturity of the Company’s lease liabilities as of March 31, 2019.



	Operating Leases			Financing Leases
	(In thousands)
April - December 2019		$30,983			$1,669
2020	27,098			1,475
2021	7,355			275
2022	3,645			234
2023	3,680			233
2024 and Thereafter	21,499			39
Total lease payments	94,260			3,925
Less: Imputed interest	(16,249		)	(547		)
Total lease liabilities		$78,011			$3,378

5.6. Income Taxes

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense or benefit to interim periods. The rates are the ratio of estimated annual income tax expense or benefit to estimated annual income or loss before income taxes by taxing jurisdiction, excluding significant unusual or infrequent items, the tax effects of statutory rate changes, certain changes in the assessment of the realizability of deferred tax assets, and excess tax benefits or deficiencies related to the vesting of stock-based compensation awards, which are recognized as discrete items in the interim period in which they occur.

The Company’s income tax ~~expense differs~~(expense) benefit differed from the income tax ~~expense~~(expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 21% for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 35% for the three and nine months ended September 30, 2017,~~ to income (loss) before income taxes as follows:

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
(In thousands)
Income before income taxes
$82,226

$7,823

$145,829

$104,150
Income tax expense at the U.S. federal statutory rate (17,267 ) (2,738 ) (30,624 ) (36,452 )
State income tax expense, net of U.S. federal income tax benefit (881 ) (247 ) (1,687 ) (1,974 )
Tax deficiencies related to stock-based compensation (10 ) (273 ) (2,552 ) (3,029 )
Decrease in valuation allowance due to current period activity 17,400
3,253
33,849
41,570
Other (122 ) 5
(668 ) (115 )
Income tax expense
($880 )
$—

($1,682 )
$—

~~Tax Cuts and Jobs Act~~

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



	Three Months Ended March 31,
	2019			2018
	(In thousands)
Income (loss) before income taxes		($28,032	)		$27,811
Income tax (expense) benefit at the U.S. federal statutory rate	5,887			(5,840		)
State income tax (expense) benefit, net of U.S. federal income tax benefit	248			(319		)
Tax deficiencies related to stock-based compensation	(1,938		)	(2,526		)
Release of valuation allowance	179,146			—
(Increase) decrease in valuation allowance due to current period activity	(3,938		)	8,401
Other	(10		)	(35		)
Income tax (expense) benefit		$179,395			($319	)

Deferred Tax Asset Valuation Allowance

The deferred tax asset valuation allowance was ~~$299.1~~$67.7 million and ~~$333.0~~$242.9 million as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, respectively. ~~Decreases in the valuation allowance for the three months and nine months ended September 30, 2018 and 2017 were based primarily on the pre-tax income recorded during those periods.~~

Throughout ~~2017 and the first nine months of~~ 2018, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that

the deferred tax assets would not be realized. ~~The~~A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016. As of March 31, 2019, the Company ~~intends to maintain~~is in a ~~full valuation allowance against its~~cumulative pre-tax income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and future years, the Company concluded that it is more likely than not that the deferred tax assets ~~until there~~would be realized and released $179.1 million of the valuation allowance, which is ~~sufficient evidence to support~~recognized as an increase in deferred tax assets and an income tax benefit for the ~~reversal of such valuation allowance.~~three months ended March 31, 2019.

6.7. Long-Term Debt

Long-term debt consisted of the following as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017:~~2018:


	September 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018
	(In thousands)						(In thousands)
Senior Secured Revolving Credit Facility due 2022		$309,837			$291,300			$825,143			$744,431
7.50% Senior Notes due 2020	130,000			450,000
Unamortized premium for 7.50% Senior Notes	124			579
Unamortized debt issuance costs for 7.50% Senior Notes	(980		)	(4,492		)
6.25% Senior Notes due 2023	650,000			650,000			650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(7,219		)	(8,208		)	(6,532		)	(6,878		)
8.25% Senior Notes due 2025	250,000			250,000			250,000			250,000
Unamortized debt issuance costs for 8.25% Senior Notes	(4,073		)	(4,395		)	(3,847		)	(3,962		)
Other long-term debt due 2028	—			4,425
Long-term debt		$1,327,689			$1,629,209			$1,714,764			$1,633,591

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of ~~September 30, 2018,~~March 31, 2019, had a borrowing base of ~~$1.0~~$1.35 billion, with an elected commitment amount of ~~$900.0 million,~~$1.25 billion, and borrowings outstanding of ~~$309.8~~$825.1 million at a weighted average interest rate of ~~3.87%~~4.18%. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022, ~~(subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”) have not been redeemed or refinanced on or prior to such time),~~ when the credit agreement matures and any outstanding borrowings are due. See “Note 14. Subsequent Events” for details regarding the maturity date of the credit agreement upon redemption of the remaining $130.0 million outstanding aggregate principal amount of its 7.50% Senior Notes. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

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

~~On May 4, 2018,~~March 27, 2019, the Company entered into the ~~twelfth~~fourteenth amendment to its credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at ~~$1.0~~$1.35 billion, with an elected commitment amount of ~~$900.0 million,~~$1.25 billion, until the next redetermination thereof, (ii) ~~reduce the applicable margins for Eurodollar loans from 2.00%-3.00% to 1.50%-2.50% and base rate loans from 1.00%-2.00% to 0.50%-1.50%, each depending on level of facility usage, (iii)~~ amend the ~~covenant limiting payment~~definition of ~~dividends~~Current Ratio, and ~~distributions on equity to increase the Company’s ability to make dividends and distributions on its equity interests and (iv)~~(iii) amend certain other ~~provisions, in each case as set forth therein.~~

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

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

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


Ratio of Outstanding Borrowings to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	0.50%	1.50%	0.375%	0.25%	1.25%	0.375%
Greater than or equal to 25% but less than 50%	0.75%	1.75%	0.375%	0.50%	1.50%	0.375%
Greater than or equal to 50% but less than 75%	1.00%	2.00%	0.500%	0.75%	1.75%	0.500%
Greater than or equal to 75% but less than 90%	1.25%	2.25%	0.500%	1.00%	2.00%	0.500%
Greater than or equal to 90%	1.50%	2.50%	0.500%	1.25%	2.25%	0.500%

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt ~~premiums and debt~~ issuance costs and is net of cash and cash equivalents, EBITDA ~~will be~~is calculated based on the last four fiscal quarters after giving pro forma effect to EBITDA for material acquisitions and divestitures of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender ~~commitments.~~commitments and excludes the Contingent ExL Consideration, which is described in “Note 12. Derivative Instruments.” As of ~~September 30, 2018,~~March 31, 2019, the ratio of Total Debt to EBITDA was ~~1.95~~2.40 to 1.00 and the Current Ratio was ~~1.84~~1.58 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings.

The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions

of senior notes, investments, acquisitions and divestitures of oil and gas properties, mergers, transactions with affiliates, hedging transactions and other matters.

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

Redemptions of 7.50% Senior Notes

During the first quarter of 2018, the Company redeemed $320.0 million of the outstanding aggregate principal amount of its 7.50% Senior Notes at a price equal to 101.875% of par. ~~Upon~~The Company paid a total of $336.9 million upon the redemptions, ~~the Company paid $336.9 million,~~ which included redemption premiums of $6.0 million and accrued and unpaid interest of $10.9 million. The redemptions were funded primarily from the net proceeds received from the divestitures in Eagle Ford and Niobrara in the first quarter of 2018. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of these divestitures. As a result of the redemptions, the Company recorded a loss on extinguishment of debt of $8.7 million, which included the redemption premiums of $6.0 million and the write-off of associated unamortized premiums and debt issuance costs of $2.7 million.

~~See “Note 14. Subsequent Events” for details~~Subsidiary Guarantors

The Company’s Senior Notes are guaranteed by its subsidiary guarantors, which are all 100% owned by the parent company. The guarantees are full and unconditional and joint and several. Carrizo Oil & Gas, Inc., as the parent company, has no independent assets and operations. Any subsidiaries of the ~~notice of conditional redemption for~~parent company, other than the ~~remaining $130.0 million outstanding aggregate principal amount of its 7.50% Senior Notes.~~

~~Redemption of Other Long-Term Debt~~

~~On May 3, 2018,~~subsidiary guarantors, are minor. In addition, there are no significant restrictions on the Company redeemed the remaining $4.4 million outstanding aggregate principal amount of its 4.375% Convertible Senior Notes due 2028 at a price equal to 100% of par. Upon the redemption, the Company paid $4.5 million, which included accrued and unpaid interest of $0.1 million.

~~Issuance of 8.25% Senior Notes~~

On July 14, 2017, the Company closed a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The Company used the proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to fund a portionability of the ~~ExL Acquisition and for general corporate purposes. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.~~parent company or any guarantor to obtain funds from its subsidiaries by dividend or loan.

7.8. Commitments and Contingencies

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

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

8.9. Preferred Stock and Common Stock Warrants

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

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

See “Note 9. Preferred Stock and Common Stock Warrants” of the ~~private placement occurred on August 10, 2017, contemporaneously with~~Notes to Consolidated Financial Statements in the ~~closing~~2018 Annual Report for details of the ~~ExL Acquisition. The Company used~~Company’s redemption options and the ~~proceeds of approximately $236.4 million, net of issuance costs, to fund a portion~~rights of the ~~ExL Acquisition and for general corporate purposes.~~ holders of the Preferred Stock.

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



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

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

The table below sets forth a reconciliation of changes in the carrying amount of Preferred Stock ~~outstanding is not mandatorily redeemable, but can be redeemed at~~for the ~~Company’s option~~three months ended March 31, 2019 and ~~in certain circumstances, at the option~~2018.



	Three Months Ended March 31,
	2019		2018
	(In thousands)
Preferred Stock, beginning of period		$174,422		$214,262
Redemption of Preferred Stock	—		(42,897		)
Accretion on Preferred Stock	801		753
Preferred Stock, end of period		$175,223		$172,118

Loss on Redemption of ~~the holders of the~~ Preferred ~~Stock.~~ Stock

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

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



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

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

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

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

~~Upon the occurrence of certain changes of control.~~

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

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

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

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

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

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

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



	~~Carrying Amount of Preferred Stock~~
	~~(In thousands)~~
~~December 31, 2017~~		~~$214,262~~
~~Redemption of Preferred Stock~~	~~(42,897~~		)
~~Accretion on Preferred Stock~~	~~2,264~~
~~September 30, 2018~~		~~$173,629~~

~~Loss on Redemption of Preferred Stock~~

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

~~9. Shareholders’ Equity and~~10. Stock-Based Compensation

~~Sales~~As of ~~Common Stock~~

~~On August 17, 2018, the Company completed a public offering of 9.5 million~~March 31, 2019, there were 152,724 shares of ~~its~~ common stock ~~at a price per share of $22.55. The Company used the proceeds of $213.9 million, net of offering costs, to fund the Devon Acquisition and~~available for general corporate purposes. Pending the closing of the Devon Acquisition, the Company used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the Devon Acquisition.

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

~~Stock-Based Compensation~~

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

The 2017 Incentive Plan provides that up to 2,675,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan at the effective date of the 2017 Incentive Plan, may be granted (the “Maximum Share Limit”). Each restricted stock award and unit and performance share granted under the 2017 Incentive Plan counts as 1.35 shares against the Maximum Share Limit. Each stock option and stock appreciation right to be settled in shares of common stock granted under the 2017 Incentive Plan counts as 1.00 share against the Maximum Share Limit. Stock appreciation rights to be settled in cash granted under the 2017 Incentive Plan and stock appreciation rights granted under the Cash SAR Plan (collectively, “Cash SARs”) do not count against the Maximum Share Limit. Restricted stock awards and units, performance shares, and Cash SARs activity during the nine months ended September 30, 2018 is presented below. The Company has not granted stock appreciation rights to be settled in shares of common stock and has no outstanding stock options. AsSee “Note 11. Stock-Based Compensation” of ~~September 30,~~the Notes to Consolidated Financial Statements in the 2018 ~~there were 296,654 shares~~Annual Report for details of ~~common stock available for grant under~~ the ~~2017 Incentive Plan.~~Company’s equity-based incentive plans.

Restricted Stock Awards and Units

The table below summarizes restricted stock award and unit activity for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018:


	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Three Months Ended March 31,
Unvested restricted stock awards and units, beginning of period	1,482,655			$28.07
					2019				2018
					Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
Unvested, beginning of period					2,266,667			$19.28	1,482,655			$28.07
Granted	1,391,422			$15.07	1,918,683			$11.01	1,347,165			$14.68
Vested	(615,762	)		$31.44	(851,456	)		$20.64	(564,912	)		$31.87
Forfeited	(23,880	)		$18.51	(13,834	)		$17.16	(1,078	)		$29.61
Unvested restricted stock awards and units, end of period	2,234,435			$19.14
Unvested, end of period					3,320,060			$14.16	2,263,830			$19.15

~~During the nine months ended September 30, 2018, the Company granted 1,391,422 restricted stock awards and units~~Grant activity primarily ~~consisting~~consisted of ~~1,343,412~~ restricted stock units to employees ~~and independent contractors~~ as part of ~~its~~the annual grant of long-term equity incentive awards ~~during~~that occurred in the first quarter of ~~2018. These restricted stock units had a grant date fair value~~each of ~~$19.7 million~~the years presented in the table above and vest ratably over an approximate three-year period. ~~During~~The Company currently intends to settle the ~~third quarter of 2018, the Company granted 33,536~~ restricted stock units granted in the first quarter of 2019 in cash upon vesting if the proposed amendment and restatement of the 2017 Incentive Plan is not approved by shareholders at the Company’s annual meeting of shareholders on May 16, 2019. As such, these restricted stock units were accounted for as liability awards. The liability for these restricted stock units as of March 31, 2019 was $0.6 million and was classified as “Other current liabilities” in the consolidated balance sheets. If the amendment and restatement of the 2017 Incentive Plan is approved, the Company intends to ~~its non-employee directors, which had a grant date~~settle these restricted stock units in common stock rather than cash upon vesting.

The aggregate fair value of ~~$0.9~~restricted stock awards and units that vested during the three months ended March 31, 2019 and 2018 was $9.8 million and $8.9 million, respectively. As of March 31, 2019, unrecognized compensation costs related to unvested restricted stock awards and units were $42.1 million and will ~~vest on the earlier~~be recognized over a weighted average period of ~~the date of the 2019 Annual Meeting of Shareholders and June 30, 2019.~~

2.4 years. As of ~~September 30,~~March 31, 2018, unrecognized compensation costs related to unvested restricted stock awards and units were ~~$26.8~~$35.0 million ~~and will~~to be recognized over a weighted average period of ~~2.0~~2.4 years.

Cash SARs

The table below summarizes the ~~Cash SAR~~ activity for stock appreciation rights that will be settled in cash (“Cash SARs”) for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018:


									Three Months Ended March 31,
									2019				2018
	Cash SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)		Cash SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Cash SARs	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)
Outstanding, beginning of period	714,238		$27.12						1,330,924		$21.35		714,238		$27.12
Granted	616,686		$14.67						770,775		$10.98		616,686		$14.67
Exercised	—		$—					$—	—		$—		—		$—
Forfeited	—		$—						—		$—		—		$—
Expired	—		$—						—		$—		—		$—
Outstanding, end of period	1,330,924		$21.35	4.6		$6.5			2,101,699		$17.55	5.1	1,330,924		$21.35	5.1
Vested, end of period	543,018		$27.18						919,800		$24.34		543,018		$27.18
Vested and exercisable, end of period	—		$27.18	2.8		$—			—		$24.34	3.2	—		$27.18	3.3

~~During the nine months ended September 30, 2018, the Company granted 616,686~~Grant activity primarily consisted of Cash SARs to certain employees ~~and independent contractors, all~~as part of ~~which~~the annual grant of long-term equity incentive awards that occurred in the first quarter of ~~2018 as part~~each of the ~~Company’s annual grant~~years presented in the table above. The Cash SARs granted in the first quarter of ~~long-term equity incentive awards. These Cash SARs~~2019 and 2018 vest ratably over an approximate three-year period and expire approximately seven years from the grant date.

The grant date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model, was $4.6 million and $4.9 ~~million.~~million for the three months ended March 31, 2019 and 2018. The following table summarizes the assumptions used ~~to calculate~~and the resulting grant date fair value of the Cash SARs granted during the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018:



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



	Three Months Ended March 31,
	2019		2018
Expected term (in years)	6.1		6.0
Expected volatility	56.0	%	54.3	%
Risk-free interest rate	2.6	%	2.8	%
Dividend yield	—	%	—	%
Grant date fair value per Cash SAR	$6.00		$7.89

The aggregate intrinsic value of Cash SARs outstanding as of March 31, 2019 and 2018 was $1.1 million and $0.7 million, respectively, and the aggregate intrinsic value of Cash SARs vested and exercisable as of March 31, 2019 and 2018 was zero. The liability for Cash SARs as of ~~September 30, 2018~~March 31, 2019 was ~~$7.9~~$2.5 million, all of which was classified as “Other current liabilities,” in the consolidated balance sheets. As of December 31, ~~2017,~~2018, the liability for Cash SARs was ~~$4.4~~$1.8 million, all of which was classified as “Other current liabilities” in the consolidated balance sheets. ~~Unrecognized~~As of March 31, 2019, unrecognized compensation costs related to unvested Cash SARs were ~~$8.7~~$7.8 million ~~as of September 30, 2018,~~ and will be recognized over a weighted average period of ~~2.4~~2.7 years. As of March 31, 2018, unrecognized compensation costs related to unvested Cash SARs were $5.8 million to be recognized over a weighted average period of 2.8 years.

Performance Shares

The table below summarizes performance share activity for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018:


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


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

~~During~~Grant activity primarily consisted of performance shares as part of the ~~nine months ended September 30, 2018, the Company granted 93,771 target performance shares~~annual grant of long-term equity incentive awards to certain employees ~~and independent contractors, all of which~~that occurred in the first quarter of ~~2018 as part of the Company’s annual grant of long-term equity incentive awards.~~2019 and 2018. Each performance share represents the right to receive one share of common stock, however, the number of performance shares that vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three-year performance period, the last day of which is also the vesting date.

~~During~~The following table presents the ~~first quarter of 2018, as a result~~results of the Company’s final TSR ranking during the performance ~~period, a multiplier of 88% was applied to~~periods that ended during the ~~56,517 target performance shares that were granted in 2015, resulting in~~three months ended March 31, 2019 and 2018:



	Three Months Ended March 31,
	2019		2018
Target performance shares granted	41,651		56,517
Multiplier	75	%	88	%
Performance shares vested	31,244		49,458
Performance shares that did not vest	10,407		7,059
Aggregate fair value of performance shares vested (In thousands)	$357		$768

For the ~~vesting of 49,458 shares~~three months ended March 31, 2019 and ~~7,059 shares that did not vest.~~

~~The~~2018, the grant date fair value of the performance shares, calculated using a Monte Carlo simulation, was $1.9 million and $1.8 ~~million.~~million, respectively. The following table summarizes the assumptions used ~~to calculate~~and the resulting grant date fair value ofper performance share for the performance shares granted during the ~~nine~~three months ended ~~September 30, 2018:~~March 31, 2019:



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



	Three Months Ended March 31,
	2019		2018
Number of simulations	500,000		500,000
Expected term (in years)	3.1		3.0
Expected volatility	58.2	%	61.5	%
Risk-free interest rate	2.5	%	2.4	%
Dividend yield	—	%	—	%
Grant date fair value per performance share	$14.20		$19.09

As of ~~September 30, 2018,~~March 31, 2019, unrecognized compensation costs related to unvested performance shares were ~~$2.5~~$3.5 million and will be recognized over a weighted average period of ~~2.0~~2.3 years. As of March 31, 2018, unrecognized compensation costs related to unvested performance shares were $3.3 million to be recognized over a weighted average period of 2.4 years.

Stock-Based Compensation Expense, Net

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

The Company recognized the following stock-based compensation expense, net for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 and ~~2017:~~2018:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
	(In thousands)												(In thousands)
Restricted stock awards and units		$4,487			$5,311			$14,291			$16,184			$4,823			$5,084
Cash SARs	(868		)	429			3,505			(7,040		)	760			(1,415		)
Performance shares	411			581			1,374			1,861			435			557
	4,030			6,321			19,170			11,005			6,018			4,226
Less: amounts capitalized to oil and gas properties	(968		)	(1,455		)	(5,384		)	(2,543		)	(1,903		)	(708		)
Total stock-based compensation expense, net		$3,062			$4,866			$13,786			$8,462			$4,115			$3,518

~~10.~~11. Net Income Attributable to Common Shareholders Per Common Share

The following table summarizes the calculation of net income attributable to common shareholders per common share:



	Three Months Ended March 31,
	2019			2018
	(In thousands, except per share amounts)
Net Income		$151,363			$27,492
Dividends on preferred stock	(4,360		)	(4,863		)
Accretion on preferred stock	(801		)	(753		)
Loss on redemption of preferred stock	—			(7,133		)
Net Income Attributable to Common Shareholders		$146,202			$14,743

Basic weighted average common shares outstanding	91,740			81,542
Dilutive effect of restricted stock and performance shares	552			637
Dilutive effect of common stock warrants	—			399
Diluted weighted average common shares outstanding	92,292			82,578

Net Income Attributable to Common Shareholders Per Common Share
Basic		$1.59			$0.18
Diluted		$1.58			$0.18



	Three Months Ended March 31,
	2019	2018
	(In thousands)
Anti-dilutive restricted stock and performance shares	366	98
Anti-dilutive common stock warrants	2,750	—
Total weighted average anti-dilutive securities	3,116	98

12. Derivative Instruments

Commodity Derivative Instruments

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

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

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

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

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

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

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

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

natural gas basis swaps is NYMEX Henry Hub minus a fixed price differential and the index price it pays is Platt’s Inside FERC West Texas Waha (“Waha”).

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

As of ~~September 30, 2018,~~March 31, 2019, the Company had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:


Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)			Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	4Q18	Price Swaps	NYMEX WTI	6,000		$49.55	—		—		—		—
Crude oil	4Q18	Three-Way Collars	NYMEX WTI	24,000	—			$39.38		$49.06		$60.14	—			2Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	4Q18	Basis Swaps	LLS-WTI Cushing	18,000	—		—		—		—			$5.11		2Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	4Q18	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			($0.10	)	2Q19	Basis Swaps	WTI Midland-WTI Cushing	7,609	—		—		—		—			($4.38	)
Crude oil	4Q18	Sold Call Options	NYMEX WTI	3,388	—		—		—			$71.33	—			2Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	2019	Three-Way Collars	NYMEX WTI	21,000	—			$40.71		$49.80		$67.80	—			3Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	2019	Basis Swaps	LLS-WTI Cushing	3,000	—		—		—		—			$4.57		3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	2019	Basis Swaps	WTI Midland-WTI Cushing	7,389	—		—		—		—			($4.82	)	3Q19	Basis Swaps	WTI Midland-WTI Cushing	9,100	—		—		—		—			($4.44	)
Crude oil	2019	Sold Call Options	NYMEX WTI	3,875	—		—		—			$73.66	—			3Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	13,000	—		—		—		—			($1.27	)	4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—			4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)
Crude oil																4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			$0.03		2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—
Crude oil																2020	Three-Way Collars	NYMEX WTI	6,000	—			$45.00		$55.00		$64.69	—
Crude oil																2020	Basis Swaps	WTI Midland-WTI Cushing	10,658	—		—		—		—			($1.68	)
Crude oil																2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—

Crude oil																2021	Basis Swaps	WTI Midland-WTI Cushing	8,000	—		—		—		—			$0.18

Commodity Period Type of Contract Index
Volumes
(Bbls
per day)

Fixed Price
($ per
Bbl)

Sub-Floor Price
($ per
Bbl)

Floor Price
($ per
Bbl)

Ceiling Price
($ per
Bbl)

Fixed
Price
Differential
($ per
Bbl)
NGLs 4Q18 Price Swaps OPIS-Ethane 2,200

$12.01
—
—
—
—
NGLs 4Q18 Price Swaps OPIS-Propane 1,500

$34.23
—
—
—
—
NGLs 4Q18 Price Swaps OPIS-Butane 200

$38.85
—
—
—
—
NGLs 4Q18 Price Swaps OPIS-Isobutane 600

$38.98
—
—
—
—
NGLs 4Q18 Price Swaps OPIS-Natural Gasoline 600

$55.23
—
—
—
—


Commodity	Period	Type of Contract	Index	Volumes (MMBtu per day)	Fixed Price ($ per MMBtu)		Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)		Fixed Price Differential ($ per MMBtu)	Period	Type of Contract	Index	Volumes (MMBtu per day)	Fixed Price ($ per MMBtu)	Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)		Fixed Price Differential ($ per MMBtu)
Natural gas	4Q18	Price Swaps	NYMEX Henry Hub	25,000		$3.01	—	—	—		—	2Q19	Basis Swaps	Waha-NYMEX Henry Hub	14,000	—	—	—	—			($2.12	)
Natural gas	4Q18	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.25	—	2Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—

Natural gas	2019	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.25	—	3Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.60	)
Natural gas												3Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—

Natural gas	2020	Sold Call Options	NYMEX Henry Hub	33,000	—		—	—		$3.50	—	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.05	)
Natural gas												4Q19	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.25	—

Natural gas												2020	Basis Swaps	Waha-NYMEX Henry Hub	25,811	—	—	—	—			($0.71	)
Natural gas												2020	Sold Call Options	NYMEX Henry Hub	33,000		—	—		$3.50	—

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

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

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

Because each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. ~~The~~As of March 31, 2019, the Company ~~executes its~~has outstanding commodity derivative instruments with ~~seventeen~~fifteen counterparties to minimize its credit exposure to any individual counterparty.

Contingent Consideration Arrangements

The purchase and sale agreements for the acquisition of properties in the Delaware Basin from ExL ~~Acquisition~~Petroleum Management, LLC and ExL Petroleum Operating Inc. (the “ExL Acquisition”) in 2017 and divestitures of the Company’s assets in the Niobrara in 2018, and Marcellus and Utica in 2017, included contingent consideration arrangements that require the Company to pay or entitle the Company to receive ~~or require the Company to pay~~ specified amounts if commodity prices exceed specified thresholds, which are summarized in the ~~table~~tables below. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to Consolidated Financial Statements in the 2018 Annual Report for ~~details~~further discussion of these ~~acquisitions and divestitures.~~transactions. See “—Cash received (paid) for settlements of contingent consideration arrangements, net” below for discussion of the settlements that occurred during the first quarter of 2019.

Contingent ExL Consideration

Contingent Consideration Arrangements Years
Threshold ⁽¹⁾
Contingent Receipt (Payment) - Annual Contingent Receipt (Payment) - Aggregate Limit
(In thousands)
Contingent ExL Consideration 2018
$50.00

($50,000 )
2019 50.00
(50,000 )
2020 50.00
(50,000 )
2021 50.00
(50,000 )
($125,000 )

Contingent Niobrara Consideration 2018
$55.00

$5,000

2019 55.00
5,000

2020 60.00
5,000
—

Contingent Marcellus Consideration 2018
$3.13

$3,000

2019 3.18
3,000

2020 3.30
3,000

$7,500

Contingent Utica Consideration 2018
$50.00

$5,000

2019 53.00
5,000

2020 56.00
5,000
—



	Year	Threshold ⁽¹⁾		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			Acquisition Date Fair Value			Remaining Contingent Payments - Aggregate Limit
						(In thousands)
										($52,300	)

Actual Settlement	2018		$50.00	1Q19	Financing		($50,000	)

Remaining Potential Settlements	2019-2021	50.00		⁽²⁾	⁽²⁾	(50,000		)					($75,000	)


(1)	The price used to determine whether the specified threshold for each year has been met ~~for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration~~ is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information ~~Administration.~~ Administration (“U.S. EIA”).

(2)

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

Contingent Niobrara Consideration



	Year	Threshold ⁽¹⁾	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Divestiture Date Fair Value		Remaining Contingent Payments - Aggregate Limit
					(In thousands)
								$7,880

Actual Settlement	2018	$55.00	1Q19	Financing		$5,000				$10,000

Remaining Potential Settlements	2019	55.00	1Q20	⁽²⁾	5,000
	2020	60.00	1Q21	⁽²⁾	5,000


(1)	The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. EIA.


(2)	If the commodity price threshold is reached, $2.9 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

Contingent Marcellus Consideration



	Year	Threshold ⁽¹⁾	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Divestiture Date Fair Value		Remaining Contingent Payments - Aggregate Limit
					(In thousands)
								$2,660

Actual Settlement	2018	$3.13	1Q19	N/A		$—				$6,000

Remaining Potential Settlements	2019	3.18	1Q20	⁽²⁾	3,000
	2020	3.30	1Q21	⁽²⁾	3,000


(1)	The price used to determine whether the specified threshold for ~~the Marcellus Contingent Consideration~~each year has been met is the average monthly settlement price per MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc.


(2)	For the three months ended March 31, 2019, there was no settlement for the Contingent Marcellus Consideration. Therefore, if the commodity price threshold is reached, $2.7 million of the contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

Contingent Utica Consideration



	Year	Threshold ⁽¹⁾	Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Receipt - Annual		Divestiture Date Fair Value		Remaining Contingent Payments - Aggregate Limit
					(In thousands)
								$6,145

Actual Settlement	2018	$50.00	1Q19	Financing		$5,000				$10,000

Remaining Potential Settlements	2019	53.00	1Q20	⁽²⁾	5,000
	2020	56.00	1Q21	⁽²⁾	5,000


(1)	The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. EIA.


(2)	If the commodity price threshold is reached, $1.1 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

Derivative Assets and Liabilities

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

The derivative instrument asset and liability fair values recorded in the consolidated balance sheets as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018 are summarized below:


	September 30, 2018									March 31, 2019
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)									(In thousands)
Commodity derivative instruments		$19,408			($18,985	)		$423			$11,513			($8,208	)		$3,305
Contingent Niobrara Consideration	4,920			—			4,920			3,409			—			3,409
Contingent Marcellus Consideration										218			—			218
Contingent Utica Consideration	4,915			—			4,915			3,926			—			3,926
Derivative assets		$29,243			($18,985	)		$10,258			$19,066			($8,208	)		$10,858
Commodity derivative instruments	12,028			(12,028		)	—			4,271			(4,173		)	98
Contingent Niobrara Consideration	6,755			—			6,755			1,803			—			1,803
Contingent Marcellus Consideration	1,315			—			1,315			670			—			670
Contingent Utica Consideration	7,300			—			7,300			2,279			—			2,279
Other assets		$27,398			($12,028	)		$15,370
Other long-term assets											$9,023			($4,173	)		$4,850

Commodity derivative instruments		($123,611	)		$9,876			($113,735	)		($30,843	)		($1,113	)		($31,956	)
Deferred premium obligations	(9,109		)	9,109			—			(9,321		)	9,321			—
Contingent ExL Consideration	(49,160		)	—			(49,160		)	(44,038		)	—			(44,038		)
Derivative liabilities-current		($181,880	)		$18,985			($162,895	)		($84,202	)		$8,208			($75,994	)
Commodity derivative instruments	(45,532		)	6,314			(39,218		)	(14,884		)	1,702			(13,182		)
Deferred premium obligations	(5,714		)	5,714			—			(2,471		)	2,471			—
Contingent ExL Consideration	(62,885		)	—			(62,885		)	(15,545		)	—			(15,545		)
Derivative liabilities-non current		($114,131	)		$12,028			($102,103	)
Other long-term liabilities											($32,900	)		$4,173			($28,727	)


	December 31, 2017									December 31, 2018
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)									(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—			$50,406			($20,502	)		$29,904
Contingent Niobrara Consideration										5,000			—			5,000
Contingent Utica Consideration										5,000			—			5,000
Derivative assets		$4,869			($4,869	)		$—			$60,406			($20,502	)		$39,904
Commodity derivative instruments	9,505			(9,505		)	—			6,083			(4,236		)	1,847
Contingent Niobrara Consideration										2,035			—			2,035
Contingent Marcellus Consideration	2,205			—			2,205			1,369			—			1,369
Contingent Utica Consideration	7,985			—			7,985			2,501			—			2,501
Other assets		$19,695			($9,505	)		$10,190
Other long-term assets											$11,988			($4,236	)		$7,752

Commodity derivative instruments		($52,671	)		($4,450	)		($57,121	)		($15,345	)		$10,140			($5,205	)
Deferred premium obligations	(9,319		)	9,319			—			(10,362		)	10,362			—
Contingent ExL Consideration										(50,000		)	—			(50,000		)
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)		($75,707	)		$20,502			($55,205	)
Commodity derivative instruments	(24,609		)	(2,098		)	(26,707		)	(10,751		)	518			(10,233		)
Deferred premium obligations	(11,603		)	11,603			—			(3,718		)	3,718			—
Contingent ExL Consideration	(85,625		)	—			(85,625		)	(30,584		)	—			(30,584		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)
Other long-term liabilities											($45,053	)		$4,236			($40,817	)

See “Note ~~11.~~13. Fair Value Measurements” for additional information regarding the fair value of the Company’s derivative instruments.

(Gain) ~~Loss~~loss on ~~Derivatives, Net~~derivatives, net

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

derivative instruments are recognized as “(Gain) loss on derivatives, net” in the consolidated statements of income in the period in which the deferred premium obligations are incurred. The net (gain) loss on derivatives in the consolidated statements of income for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ are summarized below:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
	(In thousands)												(In thousands)
(Gain) Loss on Derivatives, Net
(Gain) loss on derivatives, net
Crude oil		$43,664			$8,409			$126,612			($39,754	)		$62,761			$29,511
NGL	5,086			—			9,885			—			(6		)	(1,765		)
Natural gas	(192		)	(2,183		)	(3,084		)	(12,902		)	(2,070		)	(3,045		)
Deferred premium obligations	—			10,151			—			17,652
Contingent ExL Consideration	9,990			8,000			26,420			8,000			28,999			5,830
Contingent Niobrara Consideration	(1,705		)	—			(3,795		)	—			(3,177		)	(385		)
Contingent Marcellus Consideration	215			—			890			—			481			470
Contingent Utica Consideration	(1,670		)	—			(4,230		)	—			(3,704		)	(1,020		)
(Gain) Loss on Derivatives, Net		$55,388			$24,377			$152,698			($27,004	)
Loss on derivatives, net														$83,284			$29,596

Cash ~~Received (Paid) for Derivative Settlements, Net~~

Cash flows are impacted to the extent that settlements of commodity derivative instruments, including deferred premium obligations, and contingent consideration arrangements result in cash received or paid during the period and are recognized as “Cash received (paid) for derivative settlements, ~~net” in~~net

For the ~~consolidated statements of cash flows. Cash received or~~three months ended March 31, 2019, the Company paid in$50.0 million from the first annual settlement of the Contingent ExL Consideration and received $10.0 million from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration ~~assets or liabilities, respectively,~~arrangement were exceeded. The cash paid and received for those contingent consideration settlements are classified as cash flows from financing activities ~~up to~~as each of the ~~divestiture~~settlements were less than their respective acquisition or ~~acquisition~~divestiture date fair ~~value with any excess classified as cash flows from operating activities.~~values. For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018, ~~and 2017,~~ there were no settlements of contingent consideration arrangements.

The ~~net cash received (paid)~~components of “Cash paid for derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” in the consolidated statements of cash flows for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ are summarized below:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Cash Flows from Operating Activities	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Cash Flows From Operating Activities													(In thousands)
Cash received (paid) for commodity derivative settlements, net
Crude oil		($21,261	)		$6,500			($54,594	)		$9,941			($320	)		($12,123	)
NGL	(2,641		)	—			(3,829		)	—			623			(432		)
Natural gas	245			522			785			(731		)	(300		)	52
Deferred premium obligations	(2,605		)	(566		)	(7,072		)	(1,496		)	(2,641		)	(1,862		)
Cash Received (Paid) for Derivative Settlements, Net		($26,262	)		$6,456			($64,710	)		$7,714
Cash paid for commodity derivative settlements, net														($2,638	)		($14,365	)

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

~~11.~~13. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s derivative instrument assets and liabilities measured at fair value on a recurring basis as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017:~~2018:



	~~September 30,~~March 31, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$3,403			$—
Contingent Niobrara Consideration	—		5,212			—
Contingent Marcellus Consideration	—		888			—
Contingent Utica Consideration	—		6,205			—

Liabilities
Commodity derivative instruments		$—		($45,138	)		$—
Contingent ExL Consideration	—		(59,583		)	—



	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$~~423~~31,751			$—
Contingent Niobrara Consideration	—		—7,035			~~11,675~~—
Contingent Marcellus Consideration	—		—1,369			~~1,315~~—
Contingent Utica Consideration	—		—7,501			~~12,215~~—

Liabilities
Commodity derivative instruments		$—		($~~152,953~~15,438	)		$—
Contingent ExL Consideration	—		—			(~~112,045~~80,584		)

~~December 31, 2017~~

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(In thousands)~~

~~Assets~~

~~Commodity derivative instruments~~

$—

~~Contingent Niobrara Consideration~~

—

~~Contingent Marcellus Consideration~~

—

~~2,205~~

~~Contingent Utica Consideration~~

—

~~7,985~~

~~Liabilities~~

~~Commodity derivative instruments~~

$—

~~($83,828~~

)

$—

~~Contingent ExL Consideration~~

—

~~(85,625~~

)

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

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

~~The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the nine months ended September 30, 2018 and 2017.~~

Contingent consideration arrangements. The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors, and risk adjusted discount rates, which include adjustments for the counterparties’ credit quality for contingent consideration assets and the Company’s credit quality for the contingent consideration ~~liabilities. As some of these assumptions~~liability. These inputs are ~~not~~ substantially

observable in active markets throughout the full term of the contingent consideration arrangements ~~the contingent consideration arrangements were~~or can be derived from observable data and are therefore designated as Level 32 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

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

Contingent Consideration Arrangements
Assets Liability
(In thousands)
December 31, 2017
$10,190

($85,625 )
Recognition of divestiture date fair value 7,880
—
Gain (loss) on changes in fair value, net⁽¹⁾
7,135
(26,420 )
Transfers into (out of) Level 3 —
—
September 30, 2018
$25,205

($112,045 )



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


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

See “Note ~~10.~~12. Derivative Instruments” for additional information regarding the contingent consideration arrangements.

The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the three months ended March 31, 2019.

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

The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

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

The fair value measurements of ~~assets acquired and liabilities assumed~~asset retirement obligations are measured as of the ~~acquisition~~ date ~~for~~a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the ~~ExL Acquisition.~~market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.

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

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the ~~carrying~~principal 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 quoted secondary market trading prices which are designated as Level 1 within the valuation hierarchy. See “Note 7. Long-Term Debt” for additional discussion.

September 30, 2018 December 31, 2017
Carrying Amount Fair Value Carrying Amount Fair Value
(In thousands)
7.50% Senior Notes due 2020
$129,144

$130,000

$446,087

$459,518
6.25% Senior Notes due 2023 642,781
664,625
641,792
674,375
8.25% Senior Notes due 2025 245,927
268,750
245,605
274,375
Other long-term debt due 2028 —
—
4,425
4,445

~~12.~~ ~~Condensed Consolidating Financial Information~~

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



	March 31, 2019				December 31, 2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)
6.25% Senior Notes due 2023		$650,000		$639,438		$650,000		$599,625
8.25% Senior Notes due 2025	250,000		258,750		250,000		244,375

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(In thousands)~~

~~(Unaudited)~~

September 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Assets
Total current assets
$3,114,698

$133,308

$—

($3,096,917 )
$151,089
Total property and equipment, net 6,570
2,709,162
3,028
(3,833 ) 2,714,927
Investment in subsidiaries (576,826 ) —
—
576,826
—
Other assets 29,611
15,371
—
—
44,982
Total Assets
$2,574,053

$2,857,841

$3,028

($2,523,924 )
$2,910,998

Liabilities and Shareholders’ Equity
Current liabilities
$305,096

$3,347,575

$3,028

($3,099,937 )
$555,762
Long-term liabilities 1,357,294
87,092
—
15,879
1,460,265
Preferred stock 173,629
—
—
—
173,629
Total shareholders’ equity 738,034
(576,826 ) —
560,134
721,342
Total Liabilities and Shareholders’ Equity
$2,574,053

$2,857,841

$3,028

($2,523,924 )
$2,910,998

December 31, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Assets
Total current assets
$3,441,633

$105,533

$—

($3,424,288 )
$122,878
Total property and equipment, net 5,953
2,630,707
3,028
(3,878 ) 2,635,810
Investment in subsidiaries (999,793 ) —
—
999,793
—
Other assets 9,270
10,346
—
—
19,616
Total Assets
$2,457,063

$2,746,586

$3,028

($2,428,373 )
$2,778,304

Liabilities and Shareholders’ Equity
Current liabilities
$165,701

$3,631,401

$3,028

($3,427,308 )
$372,822
Long-term liabilities 1,689,466
114,978
—
15,879
1,820,323
Preferred stock 214,262
—
—
—
214,262
Total shareholders’ equity 387,634
(999,793 ) —
983,056
370,897
Total Liabilities and Shareholders’ Equity
$2,457,063

$2,746,586

$3,028

($2,428,373 )
$2,778,304

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING STATEMENTS OF INCOME~~

~~(In thousands)~~

~~(Unaudited)~~

Three Months Ended September 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$38

$303,337

$—

$—

$303,375
Total costs and expenses 85,242
135,920
—
(13 ) 221,149
Income (loss) before income taxes (85,204 ) 167,417
—
13
82,226
Income tax expense —
(880 ) —
—
(880 )
Equity in income of subsidiaries 166,537
—
—
(166,537 ) —
Net income
$81,333

$166,537

$—

($166,524 )
$81,346
Dividends on preferred stock (4,457 ) —
—
—
(4,457 )
Accretion on preferred stock (771 ) —
—
—
(771 )
Loss on redemption of preferred stock —
—
—
—
—
Net income attributable to common shareholders
$76,105

$166,537

$—

($166,524 )
$76,118

Three Months Ended September 30, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$35

$181,244

$—

$—

$181,279
Total costs and expenses 54,061
119,366
—
29
173,456
Income (loss) before income taxes (54,026 ) 61,878
—
(29 ) 7,823
Income tax expense —
—
—
—
—
Equity in income of subsidiaries 61,878
—
—
(61,878 ) —
Net income
$7,852

$61,878

$—

($61,907 )
$7,823
Dividends on preferred stock (2,249 ) —
—
—
(2,249 )
Accretion on preferred stock —
—
—
—
—
Loss on redemption of preferred stock —
—
—
—
—
Net income attributable to common shareholders
$5,603

$61,878

$—

($61,907 )
$5,574

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING STATEMENTS OF INCOME~~

~~(In thousands)~~

~~(Unaudited)~~

Nine Months Ended September 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$77

$792,551

$—

$—

$792,628
Total costs and expenses 278,942
367,902
—
(45 ) 646,799
Income (loss) before income taxes (278,865 ) 424,649
—
45
145,829
Income tax expense —
(1,682 ) —
—
(1,682 )
Equity in income of subsidiaries 422,967
—
—
(422,967 ) —
Net income
$144,102

$422,967

$—

($422,922 )
$144,147
Dividends on preferred stock (13,794 ) —
—
—
(13,794 )
Accretion on preferred stock (2,264 ) —
—
—
(2,264 )
Loss on redemption of preferred stock (7,133 ) —
—
—
(7,133 )
Net income attributable to common shareholders
$120,911

$422,967

$—

($422,922 )
$120,956

Nine Months Ended September 30, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Total revenues
$291

$498,826

$—

$—

$499,117
Total costs and expenses 80,660
314,237
—
70
394,967
Income (loss) before income taxes (80,369 ) 184,589
—
(70 ) 104,150
Income tax expense —
—
—
—
—
Equity in income of subsidiaries 184,589
—
—
(184,589 ) —
Net income
$104,220

$184,589

$—

($184,659 )
$104,150
Dividends on preferred stock (2,249 ) —
—
—
(2,249 )
Accretion on preferred stock —
—
—
—
—
Loss on redemption of preferred stock —
—
—
—
—
Net income attributable to common shareholders
$101,971

$184,589

$—

($184,659 )
$101,901

~~CARRIZO OIL & GAS, INC.~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~(In thousands)~~

~~(Unaudited)~~

Nine Months Ended September 30, 2018

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Net cash provided by (used in) operating activities
($218,926 )
$684,218

$—

$—

$465,292
Net cash provided by (used in) investing activities 375,265
(284,076 ) —
(400,142 ) (308,953 )
Net cash used in financing activities (163,464 ) (400,142 ) —
400,142
(163,464 )
Net decrease in cash and cash equivalents (7,125 ) —
—
—
(7,125 )
Cash and cash equivalents, beginning of period 9,540
—
—
—
9,540
Cash and cash equivalents, end of period
$2,415

$—

$—

$—

$2,415

Nine Months Ended September 30, 2017

Parent
Company

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Net cash provided by (used in) operating activities
($95,529 )
$376,126

$—

$—

$280,597
Net cash used in investing activities (728,833 ) (1,102,155 ) —
726,029
(1,104,959 )
Net cash provided by financing activities 825,260
726,029
—
(726,029 ) 825,260
Net increase in cash and cash equivalents 898
—
—
—
898
Cash and cash equivalents, beginning of period 4,194
—
—
—
4,194
Cash and cash equivalents, end of period
$5,092

$—

$—

$—

$5,092

~~13.~~14. Supplemental Cash Flow Information

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

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

$59,389

Non-cash investing activities:
Increase in capital expenditure payables and accruals
$61,893

$98,829
Fair value of contingent consideration (assets) liabilities on date of (divestiture) acquisition (7,880 ) 52,300
Stock-based compensation expense capitalized to oil and gas properties 5,384
2,543
Asset retirement obligations capitalized to oil and gas properties 1,127
2,761



	Three Months Ended March 31,
	2019		2018
	(In thousands)
Operating activities:
Cash paid for interest, net of amounts capitalized		$16,451		$14,855

Investing activities:
Increase (decrease) in capital expenditure payables and accruals		$74,666		($9,677	)

Supplemental non-cash investing activities:
Fair value of contingent consideration assets on date of divestiture		$—		($7,880	)
Stock-based compensation expense capitalized to oil and gas properties	1,903		708
Asset retirement obligations capitalized to oil and gas properties	3,226		142

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

~~14.~~15. Subsequent Events

Commodity Derivative Instruments

In ~~October 2018,~~April 2019, the Company entered into the following commodity derivative instruments at weighted average contract volumes and prices:


Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	2019	Three-Way Collars	NYMEX WTI	6,000	—			$45.00		$55.00		$93.01	—	2Q19	Price Swaps	NYMEX WTI	3,352		$64.80	—		—		—		—

Crude oil	2019	Basis Swaps	LLS-WTI Cushing	1,000		$5.78	—		—		—		—	3Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—

Crude oil														4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—

Crude oil														2020	Three-Way Collars	NYMEX WTI	6,000	—			$46.25		$56.25		$67.39	—

~~Redemption of 7.50% Senior Notes Due 2020~~

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

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

~~Thirteenth Amendment to the Credit Agreement~~

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

Commodity

Period

Type of Contract

Index

Volumes

(MMBtu

per day)

Fixed Price

($ per

MMBtu)

Sub-Floor

Price

($ per

MMBtu)

Floor

Price

($ per MMBtu)

Ceiling Price

($ per

MMBtu)

Fixed Price

Differential

($ per

MMBtu)

Natural gas

2Q20

Basis Swaps

Waha-NYMEX Henry Hub

15,000

—

($1.25

)

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

The following discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements and related notes included in “Item 1. Consolidated Financial Statements (Unaudited)” in this Quarterly Report on Form 10-Q and the discussion under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited Consolidated Financial Statements included in our ~~2017~~2018 Annual Report. The following discussion and analysis contains statements, including, but not limited to, statements related to our plans, strategies, objectives, and expectations. Please see “Forward-Looking Statements” for further details about these statements.

General Overview

~~Third~~First Quarter ~~2018~~2019 Highlights

Total production for the three months ended ~~September 30, 2018~~March 31, 2019 was ~~64,627~~61,960 Boe/d, an increase of ~~17%~~21% from the three months ended ~~September 30, 2017,~~March 31, 2018, primarily due to production from new wells in the Eagle Ford and Delaware Basin, partially offset by ~~the divestitures in Utica and Marcellus in the fourth quarter of 2017 and Niobrara and Eagle Ford in the first quarter of 2018, as well as~~ normal production ~~declines.~~decline.

Operated drilling and completion activity for the three months ended ~~September 30, 2018~~March 31, 2019 along with our drilled but uncompleted and producing wells as of ~~September 30, 2018~~March 31, 2019 are summarized in the table below.


	Three Months Ended September 30, 2018				September 30, 2018				Three Months Ended March 31, 2019				March 31, 2019
	Drilled		Completed		Drilled But Uncompleted		Producing		Drilled		Completed		Drilled But Uncompleted		Producing
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	32	31.3	25	24.3	20	19.4	516	463.1	27	24.1	32	31.8	41	38.0	553	495.5
Delaware Basin	7	5.3	10	8.7	7	5.6	57	47.2	8	7.5	11	9.0	9	8.2	84	72.9
Total	39	36.6	35	33.0	27	25.0	573	510.3	35	31.6	43	40.8	50	46.2	637	568.4

Drilling and completion expenditures for the ~~third~~first quarter of ~~2018~~2019 were ~~$241.1~~$214.7 million, of which approximately ~~62%~~63% were in the Eagle Ford with the balance in the Delaware Basin. As ~~a result~~ of the relative outlook for crude oil prices in the Eagle Ford and Delaware Basin, we elected to shift capital expenditures to the Eagle Ford in order to take advantage of the superior returns in the current environment. As of September 30, 2018,March 31, 2019, we were operating ~~six~~three rigs, with ~~four~~one located in the Eagle Ford and two located in the Delaware ~~Basin, and two completion crews, both of which were in the Eagle Ford.~~Basin. For the remainder of ~~2018,~~2019, we currently expect to ~~continue operating~~operate an average of ~~six~~three to four rigs between the Eagle Ford and Delaware ~~Basin, however, completion activity is expected to decline in the fourth quarter of 2018 as we have planned for a frac holiday.~~Basin. Our current ~~2018~~2019 drilling, completion, and infrastructure (“DC&I”) capital expenditure plan remains unchanged at ~~$800.0~~$525.0 million to ~~$825.0~~$575.0 million. See “—Liquidity and Capital Resources—~~2018 Drilling, Completion, and Infrastructure~~2019 DC&I Capital Expenditure Plan and Funding Strategy” for additional details.

In ~~July 2018,~~January 2019, we ~~closed on the divestiture of certain non-operated assets in the Delaware Basin for aggregate net proceeds of $30.9 million.~~

~~In August 2018, we entered into a purchase and sale agreement with Devon to acquire oil and gas properties in the Delaware Basin in Reeves and Ward counties, Texas for an agreed upon price of $215.0~~paid $50.0 million ~~subject to customary purchase price adjustments. We paid $21.5 million~~ as a deposit upon signing the purchase and sale agreement and $183.4 million upon closing in October for an aggregate purchase price of $204.9 million. The final purchase price remains subject to post-closing adjustments. Certain of the acreage included in the acquisition is subject to a third party’s right to purchase a 20% interest in such acreage.

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

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

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

~~Recent Developments~~

In October 2018, we delivered a notice of conditional redemption to the trustee for our 7.50% Senior Notes to call for redemption on November 19, 2018, the remaining $130.0 million aggregate principal amount of outstanding 7.50% Senior Notes at a redemption price of 100% of par, plus accrued and unpaid interest. Our redemption obligation was conditioned on and subject to there being made available to us under the revolving credit facility a commitment amount of at least $1.1 billion as of November 19, 2018, which was satisfied on October 29, 2018 in connection with the amendment to the credit agreement discussed below, therefore, our redemption obligation is no longer conditional. As a result of the redemption, we expect to record a loss on extinguishment of debt of approximately $0.8 million, which is solely attributable to the write-off of unamortized premium and debt issuance costs. Additionally, upon redemptionfirst annual settlement of the ~~7.50% Senior Notes,~~Contingent ExL Consideration and received $10.0 million from the ~~May 4, 2022 maturity date~~first annual settlements of the ~~credit agreement will no longer be subject to a springing maturity date of June 15, 2020.~~Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. See “Note 12. Derivative Instruments” for further discussion.

In ~~October 2018,~~March 2019, we entered into the ~~thirteenth~~fourteenth amendment to our credit agreement governing the revolving credit facility to, among other things (i) establish the borrowing base at ~~$1.3~~$1.35 billion, with an elected commitment amount of ~~$1.1~~$1.25 billion, until the next redetermination thereof, (ii) reduce the applicable margins for Eurodollar loans from 1.50%-2.50% to 1.25%-2.25% and base rate loans from 0.50%-1.50% to 0.25%-1.25%, each depending on the level of facility usage and each subject to an increase of 0.25% for any period during which the ratio of Total Debt to EBITDA exceeds 3.00 to 1.00, (iii) amend the definition of ~~Capital Leases,~~Current Ratio, and ~~(iv)~~(iii) amend certain other definitions and provisions.

We recorded net income attributable to common shareholders for the three months ended March 31, 2019 of $146.2 million, or $1.58 per diluted share, as compared to net income attributable to common shareholders for the three months ended March 31, 2018 of $14.7 million, or $0.18 per diluted share. The increase in net income attributable to common shareholders was driven primarily by an income tax benefit of approximately $179.4 million as a result of a release of a substantial portion of our deferred tax asset valuation allowance during the first quarter of 2019, partially offset by a $53.7 million increase in our loss on derivatives, net to $83.3 million for the first quarter of 2019 as compared to $29.6 million for the first quarter of 2018. See “—Results of Operations” below for further details.

Results of Operations

~~Three Months Ended September 30,2018, Compared to the~~Comparison of Results Between The Three Months Ended ~~September 30,~~March 31,2019 ~~2017~~and 2018

Production volumes

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

Three Months Ended September 30, 2018 Period
Compared to 2017 Period
2018 2017 Increase (Decrease) % Increase (Decrease)
Total production volumes -
    Crude oil (MBbls) 3,755
3,211
544
17 %
    NGLs (MBbls) 1,055
623
432
69 %
    Natural gas (MMcf) 6,815
7,476
(661 ) (9 %)
Total barrels of oil equivalent (MBoe) 5,946

5,080
866
17 %

Daily production volumes by product -
    Crude oil (Bbls/d) 40,813
34,903
5,910
17 %
    NGLs (Bbls/d) 11,469
6,777
4,692
69 %
    Natural gas (Mcf/d) 74,072
81,265
(7,193 ) (9 %)
Total barrels of oil equivalent (Boe/d) 64,627
55,224
9,403
17 %

Daily production volumes by region (Boe/d) -
    Eagle Ford 39,024
39,002
22
— %
    Delaware Basin 25,577
6,994
18,583
266 %
    Other 26
9,228
(9,202 ) (100 %)
Total barrels of oil equivalent (Boe/d) 64,627
55,224
9,403
17 %

Average realized prices -
    Crude oil ($ per Bbl)
$67.78

$47.37

$20.41
43 %
    NGLs ($ per Bbl) 32.04
20.01
12.03
60 %
    Natural gas ($ per Mcf) 2.21
2.24
(0.03 ) (1 %)
Total average realized price ($ per Boe)
$51.02

$35.68

$15.34
43 %

Revenues (In thousands) -
    Crude oil
$254,525

$152,101

$102,424
67 %
    NGLs 33,798
12,467
21,331
171 %
    Natural gas 15,052
16,711
(1,659 ) (10 %)
Total revenues
$303,375

$181,279

$122,096
67 %



	Three Months Ended March 31,		Amount Change Between Periods		Percent Change Between Periods
	2019	2018	Amount Change Between Periods		Percent Change Between Periods
Total production volumes
Crude oil (MBbls)	3,665	3,072	593		19	%
NGLs (MBbls)	891	739	152		21	%
Natural gas (MMcf)	6,118	4,810	1,308		27	%
Total barrels of oil equivalent (MBoe)	5,576	4,613	963		21	%

Daily production volumes by product
Crude oil (Bbls/d)	40,727	34,136	6,591		19	%
NGLs (Bbls/d)	9,903	8,213	1,690		21	%
Natural gas (Mcf/d)	67,977	53,446	14,531		27	%
Total barrels of oil equivalent (Boe/d)	61,960	51,257	10,703		21	%

Daily production volumes by region (Boe/d)
Eagle Ford	39,533	35,623	3,910		11	%
Delaware Basin	22,427	15,235	7,192		47	%
Other	—	399	(399	)	(100	%)
Total barrels of oil equivalent (Boe/d)	61,960	51,257	10,703		21	%

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

Average realized prices and ~~Marcellus in the fourth quarter of 2017~~revenues

The following table summarizes average realized prices and ~~Niobrara and Eagle Ford in the first quarter of 2018. Revenues~~revenues for the ~~three months ended September 30, 2018 increased 67% to $303.4 million compared to $181.3 million for the same period~~periods indicated:



	Three Months Ended March 31,				Amount Change Between Periods			Percent Change Between Periods
	2019		2018		Amount Change Between Periods			Percent Change Between Periods
Average realized prices
Crude oil ($ per Bbl)		$55.32		$63.45		($8.13	)	(13	%)
NGLs ($ per Bbl)	18.90		22.87		(3.97		)	(17	%)
Natural gas ($ per Mcf)	2.20		2.80		(0.60		)	(21	%)
Total average realized price ($ per Boe)		$41.79		$48.84		($7.05	)	(14	%)

Revenues (In thousands)
Crude oil		$202,744		$194,919		$7,825		4	%
NGLs	16,837		16,902		(65		)	—	%
Natural gas	13,459		13,459		—			—	%
Total revenues		$233,040		$225,280		$7,760		3	%

The increase in ~~2017~~revenues is primarily due to higher crude oil ~~prices~~ and ~~higher~~NGL production, partially offset by lower crude oil ~~production.~~and NGL prices.

Lease operating ~~expenses~~expense

The following table summarizes lease operating expense for the ~~three months ended September 30, 2018 increased to $41.0 million ($6.90 per Boe) from $34.9 million ($6.86 per Boe) for the same period in 2017.~~ periods indicated:



	Three Months Ended March 31,
	2019				2018
	(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe
Lease operating expense		$42,031		$7.54		$39,273		$8.51

The increase in lease operating expenses is primarily due to costs associated with increased production. The ~~increase~~decrease in lease operating expense per Boe is primarily due to ~~processing fees for certain~~the divestiture in the Eagle Ford in the first quarter of ~~our natural gas and NGL processing contracts that, effective January 1,~~ 2018, ~~are presented in lease~~which carried higher per Boe operating expenses as ~~a result of the adoption of ASC in 606. This more than offset a net decrease in lease operating expense per Boe related~~compared to ~~the change in the~~our remaining Eagle Ford properties, as well as an increased proportion of production from wells drilled on properties acquired in the ExL Acquisition, which have lower operating costs per Boe than our other Delaware Basin and Eagle Ford properties, and the increased proportion of total production from crude oil properties, as a result of the divestiture in Marcellus in the fourth quarter of 2017, which have a higher per operating cost per Boe than natural gas properties.

Production and ad valorem taxes ~~increased to $14.5 million (4.8% of revenues)~~

The following table summarizes production and ad valorem taxes for the ~~three months ended September 30, 2018 from $7.7 million (4.3% of revenues) for the same period in 2017 primarily as a result of the increase in crude oil and NGL revenues.~~ periods indicated:



	Three Months Ended March 31,
	2019				2018
	(In thousands, except % of revenues amounts)
	Amount		% of Revenues		Amount		% of Revenues
Production and ad valorem taxes		$14,894	6.4	%		$12,548	5.6	%

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

~~Ad valorem taxes~~ increased ~~to $2.6 million (0.9% of revenues) for the three months ended September 30, 2018 from $1.7 million (1.0% of revenues) for the same period in 2017. The increase in~~ ad valorem taxes ~~is due to~~as a result of new wells drilled in the Eagle Ford and Delaware Basin and higher property tax valuations as a result of the increase in crude oil prices ~~partially offset by a reduction in ad valorem taxes resulting from~~during 2018.

Depreciation, depletion and amortization

The following table sets forth the ~~divestitures discussed above. The decrease in ad valorem taxes as a percentage~~components of ~~revenues is primarily due to~~our depreciation, depletion and amortization (“DD&A”) expense for the ~~timing of when wells are included in the ad valorem tax assessment as wells drilled and producing during 2018 would not be included in ad valorem tax assessment until 2019.~~periods indicated:



	Three Months Ended March 31,
	2019				2018
	(In thousands, except per Boe amounts)
	Amount		Per Boe		Amount		Per Boe
DD&A of proved oil and gas properties		$74,000		$13.27		$63,331		$13.73
Depreciation of other property and equipment	699		0.13		580		0.13
Amortization of other assets	221		0.04		234		0.05
Accretion of asset retirement obligations	402		0.07		322		0.07
DD&A		$75,322		$13.51		$64,467		$13.98

DD&A expense for the ~~third quarter of 2018~~three months ended March 31, 2019 increased ~~$12.5~~$10.9 million compared to ~~$80.1 million ($13.47 per Boe) from~~ the ~~DD&A expense for the third quarter of 2017 of $67.6 million ($13.30 per Boe).~~three months ended March 31, 2018. The increase in DD&A expense is attributable to increased production, ~~and an increase~~partially offset by the decrease in the DD&A rate per Boe. The ~~increase~~decrease in the DD&A rate per Boe is due primarily to ~~increases~~an increased proportion of proved oil and gas reserves in the Delaware Basin, as well as decreased future development costs in Eagle Ford and the Delaware Basin that occurred subsequent to the ~~third~~first quarter of ~~2017 as well as an increase~~2018.

General and administrative expense, net

The following table summarizes general and administrative expense, net for the periods indicated:



	Three Months Ended March 31,
	2019		2018
	(In thousands)
General and administrative expense, net		$24,732		$27,292

The decrease in ~~proved oil~~general and gas properties as a result of our ongoing capital expenditure program, partially offset by the reduction in proved oil and gas properties as a result of the divestitures in Utica and Marcellus in the fourth quarter of 2017 and Niobrara and Eagle Fordadministrative expense, net was primarily due to lower annual bonuses awarded in the first quarter of 2019 as compared to the first quarter of 2018, ~~and~~partially offset by an increase in ~~proved oil and gas reserves. The components of our DD&A expense were as follows:~~

Three Months Ended September 30,
2018 2017
(In thousands)
DD&A of proved oil and gas properties
$79,051

$66,221
Depreciation of other property and equipment 607
584
Amortization of other assets 102
294
Accretion of asset retirement obligations 348
465
Total DD&A
$80,108

$67,564

General and administrative expense, net decreased to $12.8 million for the three months ended September 30, 2018 from $16.0 million for the corresponding period in 2017. The decrease was primarily due to stock-based compensation expense, net as a result of ~~a larger decrease~~an increase in the fair value of ~~stock appreciation rights~~Cash SARs for the three months ended ~~September 30, 2018~~March 31, 2019 as compared to a decrease in fair value for the same period in ~~2017.~~2018.

~~We recorded a~~(Gain) loss on derivatives, net ~~of $55.4 million and $24.4 million for~~

The following table sets forth the ~~three months ended September 30, 2018 and 2017, respectively. The~~ components of our loss on derivatives, net ~~were as follows:~~for the periods indicated:

Three Months Ended September 30,
2018 2017
(In thousands)
Crude oil derivative positions:
Loss due to upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period
$34,282

$7,567
Loss due to new derivative positions executed during the period 9,382
842
Loss due to deferred premium obligations incurred —
10,151
NGL derivative positions:
Loss due to upward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period 5,086
—
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period (192 ) (2,183 )
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period 6,830
8,000
Loss on derivatives, net
$55,388

$24,377



	Three Months Ended March 31,
	2019			2018
	(In thousands)
Crude oil derivative instruments		$62,761			$29,511
NGL derivative instruments	(6		)	(1,765		)
Natural gas derivative instruments	(2,070		)	(3,045		)
Contingent consideration arrangements	22,599			4,895
Loss on derivatives, net		$83,284			$29,596

~~Interest expense,~~The loss on derivatives, net for the three months ended ~~September 30,~~March 31, 2019 was primarily due to the upward shift in the futures curve of forecasted crude oil prices from January 1, 2019 to March 31, 2019 on crude oil derivative instruments outstanding at the beginning of 2019 and on our Contingent ExL Consideration.

The loss on derivatives, net for the three months ended March 31, 2018 was ~~$15.4 million~~primarily due to the upward shift in the futures curve of forecasted crude oil prices from January 1, 2018 to March 31, 2018 on crude oil derivative instruments outstanding at the beginning of 2018 and on our Contingent ExL Consideration.

Interest expense, net

The following table sets forth the components of our interest expense, net for the periods indicated:



	Three Months Ended March 31,
	2019			2018
	(In thousands)
Interest expense on Senior Notes		$15,313			$21,486
Interest expense on revolving credit facility	9,054			3,158
Amortization of premiums and debt issuance costs	932			1,104
Other interest expense	145			137
Interest capitalized	(8,993		)	(10,368		)
Interest expense, net		$16,451			$15,517

The increase in interest expense, net was primarily due to increased borrowings and associated interest expense on our revolving credit facility for the three months ended March 31, 2019 as compared to ~~$20.7 million for~~ the ~~same period~~three months ended March 31, 2018 as well as the decrease in ~~2017.~~capitalized interest as a result of a lower weighted average interest rate driven by the higher proportion of borrowings on our revolving credit facility, which carries a lower interest rate than the Senior Notes. The ~~decrease~~increase was ~~primarily due to~~partially offset by reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the first and fourth ~~quarter~~quarters of ~~2017 and~~2018.

Loss on extinguishment of debt

As a result of our redemptions of $320.0 million of the outstanding aggregate principal amount of our 7.50% Senior Notes in the first quarter of 2018, ~~The decrease was partially offset by increased borrowings~~we recorded a loss on extinguishment of debt of $8.7 million, which included redemption premiums of $6.0 million paid to redeem the notes and ~~associated interest expense on our revolving credit facility for the three months ended September 30, 2018 as compared~~non-cash charges of $2.7 million attributable to the ~~three months ended September 30, 2017. The components~~write-off of ~~our interest expense, net were as follows:~~associated unamortized premiums and debt issuance costs.

Income taxes and deferred tax assets valuation allowance

Three Months Ended September 30,
2018 2017
(In thousands)
Interest expense on Senior Notes
$17,750

$25,750
Interest expense on revolving credit facility 5,092
1,969
Amortization of premiums and debt issuance costs 956
1,116
Other interest expense 124
293
Interest capitalized (8,516 ) (8,455 )
Interest expense, net
$15,406

$20,673

~~The effective~~For the first quarter of 2019, we recognized an income tax ~~rates for the third quarter~~benefit of ~~2018 and 2017 were 1.1% and 0.0%, respectively, which were nominal~~$179.4 million as a result of ~~maintaining~~determining that it was more likely than not that our deferred tax assets would be realized after considering all available evidence (both positive and negative). A significant item of objective positive evidence considered was the cumulative pre-tax income incurred over the three-year period ended March 31, 2019. As a ~~full~~result, we released $179.1 million of the valuation allowance against our ~~net~~ deferred tax ~~assets. The increase~~assets which resulted in an income tax benefit.

For the ~~effective rate between the periods is due to $0.9~~first quarter of 2018, we recognized income tax expense of $0.3 million ~~of Texas franchise tax recognized for the three months ended September 30, 2018 due to an increase in the apportionment of income to the state of Texas~~ as a result of ~~our divestitures in the fourth quarter of 2017 and first quarter of 2018.~~

~~Throughout 2017 and the first nine months of 2018, we maintained~~maintaining a full valuation allowance against our deferred tax assets based on our conclusion ~~considering all available evidence (both positive and negative),~~ that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended ~~September 30,~~March 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the fourth quarter of 2015 and the first three quarters of 2016, which ~~limits~~limited our ability to consider subjective positive evidence, such as its projections of future taxable income.

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

For the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ we declared, and paid in cash, dividends of ~~$4.5~~$4.4 million and ~~$2.2~~$4.9 million, respectively, on our Preferred Stock.

~~Results of Operations~~

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

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

Nine Months Ended September 30, 2018 Period
Compared to 2017 Period
2018 2017 Increase (Decrease) % Increase (Decrease)
Total production volumes -
    Crude oil (MBbls) 10,272
8,867
1,405
16 %
    NGLs (MBbls) 2,648
1,482
1,166
79 %
    Natural gas (MMcf) 16,996
21,279
(4,283 ) (20 %)
Total barrels of oil equivalent (MBoe) 15,753
13,896
1,857
13 %

Daily production volumes by product -
    Crude oil (Bbls/d) 37,628
32,481
5,147
16 %
    NGLs (Bbls/d) 9,699
5,430
4,269
79 %
    Natural gas (Mcf/d) 62,258
77,946
(15,688 ) (20 %)
Total barrels of oil equivalent (Boe/d) 57,703
50,902
6,801
13 %

Daily production volumes by region (Boe/d) -
    Eagle Ford 37,241
36,569
672
2 %
    Delaware Basin 20,236
3,871
16,365
423 %
    Other 226
10,462
(10,236 ) (98 %)
Total barrels of oil equivalent (Boe/d) 57,703
50,902
6,801
13 %

Average realized prices -
    Crude oil ($ per Bbl)
$66.13

$47.70

$18.43
39 %
    NGLs ($ per Bbl) 27.18
18.68
8.50
46 %
    Natural gas ($ per Mcf) 2.44
2.28
0.16
7 %
Total average realized price ($ per Boe)
$50.32

$35.92

$14.40
40 %

Revenues (In thousands) -
    Crude oil
$679,242

$422,999

$256,243
61 %
    NGLs 71,969
27,678
44,291
160 %
    Natural gas 41,417
48,440
(7,023 ) (14 %)
Total revenues
$792,628

$499,117

$293,511
59 %

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

Lease operating expenses for the nine months ended September 30, 2018 increased to $115.4 million ($7.33 per Boe) from $100.8 million ($7.25 per Boe) for the same period in 2017. The increase in lease operating expenses is primarily due to costs associated with increased production. The increase in lease operating expense per Boe is primarily due to processing fees for certain of our natural gas and NGL processing contracts that, effective January 1, 2018, are presented in lease operating expenses as a result of the adoption of ASC in 606. Additionally, there was a net increase in lease operating expense per Boe related to the increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties, as a result of the divestiture in Marcellus in the fourth quarter of 2017 and the increased proportion of production from properties acquired in the ExL Acquisition, which have lower operating costs per Boe than our other Delaware Basin and Eagle Ford properties.

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

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

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

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

Nine Months Ended September 30,
2018 2017
(In thousands)
DD&A of proved oil and gas properties
$213,727

$176,876
Depreciation of other property and equipment 1,801
1,842
Amortization of other assets 476
966
Accretion of asset retirement obligations 1,001
1,334
Total DD&A
$217,005

$181,018

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

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

Nine Months Ended September 30,
2018 2017
(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
$113,282

($28,334 )
(Gain) loss due to new derivative positions executed during the period 13,330
(11,420 )
Loss due to deferred premium obligations incurred —
17,652
NGL derivative positions:
Loss due to upward shift in the futures curve of forecasted NGL prices during the period on derivative positions outstanding at the beginning of the period 9,885
—
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period (3,152 ) (12,902 )
Loss due to new derivative positions executed during the period 68
—
Contingent consideration arrangements:
Net loss primarily due to upward shift in the futures curve of forecasted crude oil prices during the period 19,285
8,000
(Gain) loss on derivatives, net
$152,698

($27,004 )

Interest expense, net for the nine months ended September 30, 2018 was $46.5 million as compared to $62.4 million for the same period in 2017. The decrease was due primarily to reduced interest expense as a result of the redemptions of the 7.50% Senior Notes in the fourth quarter of 2017 and first quarter of 2018 as well as an increase in capitalized interest as a result of higher

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

Nine Months Ended September 30,
2018 2017
(In thousands)
Interest expense on Senior Notes
$57,003

$68,660
Interest expense on revolving credit facility 13,741
5,656
Amortization of debt issuance costs, premiums, and discounts 2,996
3,381
Other interest expense 394
876
Capitalized interest (27,612 ) (16,223 )
Interest expense, net
$46,522

$62,350

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

The effective income tax rate for the nine months ended September 30, 2018 and 2017 was 1.2% and 0.0%, respectively, which were nominal as a result of maintaining a full valuation allowance against our net deferred tax assets. The increase in the effective rate between the periods is due to $1.7 million of Texas franchise tax recognized for the nine months ended September 30, 2018 due to an increase in the apportionment of income to the state of Texas as a result of our divestitures in the fourth quarter of 2017 and first quarter of 2018.

Throughout 2017 and the first nine months of 2018, we maintained a full valuation allowance against our deferred tax assets based on our conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended September 30, 2018, primarily due to impairments of proved oil and gas properties recognized in the fourth quarter of 2015 and the first three quarters of 2016, which limits our ability to consider subjective positive evidence, such as its projections of future taxable income.

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

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

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

Liquidity and Capital Resources

~~2018 Drilling, Completion, and Infrastructure~~2019 DC&I Capital Expenditure Plan and Funding Strategy. Our ~~2018 drilling, completion, and infrastructure~~2019 DC&I capital expenditure plan remains unchanged at ~~$800.0~~$525.0 million to ~~$825.0~~$575.0 million. We currently intend to finance the remainder of our ~~2018 drilling, completion, and infrastructure~~2019 DC&I capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather

delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. The following is a summary of our capital expenditures for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019:

Three Months Ended Nine Months Ended
March 31, 2018 June 30, 2018 September 30, 2018 September 30, 2018
(In thousands)
Drilling, completion, and infrastructure
Eagle Ford
$135,677

$101,249

$149,386

$386,312
Delaware Basin 73,892
116,743
91,761
282,396
All other regions 284
—
—
284
Total drilling, completion, and
infrastructure
209,853
217,992
241,147
668,992
Leasehold and seismic 5,520
6,129
6,668
18,317
Total capital expenditures ⁽¹⁾

$215,373

$224,121

$247,815

$687,309



	Three Months Ended
	March 31, 2019
	(In thousands)
DC&I
Eagle Ford		$134,275
Delaware Basin	80,390
Other	52
Total DC&I	214,717
Leasehold and seismic	9,107
Total capital expenditures ⁽¹⁾		$223,824


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

Sources and Uses of Cash. Our primary use of cash is related to our ~~drilling, completion and infrastructure~~DC&I capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, we funded our capital expenditures primarily with cash provided by operations and borrowings under our revolving credit facility. Potential sources of future liquidity include the following:

Cash provided by operations. Cash flows from operations are highly dependent on crude oil prices. As such, we hedge a portion of our forecasted production to reduce our exposure to commodity price volatility in order to achieve a more predictable level of cash flows.

Borrowings under revolving credit facility. As of ~~November 2, 2018,~~April 30, 2019, our revolving credit facility had a borrowing base of ~~$1.3~~$1.35 billion, with an elected commitment amount of ~~$1.1~~$1.25 billion, with ~~$618.0~~$901.9 million of borrowings outstanding. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility. ~~See “Note 14. Subsequent Events” for details of the recent thirteenth amendment.~~

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

Divestitures. We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details.

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

Overview of Cash Flow Activities. Net cash provided by operating activities was ~~$465.3~~$125.1 million and ~~$280.6~~$138.7 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. The ~~increase~~decrease was driven primarily by an increase in working capital requirements and operating expenses as well as a decrease in revenues as a result of lower crude oil and NGL prices, partially offset by an increase in revenues as a result of higher crude oil ~~prices~~ and ~~higher crude oil~~NGL production ~~partially offset by an increase~~and a decrease in the net cash paid for derivative ~~settlements and an increase in operating expenses and cash general and administrative expense.~~settlements.

Net cash used in investing activities ~~decreased to $309.0~~was $160.6 million for the ~~nine~~three months ended ~~September 30, 2018, from $1,105.0~~March 31, 2019 as compared to net cash provided by investing activities was $107.6 million for the corresponding period in ~~2017. This~~2018. The change was primarily due ~~primarily~~ to the proceeds we received in the first quarter of 2018 related to the divestitures in Eagle Ford and Niobrara, partially offset by a decrease in cash ~~payments~~paid for ~~acquisitions of oil and gas properties, as well as~~capital expenditures.

Net cash ~~received from~~provided by financing activities was $35.4 million for the divestitures in Niobrara and Eagle Ford in early 2018, partially offset by an increase in capital expenditures as a result of our ongoing drilling, completion, and infrastructure activity in Eagle Ford and the Delaware Basin.

~~Net~~three months ended March 31, 2019 compared to net cash used in financing activities ~~was $163.5 million~~ for the ~~nine~~three months ended ~~September 30,~~March 31, 2018 ~~compared to net cash provided by financing activities for the nine months ended September 30, 2017~~ of ~~$825.3~~$251.0 million. The change was primarily due to payments for the redemptions of our 7.50% Senior Notes and Preferred Stock during the first quarter of 2018 and decreased borrowings, net of repayments under our revolving credit facility ~~decreased~~during the first quarter of 2019, partially offset by net cash ~~provided by the issuance~~paid for settlements of ~~senior notes and preferred stock, and increased cash dividends paid on the Preferred Stock.~~

contingent consideration arrangements in January 2019.

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

Revolving credit facility. The borrowing base under our revolving credit facility is affected by assumptions of the administrative agent with respect to, among other things, crude oil and, to a lesser extent, natural gas prices. Our borrowing base may decrease if our administrative agent reduces the crude oil and natural gas prices from those used to determine our existing borrowing base. See “Note 7. Long-Term Debt” and “—Sources and Uses of Cash—Borrowings under revolving credit facility” ~~and “—Financing Arrangements—Senior Secured Revolving Credit Facility”~~ for further details of our revolving credit facility.

Contingent consideration arrangements. As part of the ExL Acquisition, as well as in each of the divestitures of our assets in Niobrara, Marcellus, and Utica, we agreed to contingent consideration arrangements, where we will receive or be required to pay certain amounts if commodity prices are greater than specified thresholds. See “Note ~~10.~~12. Derivative Instruments” for further details of each of these contingent consideration arrangements and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for details of the sensitivities to commodity price for each contingent consideration arrangement.

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

As of ~~November 2, 2018,~~May 3, 2019, we had the following outstanding commodity derivative instruments at weighted average contract volumes and prices:


Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)			Period	Type of Contract	Index	Volumes (Bbls per day)	Fixed Price ($ per Bbl)		Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	4Q18	Price Swaps	NYMEX WTI	6,000		$49.55	—		—		—		—			2Q19	Price Swaps	NYMEX WTI	3,352		$64.80	—		—		—		—
Crude oil	4Q18	Three-Way Collars	NYMEX WTI	24,000	—			$39.38		$49.06		$60.14	—			2Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	4Q18	Basis Swaps	LLS-WTI Cushing	18,000	—		—		—		—			$5.11		2Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	4Q18	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			($0.10	)	2Q19	Basis Swaps	WTI Midland-WTI Cushing	7,609	—		—		—		—			($4.38	)
Crude oil	4Q18	Sold Call Options	NYMEX WTI	3,388	—		—		—			$71.33	—			2Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	2019	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$73.40	—			3Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil	2019	Basis Swaps	LLS-WTI Cushing	4,000	—		—		—		—			$4.87		3Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	2019	Basis Swaps	WTI Midland-WTI Cushing	7,389	—		—		—		—			($4.82	)	3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—		—			$5.16
Crude oil	2019	Sold Call Options	NYMEX WTI	3,875	—		—		—			$73.66	—			3Q19	Basis Swaps	WTI Midland-WTI Cushing	9,100	—		—		—		—			($4.44	)
Crude oil																3Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil																4Q19	Price Swaps	NYMEX WTI	5,000		$64.80	—		—		—		—
Crude oil																4Q19	Three-Way Collars	NYMEX WTI	27,000	—			$41.67		$50.96		$74.23	—
Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	13,000	—		—		—		—			($1.27	)	4Q19	Basis Swaps	WTI Midland-WTI Cushing	9,200	—		—		—		—			($4.64	)
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—			4Q19	Sold Call Options	NYMEX WTI	3,875	—		—		—			$81.07	—

Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—		—			$0.03		2020	Price Swaps	NYMEX WTI	3,000		$55.06	—		—		—		—
Crude oil																2020	Three-Way Collars	NYMEX WTI	12,000	—			$45.63		$55.63		$66.04	—
Crude oil																2020	Basis Swaps	WTI Midland-WTI Cushing	10,658	—		—		—		—			($1.68	)
Crude oil																2020	Sold Call Options	NYMEX WTI	4,575	—		—		—			$75.98	—

Crude oil																2021	Basis Swaps	WTI Midland-WTI Cushing	8,000	—		—		—		—			$0.18



Commodity	Period	Type of Contract	Index	Volumes (MMBtu per day)	Fixed Price ($ per MMBtu)	Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)		Fixed Price Differential ($ per MMBtu)
Natural gas	2Q19	Basis Swaps	Waha-NYMEX Henry Hub	14,000	—	—	—	—			($2.12	)
Natural gas	2Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—

Natural gas	3Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.60	)
Natural gas	3Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—

Natural gas	4Q19	Basis Swaps	Waha-NYMEX Henry Hub	15,000	—	—	—	—			($1.05	)
Natural gas	4Q19	Sold Call Options	NYMEX Henry Hub	33,000	—	—	—		$3.25	—

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

Commodity Period Type of Contract Index
Volumes
(MMBtu
per day)

Fixed
Price
($ per
MMBtu)

Sub-Floor Price
($ per
MMBtu)

Floor Price
($ per
MMBtu)

Ceiling Price
($ per
MMBtu)

Fixed
Price
Differential
($ per
MMBtu)
Natural gas 4Q18 Price Swaps NYMEX Henry Hub 25,000

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

$3.25
—

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

$3.25
—

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

$3.50
—

If cash flows from operations and borrowings under our revolving credit facility and the other sources of cash described under “—Sources and Uses of Cash” are insufficient to fund our remaining 2019 DC&I capital expenditure plan, 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 2019 DC&I capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Based on existing market conditions and our expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from divestitures, securities offerings or borrowings to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings. ~~See “Note 14. Subsequent Events” for details of the notice of conditional redemption for the remaining $130.0 million aggregate principal amount of outstanding 7.50% Senior Notes.~~

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of ~~September 30, 2018~~March 31, 2019 (in thousands):

October - December 2018 2019 2020 2021 2022 2023 and Thereafter Total
Long-term debt ⁽¹⁾

$—

$—

$130,000

$—

$309,837

$900,000

$1,339,837
Cash interest on senior notes ⁽²⁾
20,313
71,000
71,000
61,250
61,250
82,188
367,001
Cash interest and commitment fees on revolving credit facility ⁽³⁾
3,637
14,233
14,233
14,233
4,903
—
51,239
Capital leases 450
1,800
1,050
—
—
—
3,300
Operating leases 1,158
4,500
4,219
3,702
3,639
24,658
41,876
Drilling rig contracts ⁽⁴⁾
12,412
35,541
15,932
792
—
—
64,677
Delivery commitments ⁽⁵⁾
938
3,726
2,807
2,487
30
26
10,014
Produced water disposal commitments ⁽⁶⁾
3,331
21,336
21,443
21,445
21,501
17,678
106,734
Asset retirement obligations and other ⁽⁷⁾
633
2,853
910
377
244
16,499
21,516
Total Contractual Obligations ⁽⁸⁾

$42,872

$154,989

$261,594

$104,286

$401,404

$1,041,049

$2,006,194



	April - December 2019		2020		2021		2022		2023		2024 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$—		$825,143		$650,000		$250,000		$1,725,143
Cash interest on senior notes ⁽²⁾	50,938		61,250		61,250		61,250		40,938		41,250		316,876
Cash interest and commitment fees on revolving credit facility ⁽³⁾	27,501		36,627		36,627		12,616		—		—		113,371
Operating leases - other ⁽⁴⁾	7,658		9,359		6,550		3,645		3,680		21,499		52,391
Operating leases - drilling rig contracts ⁽⁵⁾	23,325		17,739		805		—		—		—		41,869
Delivery commitments ⁽⁶⁾	2,849		2,807		2,487		30		7		19		8,199
Produced water disposal commitments ⁽⁷⁾	15,001		20,894		20,898		20,954		10,471		9,769		97,987
Asset retirement obligations and other ⁽⁸⁾	4,824		2,542		628		488		432		20,784		29,698
Total Contractual Obligations		$132,096		$151,218		$129,245		$924,126		$705,528		$343,321		$2,385,534

(1)

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


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

(3)

Cash interest on our revolving credit facility was calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of ~~September 30, 2018~~March 31, 2019 of ~~3.87%~~4.18%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of ~~September 30, 2018,~~March 31, 2019, at the applicable commitment fee rate of ~~0.375%~~0.500%.

(4)

~~Drilling rig~~Other operating leases include contracts for office space and the use of well equipment, vehicles, and other office equipment. The amounts presented above represent gross contractual ~~obligations and accordingly, other~~obligations. Other joint owners in the properties operated by us ~~will~~ generally ~~be billed~~pay for their working interest share of costs associated with the use of well equipment.


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


~~(5)~~(6)	Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.


~~(6)~~(7)	Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.


~~(7)~~(8)	Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of ~~September 30, 2018~~March 31, 2019. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.


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

~~Financing~~Off Balance Sheet Arrangements

~~Senior Secured Revolving Credit Facility~~

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

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

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

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

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

See “Note 6. Long-Term Debt” for details of rates of interest on outstanding borrowings, commitment fees on the unused portion of lender commitments, and the financial covenants we are subject to under the terms of the credit agreement as of September 30, 2018.

~~7.50% Senior Notes~~

During the first quarter of 2018, we redeemed $320.0 million of the outstanding aggregate principal amount of our 7.50% Senior Notes at a price equal to 101.875% of par. Upon the redemptions, we paid $336.9 million, which included redemption premiums of $6.0 million as well as accrued but unpaid interest of $10.9 million. As a result of the redemptions, we recorded a loss on extinguishment of debt of $8.7 million, which included the redemption premiums $6.0 million paid to redeem the notes and non-cash charges of $2.7 million attributable to the write-off of unamortized premium and debt issuance costs.

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

~~Redemption of Preferred Stock~~

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

~~Redemption of Other Long-Term Debt~~

During the second quarter of 2018, we redeemed the remaining $4.4 million outstanding principal amount of our 4.375% Convertible Senior Notes due 2028 at a price equal to 100% of par. Upon redemption, we paid $4.5 million, which included accrued and unpaid interest of $0.1 million.off balance sheet arrangements.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, commitments and contingencies and preferred stock. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our ~~2017~~2018 Annual Report. See “Note 8.9. Preferred ~~Stock”~~Stock and Common Stock Warrants”, “Note ~~10.~~12. Derivative Instruments” and “Note ~~11.~~13. Fair Value Measurements” for details of the Preferred Stock and contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our ~~September 30, 2018~~March 31, 2019 cost center ceiling to changes in the 12-month average benchmark crude oil and natural gas prices underlying the average realized prices for sales of crude oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”). The sensitivity analysis is as of ~~September 30, 2018~~March 31, 2019 and, accordingly, does not consider

drilling and completion activity, acquisitions or divestitures of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to ~~September 30, 2018~~March 31, 2019 that may require revisions to estimates of proved reserves.


	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
September 30, 2018 Actual	$62.65	$2.55	$1,553
March 31, 2019 Actual					$60.54	$2.18	$1,184

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$68.99	$2.85	$2,105	$552	$66.83	$2.50	$1,762	$578
Crude Oil and Natural Gas -10%	$56.32	$2.25	$1,001	($552)	$54.24	$1.86	$606	($578)

Crude Oil Price Sensitivity
Crude Oil +10%	$68.99	$2.55	$2,062	$509	$66.83	$2.18	$1,708	$524
Crude Oil -10%	$56.32	$2.55	$1,044	($509)	$54.24	$2.18	$660	($524)

Natural Gas Price Sensitivity
Natural Gas +10%	$62.65	$2.85	$1,596	$43	$60.54	$2.50	$1,238	$54
Natural Gas -10%	$62.65	$2.25	$1,510	($43)	$60.54	$1.86	$1,130	($54)

The price of crude oil, which is the commodity price that our cost center ceiling is most sensitive to, increased slightly during the first quarter of 2019 as compared to year end 2018, however, the 12-Month Average Realized Price as of March 31, 2019 decreased when compared to the 12-Month Average Realized Price as of December 31, 2018. We currently estimate that the 12-Month Average Realized Price of crude oil as of June 30, 2019 will be $62.25, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Utilizing this estimated 12-Month Average Realized Price, we estimate that the second quarter of 2019 cost center ceiling will exceed the net book value, less related deferred income taxes, resulting in no impairment of proved oil and gas properties.

This estimate assumes that all other inputs and assumptions are as of March 31, 2019, other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to March 31, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.

Income Taxes

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

For the year ended December 31, 2018, we maintained a full valuation allowance against our deferred tax assets based on our conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2018, primarily due to impairments of proved oil and gas properties recognized in the first three quarters of 2016, which limited our ability to consider subjective positive evidence, such as its projections of future taxable income. However, as of March 31, 2019, we are in a cumulative pre-tax income position. Based on this factor, as well as other positive evidence including projected future taxable income for the current and future years, concluded that it is more likely than not that the deferred tax assets would be realized. As a result, we released $179.1 million of the valuation allowance, which was recognized as an income tax benefit for the three months ended March 31, 2019.

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

As of ~~September 30, 2018,~~March 31, 2019, we have estimated U.S. federal net operating loss carryforwards of ~~$1.1 billion.~~$1.1 billion that, if not utilized in earlier periods, will expire between 2026 and 2037. Our ability to utilize these U.S. loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold.

Due to the issuance of the Preferred Stock and the common stock offering associated with the ExL Acquisition in 2017, as well as the common stock offering in August 2018, our calculated ownership change percentage ~~increased, however,~~increased. However, as of ~~September 30, 2018,~~March 31, 2019, we do not believe we have a Section 382 limitation on the ability to utilize our U.S. loss carryforwards. Future equity transactions involving us or 5% shareholders of us (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes and therefore a limitation on the annual utilization of the U.S. loss carryforwards.

Recently Adopted and Recently Issued Accounting Pronouncements

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

Forward-Looking Statements

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

our growth strategies;

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

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

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

changes in working capital requirements, reserves, and acreage;

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

anticipated trends in our business;

availability of pipeline connections and water disposal on economic terms;

effects of competition on us;

our future results of operations;

profitability of drilling locations;

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

our planned expenditures, prospects and capital expenditure plan;

future market conditions in the oil and gas industry;

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

results of the Devon Properties;

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

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

our ability to maintain a sound financial position;

receipt of receivables and proceeds from divestitures;

our ability to complete planned transactions on desirable terms; ~~and~~

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

realization and other matters concerning deferred tax assets.

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

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

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

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under “Part I. Item 1A. Risk Factors” and other sections of our ~~2017~~2018 Annual Report and in our other filings with the SEC, including this quarterly report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our ~~2017~~2018 Annual Report. Except as disclosed below, there have been no material changes from the disclosure made in our ~~2017~~2018 Annual Report regarding our exposure to certain market risks.

Commodity Price Risk

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

The following ~~tables set~~table sets forth our crude oil, NGL, and natural gas revenues for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 as well as the impact on the crude oil, NGL, and natural gas revenues assuming a 10% increase and decrease in our average realized crude oil, NGL, and natural gas prices, excluding the impact of derivative settlements:

Three Months Ended September 30, 2018
Crude oil NGLs Natural gas Total
(In thousands)
Revenues
$254,525

$33,798

$15,052

$303,375

Impact of a 10% fluctuation in average realized prices
$25,450

$3,381

$1,506

$30,337


	Nine Months Ended September 30, 2018								Three Months Ended March 31, 2019
	Crude oil		NGLs		Natural gas		Total		Crude oil		NGLs		Natural gas		Total
	(In thousands)								(In thousands)
Revenues		$679,242		$71,969		$41,417		$792,628		$202,744		$16,837		$13,459		$233,040

Impact of a 10% fluctuation in average realized prices		$67,931		$7,197		$4,147		$79,275		$20,273		$1,684		$1,346		$23,303

We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not enter into commodity derivative instruments for speculative purposes. As of ~~September 30, 2018,~~March 31, 2019, our commodity derivative instruments consisted of price swaps, three-way collars, ~~basis swaps, and~~ sold call ~~options.~~options, and basis swaps. See “Note ~~10.~~12. Derivative Instruments” and “Note 15. Subsequent Events” for further ~~details~~discussion of our ~~crude oil, NGL and natural gas~~ commodity derivative instruments as of ~~September 30, 2018~~March 31, 2019 and ~~“Note 14. Subsequent Events” for further details of~~ our ~~crude oil~~commodity derivative instruments entered into subsequent to ~~September 30, 2018.~~March 31, 2019, respectively.

The following table sets forth the cash received (paid) for commodity derivative settlements, net, excluding deferred premium obligations, for the three months ended March 31, 2019 as well as the impact on the cash received (paid) for commodity derivative settlements, net assuming a 10% increase and decrease in the respective settlement prices:



	Three Months Ended March 31, 2019
	Crude oil			NGLs			Natural gas			Total
	(In thousands)
Cash received (paid) for commodity derivative settlements, net		($320	)		$623			($300	)		$3

Impact of a 10% increase in settlement prices		($2,575	)		($378	)		($362	)		($3,315	)
Impact of a 10% decrease in settlement prices		$8,854			$378			$300			$9,532

During the three months ended March 31, 2019, we paid $50.0 million as a result of the first annual settlement of the Contingent ExL Consideration and received $10.0 million from the first annual settlements of the Contingent Niobrara Consideration and the Contingent Utica Consideration as the specified pricing thresholds for fiscal year 2018 for each contingent consideration arrangement were exceeded. A 10% increase or decrease in the settlement price would have had no impact on the actual settlements related to our Contingent ExL Consideration, Contingent Niobrara Consideration, and Contingent Utica Consideration. A 10% increase in the settlement price would have resulted in a $3.0 million cash receipt related to our Contingent Marcellus Consideration, while a 10% decrease in the settlement price would have had no impact. See “Note 12. Derivative Instruments” for further details on the cash received (paid) for settlements of contingent consideration arrangements, net.

The primary drivers of our commodity derivative instrument fair values are the underlying forward oil and gas price curves. The following table sets forth the average forward oil and gas price curves as of March 31, 2019 for each of the years in which we have commodity derivative instruments:



	2019	2020	2021
Crude oil:
NYMEX WTI	$60.36	$58.75	$56.32
LLS-WTI Cushing	$4.77	$3.20	$2.83
WTI Midland-WTI Cushing	($0.19)	$0.40	$0.60
Natural gas:
NYMEX Henry Hub	$2.80	$2.74	$2.65
Waha-NYMEX Henry Hub	($1.63)	($0.87)	($0.49)

The following table sets forth the fair values as of ~~September 30, 2018,~~March 31, 2019 of our commodity derivative instruments, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price ~~curves:~~curves that are shown above:


	Crude oil			NGLs			Natural gas			Total			Crude oil			NGLs		Natural gas			Total
	(In thousands)												(In thousands)
Fair value liability as of September 30, 2018		$128,497			$7,378			$1,832			$137,707
Fair value liability as of March 31, 2019														($30,313	)		$—		$370			($29,943	)

Impact of a 10% increase in forward commodity prices		$75,109			$1,887			$2,266			$79,262			($38,340	)		$—		$181			($38,159	)
Impact of a 10% decrease in forward commodity prices		($56,318	)		($1,845	)		($1,376	)		($59,539	)		$26,738			$—		($1,013	)		$25,725

The fair values of the contingent consideration arrangements were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as forward oil and gas price curves, volatility factors and risk adjusted discount rates. See “Note ~~10. Derivative Instruments” and “Note 11.~~13. Fair Value Measurements” for further ~~details.~~discussion.

The following table sets forth the fair values of the contingent consideration arrangements as of ~~September 30, 2018,~~March 31, 2019, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price ~~curves:~~curves that are shown above:


	Contingent ExL Consideration			Contingent Niobrara Consideration			Contingent Marcellus Consideration			Contingent Utica Consideration			Contingent ExL Consideration			Contingent Niobrara Consideration			Contingent Marcellus Consideration			Contingent Utica Consideration
	(In thousands)												(In thousands)
Potential (payment) receipt per year		($50,000	)		$5,000			$3,000			$5,000			($50,000	)		$5,000			$3,000			$5,000
Maximum potential (payment) receipt		($125,000	)		$15,000			$7,500			$15,000
Maximum remaining potential (payment) receipt														($75,000	)		$10,000			$6,000			$10,000

Fair value (liability) asset as of September 30, 2018		($112,045	)		$11,675			$1,315			$12,215
Fair value (liability) asset as of March 31, 2019														($59,583	)		$5,212			$888			$6,205
Impact of a 10% increase in forward commodity prices		($2,685	)		$835			$625			$690			($4,538	)		$1,477			$877			$1,203
Impact of a 10% decrease in forward commodity prices		$5,490			($1,270	)		($530	)		($1,130	)		$9,910			($1,997	)		($422	)		($1,902	)

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding borrowings on our revolving credit facility. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate ~~7.50% Senior Notes,~~ 6.25% Senior Notes and 8.25% Senior Notes, but can impact their fair values. As of ~~September 30, 2018,~~March 31, 2019, we had approximately ~~$1.3~~$1.7 billion of long-term debt outstanding. Of this amount, approximately ~~$1.0~~$0.9 billion was fixed-rate debt with a weighted average interest rate of ~~6.89%~~7.22% and approximately $0.8 billion was floating-rate debt on outstanding borrowings on our revolving credit facility with a weighted average interest rate of 4.18%. A 1% increase or decrease in the interest rate on outstanding borrowings on our revolving credit facility would have a corresponding increase or decrease in our interest expense of approximately $2.1 million. See “Note ~~11.~~13. Fair Value Measurements” for further details on the fair value of our ~~7.50% Senior Notes,~~ 6.25% Senior Notes and 8.25% Senior Notes.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of ~~September 30, 2018~~March 31, 2019 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended ~~September 30, 2018~~March 31, 2019 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

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

~~Barrow-Shaver Litigation~~

~~On September 24, 2014 an unfavorable jury verdict was delivered against the Company in a case entitled~~ ~~Barrow-Shaver Resources Company v. Carrizo Oil & Gas, Inc.~~ in the amount of $27.7 million. On January 5, 2015, the court entered a judgment awarding the verdict amount plus $2.9 million in attorneys’ fees plus pre-judgment interest. On January 31, 2017, the Twelfth Court of Appeals at Tyler, Texas reversed the trial court decision and rendered judgment in favor of the Company, declaring that the plaintiff take nothing on any of its claims. The plaintiff filed a motion for rehearing with the Twelfth Court of Appeals at Tyler, Texas, which was not granted, and petitioned the Texas Supreme Court for review. In August 2018, the Texas Supreme Court granted review and set oral argument for December 4, 2018. The payment of damages per the original judgment was superseded by posting a bond in the amount of $25.0 million, which will remain outstanding pending resolution of the appeals process (which could take an extended period of time) or agreement of the parties.

The case was filed September 19, 2012 in the 7th Judicial District Court of Smith County, Texas and arises from an agreement between the plaintiff and the Company whereby the plaintiff could earn an assignment of certain of the Company’s leasehold interests in Archer and Baylor counties, Texas for each commercially productive oil and gas well drilled by the plaintiff on acreage covered by the agreement. The agreement contained a provision that the plaintiff had to obtain the Company’s written consent to any assignment of rights provided by such agreement. The plaintiff subsequently entered into a purchase and sale agreement with a third-party purchaser allowing the third-party purchaser to purchase rights in approximately 62,000 leasehold acres, including the rights under the agreement with the Company, for approximately $27.7 million. The plaintiff requested the Company’s consent to make the assignment to the third-party purchaser and the Company refused. The plaintiff alleged that, as a result of the Company’s refusal, the third-party purchaser terminated such purchase and sale agreement. The plaintiff sought damages for breach of contract, tortious interference with existing contract and other grounds in an amount not to exceed $35.0 million plus exemplary damages and attorneys’ fees. As mentioned above, the Twelfth Court of Appeals at Tyler, Texas found in favor of the Company on all grounds.

Item 1A. Risk Factors

There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our ~~2017~~2018 Annual Report.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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



Exhibit Number		Exhibit Description
†1.1 10.1		~~Underwriting~~Fourteenth Amendment to Credit Agreement, dated as of ~~August 14, 2018, by and between~~March 27, 2019, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and ~~Citigroup Global Markets Inc. and Goldman Sachs & Co. LLC, as representatives of~~ the ~~Underwriters~~lender parties thereto (incorporated herein by reference to Exhibit ~~1.1~~10.1 to the Company’s Current Report on Form 8-K filed on ~~August 16, 2018)~~March 28, 2019).
*31.1	—	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	—	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	—	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	—	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101	—	Interactive Data Files


†	Incorporated by reference as indicated.


*	Filed herewith.

Signatures

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



			Carrizo Oil & Gas, Inc. (Registrant)

Date:	~~November 7, 2018~~May 9, 2019		By:	/s/ David L. Pitts
		��		Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	~~November 7, 2018~~May 9, 2019		By:	/s/ Gregory F. Conaway
				Vice President and Chief Accounting Officer (Principal Accounting Officer)

~~-51-~~-41-



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

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

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



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

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



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

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

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

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



	Contingent Consideration Arrangements
	Assets		Liability
	(In thousands)
December 31, 2017		$10,190		($85,625	)
Recognition of divestiture date fair value	7,880		—
Gain (loss) on changes in fair value, net⁽¹⁾	7,135		(26,420		)
Transfers into (out of) Level 3	—		—
September 30, 2018		$25,205		($112,045	)



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



	September 30, 2018
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,114,698			$133,308			$—		($3,096,917	)		$151,089
Total property and equipment, net	6,570			2,709,162			3,028		(3,833		)	2,714,927
Investment in subsidiaries	(576,826		)	—			—		576,826			—
Other assets	29,611			15,371			—		—			44,982
Total Assets		$2,574,053			$2,857,841			$3,028		($2,523,924	)		$2,910,998

Liabilities and Shareholders’ Equity
Current liabilities		$305,096			$3,347,575			$3,028		($3,099,937	)		$555,762
Long-term liabilities	1,357,294			87,092			—		15,879			1,460,265
Preferred stock	173,629			—			—		—			173,629
Total shareholders’ equity	738,034			(576,826		)	—		560,134			721,342
Total Liabilities and Shareholders’ Equity		$2,574,053			$2,857,841			$3,028		($2,523,924	)		$2,910,998



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

Daily production volumes by product -
Crude oil (Bbls/d)	40,813		34,903		5,910			17	%
NGLs (Bbls/d)	11,469		6,777		4,692			69	%
Natural gas (Mcf/d)	74,072		81,265		(7,193		)	(9	%)
Total barrels of oil equivalent (Boe/d)	64,627		55,224		9,403			17	%

Daily production volumes by region (Boe/d) -
Eagle Ford	39,024		39,002		22			—	%
Delaware Basin	25,577		6,994		18,583			266	%
Other	26		9,228		(9,202		)	(100	%)
Total barrels of oil equivalent (Boe/d)	64,627		55,224		9,403			17	%

Average realized prices -
Crude oil ($ per Bbl)		$67.78		$47.37		$20.41		43	%
NGLs ($ per Bbl)	32.04		20.01		12.03			60	%
Natural gas ($ per Mcf)	2.21		2.24		(0.03		)	(1	%)
Total average realized price ($ per Boe)		$51.02		$35.68		$15.34		43	%

Revenues (In thousands) -
Crude oil		$254,525		$152,101		$102,424		67	%
NGLs	33,798		12,467		21,331			171	%
Natural gas	15,052		16,711		(1,659		)	(10	%)
Total revenues		$303,375		$181,279		$122,096		67	%



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



	October - December 2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt ⁽¹⁾		$—		$—		$130,000		$—		$309,837		$900,000		$1,339,837
Cash interest on senior notes ⁽²⁾	20,313		71,000		71,000		61,250		61,250		82,188		367,001
Cash interest and commitment fees on revolving credit facility ⁽³⁾	3,637		14,233		14,233		14,233		4,903		—		51,239
Capital leases	450		1,800		1,050		—		—		—		3,300
Operating leases	1,158		4,500		4,219		3,702		3,639		24,658		41,876
Drilling rig contracts ⁽⁴⁾	12,412		35,541		15,932		792		—		—		64,677
Delivery commitments ⁽⁵⁾	938		3,726		2,807		2,487		30		26		10,014
Produced water disposal commitments ⁽⁶⁾	3,331		21,336		21,443		21,445		21,501		17,678		106,734
Asset retirement obligations and other ⁽⁷⁾	633		2,853		910		377		244		16,499		21,516
Total Contractual Obligations ⁽⁸⁾		$42,872		$154,989		$261,594		$104,286		$401,404		$1,041,049		$2,006,194