Edgar Filing: CARRIZO OIL & GAS INC

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Non-accelerated filer

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Smaller reporting company

CRZO 2Q15 Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________________________

FORM 10-Q

_________________________________________________



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

For the quarterly period ended June 30, 2015



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 x NO ¨

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

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of July 31, 2015 was 51,963,796.

TABLE OF CONTENTS



		PAGE
Part I. Financial Information
Item 1.	Consolidated Financial Statements (Unaudited)	2
	Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	2
	Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	29
Part II. Other Information
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Mine Safety Disclosures	30
Item 5.	Other Information	30
Item 6.	Exhibits	31
Signatures		32

Part I. Financial Information

Item 1. Consolidated Financial Statements

CARRIZO OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS (In thousands, except share and per share data) (Unaudited)

	June 30, 2015		December 31, 2014
Assets
Current assets
Cash and cash equivalents		$2,004		$10,838
Accounts receivable, net	81,182		92,946
Derivative assets	114,182		171,101
Other current assets	4,096		3,736
Total current assets	201,464		278,621
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	2,312,047		2,086,727
Unproved properties, not being amortized	504,646		535,197
Other property and equipment, net	7,752		7,329
Total property and equipment, net	2,824,445		2,629,253
Derivative assets	20,171		43,684
Debt issuance costs	26,342		25,403
Other assets	5,328		4,515
Total Assets		$3,077,750		$2,981,476

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$81,486		$106,819
Revenues and royalties payable	58,687		66,954
Accrued capital expenditures	75,448		106,149
Accrued interest	20,412		21,149
Liabilities of discontinued operations	4,412		4,405
Deferred income taxes	39,760		61,258
Other current liabilities	60,861		57,570
Total current liabilities	341,066		424,304
Long-term debt	1,372,785		1,351,346
Liabilities of discontinued operations	3,900		8,394
Deferred income taxes	62,112		77,349
Asset retirement obligations	13,862		12,187
Other liabilities	4,012		4,455
Total liabilities	1,797,737		1,878,035
Commitments and contingencies
Shareholders’ equity
Common stock, $0.01 par value, 90,000,000 shares authorized; 51,961,981 issued and outstanding as of June 30, 2015 and 46,127,924 issued and outstanding as of December 31, 2014	520		461
Additional paid-in capital	1,159,291		915,436
Retained earnings	120,202		187,544
Total shareholders’ equity	1,280,013		1,103,441
Total Liabilities and Shareholders’ Equity		$3,077,750		$2,981,476

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues
Crude oil		$111,257			$165,962			$194,315			$296,324
Natural gas liquids	3,799			5,983			8,272			11,871
Natural gas	8,438			21,530			20,957			42,492
Total revenues	123,494			193,475			223,544			350,687

Costs and Expenses
Lease operating	23,375			17,378			45,091			29,983
Production taxes	5,031			8,182			9,049			14,273
Ad valorem taxes	1,723			1,906			4,756			3,334
Depreciation, depletion and amortization	79,331			80,746			153,202			145,340
General and administrative	19,095			27,682			50,672			55,943
(Gain) loss on derivatives, net	12,595			39,950			(13,844		)	60,630
Interest expense, net	16,999			11,931			35,195			24,356
Loss on extinguishment of debt	38,137			—			38,137			—
Other expense, net	281			413			7,273			987
Total costs and expenses	196,567			188,188			329,531			334,846

Income (Loss) From Continuing Operations Before Income Taxes	(73,073		)	5,287			(105,987		)	15,841
Income tax (expense) benefit	26,103			(2,073		)	37,541			(6,006		)
Income (Loss) From Continuing Operations	(46,970		)	3,214			(68,446		)	9,835
Income (Loss) From Discontinued Operations, Net of Income Taxes	838			(895		)	1,104			(1,540		)
Net Income (Loss)		($46,132	)		$2,319			($67,342	)		$8,295

Net Income (Loss) Per Common Share - Basic
Income (loss) from continuing operations		($0.92	)		$0.07			($1.40	)		$0.22
Income (loss) from discontinued operations, net of income taxes	0.02			(0.02		)	0.02			(0.04		)
Net income (loss)		($0.90	)		$0.05			($1.38	)		$0.18

Net Income (Loss) Per Common Share - Diluted
Income (loss) from continuing operations		($0.92	)		$0.07			($1.40	)		$0.21
Income (loss) from discontinued operations, net of income taxes	0.02			(0.02		)	0.02			(0.03		)
Net income (loss)		($0.90	)		$0.05			($1.38	)		$0.18

Weighted Average Common Shares Outstanding
Basic	51,225			45,213			48,827			45,109
Diluted	51,225			46,158			48,827			45,988

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended June 30,
	2015			2014
Cash Flows From Operating Activities
Net income (loss)		($67,342	)		$8,295
(Income) loss from discontinued operations, net of income taxes	(1,104		)	1,540
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities from continuing operations
Depreciation, depletion and amortization	153,202			145,340
(Gain) loss on derivatives, net	(13,844		)	60,630
Net cash received (paid) for derivative settlements	94,193			(17,788		)
Loss on extinguishment of debt	38,137			—
Stock-based compensation, net	14,796			29,139
Deferred income taxes	(37,961		)	305
Non-cash interest expense, net	2,787			1,346
Other, net	5,384			1,594
Changes in operating assets and liabilities-
Accounts receivable	3,732			(23,139		)
Accounts payable	(16,437		)	4,526
Accrued liabilities	(6,605		)	(14,040		)
Other, net	(3,286		)	(2,102		)
Net cash provided by operating activities from continuing operations	165,652			195,646
Net cash used in operating activities from discontinued operations	(1,220		)	(903		)
Net cash provided by operating activities	164,432			194,743
Cash Flows From Investing Activities
Capital expenditures - oil and gas properties	(377,995		)	(474,011		)
Capital expenditures - other property and equipment	(1,173		)	(375		)
Proceeds from sales of oil and gas properties, net	285			7,434
Other, net	(3,684		)	1,913
Net cash used in investing activities from continuing operations	(382,567		)	(465,039		)
Net cash used in investing activities from discontinued operations	(937		)	(4,679		)
Net cash used in investing activities	(383,504		)	(469,718		)
Cash Flows From Financing Activities
Issuance of senior notes	650,000			—
Tender and redemption of senior notes	(626,681		)	—
Payment of deferred purchase payment	(150,000		)	—
Borrowings under credit agreement	800,939			293,000
Repayments of borrowings under credit agreement	(683,939		)	(172,000		)
Payments of debt issuance costs	(11,443		)	(594		)
Sale of common stock, net of offering costs	231,316			—
Excess tax benefits from stock-based compensation	—			5,678
Proceeds from stock options exercised	46			74
Net cash provided by financing activities from continuing operations	210,238			126,158
Net cash provided by financing activities from discontinued operations	—			—
Net cash provided by financing activities	210,238			126,158
Net Decrease in Cash and Cash Equivalents	(8,834		)	(148,817		)
Cash and Cash Equivalents, Beginning of Period	10,838			157,439
Cash and Cash Equivalents, End of Period		$2,004			$8,622

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

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Operations

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

Consolidated Financial Statements

The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. These financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”). Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

2. Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates, and judgments in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its 2014 Annual Report. There have been no changes to the Company’s significant accounting policies since December 31, 2014.

Recent Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (the “ASU”). The objective of this ASU is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt rather than as an asset. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and applied retrospectively with early adoption permitted. The adoption of the ASU will not have an impact on the Company’s consolidated financial statements, other than balance sheet reclassifications.

3. Discontinued Operations

On February 22, 2013, the Company closed on the sale of Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all of its interest in the Huntington Field discovery, including a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) for an agreed-upon price of $184.0 million, including the assumption and repayment by Iona Energy of the $55.0 million of borrowings outstanding under Carrizo UK’s senior secured multicurrency credit facility as of the closing date. The liabilities, results of operations and cash flows associated with Carrizo UK have been classified as discontinued operations in the consolidated financial statements. The liabilities of discontinued operations of $8.3 million and $12.8 million as of June 30, 2015 and December 31, 2014, respectively, relate to an accrual for estimated future obligations related to the sale.

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The following table summarizes the amounts included in income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of operations:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Revenues		$—			$—			$—			$—

Costs and expenses
General and administrative	1,166			466			1,367			903
Increase (decrease) in estimated future obligations	(3,086		)	913			(3,695		)	1,448
(Gain) loss on derivatives, net	—			(2		)	—			18
Income (Loss) From Discontinued Operations Before Income Taxes	1,920			(1,377		)	2,328			(2,369		)
Income tax (expense) benefit	(1,082		)	482			(1,224		)	829
Income (Loss) From Discontinued Operations, Net of Income Taxes		$838			($895	)		$1,104			($1,540	)

Carrizo UK is a disregarded entity for U.S. federal income tax purposes. Accordingly, the income tax (expense) benefit reflected above includes the Company’s U.S. deferred income tax (expense) benefit associated with the income (loss) from discontinued operations before income taxes. The related U.S. deferred tax assets and liabilities have been classified as deferred income taxes of continuing operations in the consolidated balance sheets.

4. Property and Equipment, Net

As of June 30, 2015 and December 31, 2014, total property and equipment, net consisted of the following:



	June 30, 2015			December 31, 2014
	(In thousands)
Proved properties		$3,550,822			$3,174,268
Accumulated depreciation, depletion and amortization	(1,238,775		)	(1,087,541		)
Proved properties, net	2,312,047			2,086,727
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	382,953			401,954
Exploratory wells in progress	59,485			71,402
Capitalized interest	62,208			61,841
Total unproved properties, not being amortized	504,646			535,197
Other property and equipment	17,190			16,017
Accumulated depreciation	(9,438		)	(8,688		)
Other property and equipment, net	7,752			7,329
Total property and equipment, net		$2,824,445			$2,629,253

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. Average depreciation, depletion and amortization (“DD&A”) per Boe of proved properties was $23.81 and $26.34 for the three months ended June 30, 2015 and 2014, respectively, and $23.63 and $26.49 for the six months ended June 30, 2015 and 2014, respectively.

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $5.1 million and $5.3 million for the three months ended June 30, 2015 and 2014, respectively, and $10.9 million and $10.7 million for the six months ended June 30, 2015 and 2014, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost of exploratory wells in progress and related capitalized interest. The Company capitalized interest costs associated with its unproved properties totaling $9.0 million and $8.6 million for the three months ended June 30, 2015 and 2014, respectively, and $18.7 million and $16.3 million for the six months ended June 30, 2015 and 2014, respectively.

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5. Income Taxes

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense or benefit to interim periods. The rates are the ratio of estimated annual income tax expense or benefit to estimated annual income or loss before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the discrete item occurs. The estimated annual effective income tax rates are applied to the year-to-date income or loss before income taxes by taxing jurisdiction to determine the income tax expense or benefit allocated to the interim period. The Company updates its estimated annual effective income tax rates at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rates will impact future income tax expense or benefit. Income tax (expense) benefit differs from income tax (expense) benefit computed by applying the U.S. Federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Income (loss) from continuing operations before income taxes		($73,073	)		$5,287			($105,987	)		$15,841
Income tax (expense) benefit at the statutory rate	25,575			(1,850		)	37,095			(5,544		)
State income taxes, net of U.S. Federal income tax benefit	(145		)	(222		)	(221		)	(414		)
2015 Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	1,671			—			1,671			—
Other	(998		)	(1		)	(1,004		)	(48		)
Total income tax (expense) benefit from continuing operations		$26,103			($2,073	)		$37,541			($6,006	)

6. Long-Term Debt

Long-term debt consisted of the following as of June 30, 2015 and December 31, 2014:



	June 30, 2015		December 31, 2014
	(In thousands)
Long-term debt
Deferred purchase payment due 2015		$—		$150,000
Unamortized discount for deferred purchase payment	—		(1,100		)
Senior Secured Revolving Credit Facility due 2018	117,000		—
8.625% Senior Notes due 2018	—		600,000
Unamortized discount for 8.625% Senior Notes	—		(3,444		)
7.50% Senior Notes due 2020	600,000		600,000
Unamortized premium for 7.50% Senior Notes	1,360		1,465
6.25% Senior Notes due 2023	650,000		—
Other long-term debt due 2028	4,425		4,425
Total long-term debt		$1,372,785		$1,351,346

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of June 30, 2015, had a borrowing base of $685.0 million, with $117.0 million of borrowings outstanding with a weighted average interest rate of 1.67%. As of June 30, 2015, the Company also had $0.6 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest only payments until July 2, 2018, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the Spring and Fall of each year, as well as special redeterminations described in the credit agreement, in each case which 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 governing the revolving credit facility.

On May 5, 2015, the Company entered into the sixth amendment to the senior secured revolving credit agreement to, among other things, (i) establish an approved borrowing base of $685.0 million until the next redetermination thereof, (ii) establish a swing

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line commitment under the revolving credit facility not to exceed $15.0 million and (iii) include seven additional banks to its banking syndicate, bringing the total number of banks to 19 as of the date of such amendment.

The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 80% of the proved reserve value of the oil and gas properties included in the determination of the borrowing base.

Amounts 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 as set forth in the table below on the unused portion of lender commitments, and which are included as a component of interest expense.



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

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA (as defined in the credit agreement) of not more than 4.00 to 1.00; and (2) a Current Ratio (as defined in the credit agreement) of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt discounts and premiums and is net of cash and cash equivalents, EBITDA is for the last four quarters after giving pro forma effect to certain material acquisitions and dispositions of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of June 30, 2015, the ratio of Total Debt to EBITDA was 2.61 to 1.00 and the Current Ratio was 2.75 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 amounts outstanding under the credit agreement are dependent on the timing of cash flows from operations, capital expenditures, acquisitions and dispositions of oil and gas properties and securities offerings.

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

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

8.625% Senior Notes due 2018

Since October 15, 2014, the Company had the right to redeem all or a portion of the 8.625% Senior Notes at redemption prices decreasing from 104.313% to 100% of the principal amount on October 15, 2017, plus accrued and unpaid interest. On April 14, 2015, the Company commenced a cash tender offer for any or all of the outstanding $600.0 million aggregate principal amount of its 8.625% Senior Notes. The tender offer expired on April 23, 2015. On April 28, 2015, the Company made an aggregate cash payment of $276.4 million for the $264.2 million aggregate principal amount of 8.625% Senior Notes validly tendered in the tender offer. This represented a tender offer premium totaling $12.2 million, equal to $1,046.13 for each $1,000 principal amount of 8.625% Senior Notes validly tendered and accepted for payment pursuant to the tender offer. In addition, all 8.625% Senior Notes accepted for payment received accrued and unpaid interest of $0.8 million from the last interest payment date up to, but not including, the settlement date.

In connection with the cash tender offer, the Company also sent a notice of redemption to the trustee for its 8.625% Senior Notes to conditionally call for redemption on May 14, 2015 all of the 8.625% Senior Notes then outstanding, conditioned upon and subject to the Company receiving specified net proceeds from one or more securities offerings, which conditions were satisfied. On May 14, 2015, the Company paid an aggregate redemption price of $352.6 million, including a redemption premium of $14.5 million, which represented 104.313% of the principal amount of the then outstanding 8.625% Senior Notes (or $1,043.13 for each $1,000 principal amount of the 8.625% Senior Notes) plus accrued and unpaid interest of $2.3 million from the last interest payment date up to, but not including, the redemption date, to redeem the then outstanding $335.8 million aggregate principal amount of

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8.625% Senior Notes. As a result of the cash tender offer and the redemption of the 8.625% Senior Notes, the Company recorded a loss on extinguishment of debt of $38.1 million during the three and six months ended June 30, 2015, which includes the premium paid to repurchase the 8.625% Senior Notes of $26.7 million and non-cash charges of $11.4 million attributable to the write-off of unamortized debt issuance costs and the remaining discount associated with the 8.625% Senior Notes.

6.25% Senior Notes due 2023

On April 28, 2015, the Company closed a public offering of $650.0 million aggregate principal amount of 6.25% Senior Notes due 2023. The Company received proceeds of approximately $640.3 million, net of underwriting discounts and commissions. The net proceeds were used to fund the repurchase and redemption of the 8.625% Senior Notes described above as well as to temporarily repay borrowings outstanding under the Company’s revolving credit facility. The 6.25% Senior Notes bear interest at 6.25% per annum which is payable semi-annually on each April 15 and October 15 and mature on April 15, 2023. Before April 15, 2018, the Company may, at its option, redeem all or a portion of the 6.25% Senior Notes at 100% of the principal amount plus a make-whole premium. Thereafter, the Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 104.688% to 100% of the principal amount on April 15, 2018, plus accrued and unpaid interest. The 6.25% Senior Notes were guaranteed by the same subsidiaries that also guarantee the 7.50% Senior Notes and the revolving credit facility.

The indenture governing the 6.25% Senior Notes, which is substantially similar to the indenture governing the 7.50% Senior Notes, contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments.

7. Commitments and Contingencies

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

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

8. Shareholders’ Equity

Common Stock Offering

On March 20, 2015, the Company completed its public offering of 5.2 million shares of its common stock at a price of $44.75 per share, which generated proceeds of $231.3 million, net of offering costs. The net proceeds from the common stock offering were used to repay a portion of the borrowings under the Company’s revolving credit facility and for general corporate purposes.

Exercise of Warrants

On November 24, 2009, the Company entered into an agreement with an unrelated third party and its affiliate under which the Company issued 118,200 warrants to purchase shares of the Company’s common stock. In May 2015, the holders of the warrants exercised all warrants outstanding on a “cashless” basis at an exercise price of $22.09 resulting in the issuance of 71,913 net shares of the Company’s common stock.

-9-

Stock-Based Compensation

The Company recognized the following stock-based compensation expense, net for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Stock appreciation rights		($49	)		$11,116			$5,891			$19,572
Restricted stock awards and units	6,014			8,224			11,229			13,925
Performance share awards	496			319			765			333
	6,461			19,659			17,885			33,830
Less: amounts capitalized to proved and unproved properties	(1,518		)	(2,681		)	(3,089		)	(4,691		)
Total stock-based compensation expense, net		$4,943			$16,978			$14,796			$29,139
Income tax benefit		$1,731			$5,943			$5,179			$10,199

9. Earnings Per Share

Supplemental income (loss) from continuing operations per common share information is provided below:



	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(In thousands, except per share amounts)
Income (Loss) from Continuing Operations		($46,970	)		$3,214		($68,446	)		$9,835
Basic weighted average common shares outstanding	51,225			45,213		48,827			45,109
Effect of dilutive instruments	—			945		—			879
Diluted weighted average common shares outstanding	51,225			46,158		48,827			45,988
Income (Loss) from Continuing Operations Per Common Share
Basic		($0.92	)		$0.07		($1.40	)		$0.22
Diluted		($0.92	)		$0.07		($1.40	)		$0.21

Basic income (loss) from continuing operations per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted income (loss) from continuing operations per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock awards and units, performance share awards, stock options and warrants. When a loss from continuing operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.

For the three and six months ended June 30, 2015, the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 0.7 million shares of restricted stock awards and units, performance share awards, options and warrants due to the loss from continuing operations. For the three and six months ended June 30, 2014, the number of shares of restricted stock awards and units, performance share awards, options and warrants excluded were insignificant.

10. Derivative Instruments

The Company uses commodity derivative instruments, primarily fixed price swaps and costless collars, to reduce its exposure to commodity price volatility for a substantial, but varying, portion of its forecasted crude oil and natural gas production up to 36 months and thereby achieve a more predictable level of cash flows to support the Company’s drilling and completion capital expenditure program. Costless collars are designed to establish floor and ceiling prices on anticipated future production. While the use of collars limit the downside risk of adverse price movements below the floor price, collars also limit the benefit of favorable price movements above the ceiling price. The Company does not enter into derivative instruments for speculative or trading purposes.

-10-

The Company typically has numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value of derivative instruments where the Company is in a net asset position with its counterparties as of June 30, 2015 and December 31, 2014 totaled $134.4 million and $214.8 million, respectively, and is summarized by counterparty in the table below:



Counterparty	June 30, 2015		December 31, 2014
Wells Fargo	57	%	37	%
Societe Generale	27	%	26	%
Regions	10	%	8	%
Union Bank	5	%	4	%
Royal Bank of Canada	1	%	1	%
Credit Suisse	—	%	24	%
Total	100	%	100	%

The counterparties to the Company’s derivative instruments are lenders under the Company’s credit agreement. Because each of the lenders have investment grade credit ratings, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. Although the Company does not currently anticipate such nonperformance, it continues to monitor the credit ratings of its counterparties.

For the three months ended June 30, 2015 and 2014, the Company recorded in the consolidated statements of operations a loss on derivatives, net of $12.6 million and $40.0 million, respectively. For the six months ended June 30, 2015 and 2014, the Company recorded in the consolidated statements of operations a gain on derivatives, net of $13.8 million and a loss on derivatives, net of $60.6 million, respectively.

On February 11, 2015, the Company entered into derivative transactions offsetting its then existing crude oil derivative positions covering the periods from March 2015 through December 2016. As a result of the offsetting derivative transactions, the Company locked in $166.4 million of cash flows, of which $40.0 million was received due to contract settlements during the three and six months ended June 30, 2015. As of June 30, 2015, the remaining locked in value of cash flows is $126.4 million, of which $106.5 million is classified as a current derivative asset and $19.9 million is classified as a noncurrent derivative asset in the consolidated balance sheets. These locked in cash flows are not subject to price risk and will be received as the applicable contracts settle. Included in the $13.8 million gain on derivatives, net for the six months ended June 30, 2015, is an $8.4 million gain representing the increase in fair value of the crude oil derivative positions from December 31, 2014 to February 11, 2015. Additionally, on February 13, 2015, the Company entered into costless collars for the periods from March 2015 through December 2016 which will continue to provide the Company with downside protection at crude oil prices below the weighted average floor prices yet allow the Company to benefit from an increase in crude oil prices up to the weighted average ceiling prices.

The following sets forth a summary of the Company’s crude oil derivative positions, including additional costless collars entered into subsequent to the February 13, 2015 costless collars described above, at average NYMEX prices as of June 30, 2015:



Period	Type of Contract	Volumes (in Bbls/d)	Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
July - December 2015	Costless Collars	16,200		$50.00	$67.34
January - December 2016	Costless Collars	5,490		$50.96	$74.73

The following sets forth a summary of the Company’s natural gas derivative positions at average NYMEX prices as of June 30, 2015:



Period	Type of Contract	Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)
July - December 2015	Fixed Price Swaps	30,000		$4.29

-11-

11. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2015 and December 31, 2014. All items included in the tables below are Level 2 inputs within the fair value hierarchy:



	June 30, 2015
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Derivative assets
Derivative assets-current		$123,669			($9,487	)		$114,182
Derivative assets-noncurrent	20,289			(118		)	20,171
Derivative liabilities
Other current liabilities	(9,605		)	9,487			(118		)
Other liabilities	(118		)	118			—
Total		$134,235			$—			$134,235



	December 31, 2014
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Derivative assets
Derivative assets-current		$183,625			($12,524	)		$171,101
Derivative assets-noncurrent	44,725			(1,041		)	43,684
Derivative liabilities
Other current liabilities	(12,707		)	12,524			(183		)
Other liabilities	(1,058		)	1,041			(17		)
Total		$214,585			$—			$214,585

The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for crude oil and natural gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.

The derivative asset and liability fair values reported in the consolidated balance sheets that pertain to the Company’s derivative instruments, as well as the Company’s crude oil derivative instruments that were entered into subsequent to the offsetting derivative transactions, are as of a particular point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. However, the fair value of the net derivative asset attributable to the offsetting crude oil derivative transactions are not subject to price risk as changes in the fair value of the original positions are offset by changes in the fair value of the offsetting positions. The Company typically has numerous hedge positions that span several time

-12-

periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the six months ended June 30, 2015 and 2014.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables and long-term debt, which are classified as Level 1 under the fair value hierarchy with the exception of the deferred purchase payment, which is classified as Level 2 under the fair value hierarchy. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the carrying amounts of long-term debt with the fair values of the Company’s senior notes and other long-term debt based on quoted market prices and the fair value of the deferred purchase payment based on indirect observable market rates.



	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
8.625% Senior Notes due 2018		$—		$—		$596,555		$597,000
7.50% Senior Notes due 2020	601,360		630,000		601,466		573,000
6.25% Senior Notes due 2023	650,000		648,375		—		—
Other long-term debt due 2028	4,425		4,204		4,425		4,071
Deferred purchase payment due 2015	—		—		148,900		148,558

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.

Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A.

-13-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

(Unaudited)



	June 30, 2015
	Parent Company		Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,404,178		$79,119		$—		($2,281,833	)		$201,464
Total property and equipment, net	31,995		2,757,601		3,028		31,821			2,824,445
Investment in subsidiaries	240,306		—		—		(240,306		)	—
Other assets	142,362		—		—		(90,521		)	51,841
Total Assets		$2,818,841		$2,836,720		$3,028		($2,580,839	)		$3,077,750

Liabilities and Shareholders’ Equity
Current liabilities		$173,022		$2,449,862		$3,028		($2,284,846	)		$341,066
Long-term liabilities	1,379,611		146,552		—		(69,492		)	1,456,671
Total shareholders’ equity	1,266,208		240,306		—		(226,501		)	1,280,013
Total Liabilities and Shareholders’ Equity		$2,818,841		$2,836,720		$3,028		($2,580,839	)		$3,077,750



	December 31, 2014
	Parent Company		Combined Guarantor Subsidiaries		Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,380,445		$245,051		$111		($2,346,986	)		$278,621
Total property and equipment, net	613		2,562,029		39,939		26,672			2,629,253
Investment in subsidiaries	233,173		—		—		(233,173		)	—
Other assets	140,774		—		—		(67,172		)	73,602
Total Assets		$2,755,005		$2,807,080		$40,050		($2,620,659	)		$2,981,476

Liabilities and Shareholders’ Equity
Current liabilities		$296,686		$2,434,649		$39,955		($2,346,986	)		$424,304
Long-term liabilities	1,364,793		139,353		—		(50,415		)	1,453,731
Total shareholders’ equity	1,093,526		233,078		95		(223,258		)	1,103,441
Total Liabilities and Shareholders’ Equity		$2,755,005		$2,807,080		$40,050		($2,620,659	)		$2,981,476

-14-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)



	Three Months Ended June 30, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Total revenues		$660			$122,891			($57	)		$—			$123,494
Total costs and expenses	96,843			106,409			(216		)	(6,469		)	196,567
Income (loss) from continuing operations before income taxes	(96,183		)	16,482			159			6,469			(73,073		)
Income tax (expense) benefit	33,664			(5,769		)	(55		)	(1,737		)	26,103
Equity in income of subsidiaries	10,817			—			—			(10,817		)	—
Income (loss) from continuing operations	(51,702		)	10,713			104			(6,085		)	(46,970		)
Income from discontinued operations, net of income taxes	838			—			—			—			838
Net income (loss)		($50,864	)		$10,713			$104			($6,085	)		($46,132	)



	Three Months Ended June 30, 2014
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$1,206			$192,269			$—		$—			$193,475
Total costs and expenses	78,089			109,088			—		1,011			188,188
Income (loss) from continuing operations before income taxes	(76,883		)	83,181			—		(1,011		)	5,287
Income tax (expense) benefit	26,908			(29,381		)	—		400			(2,073		)
Equity in income of subsidiaries	53,800			—			—		(53,800		)	—
Income from continuing operations	3,825			53,800			—		(54,411		)	3,214
Loss from discontinued operations, net of income taxes	(895		)	—			—		—			(895		)
Net income		$2,930			$53,800			$—		($54,411	)		$2,319

-15-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)



	Six Months Ended June 30, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$1,250			$222,294			$—		$—			$223,544
Total costs and expenses	123,511			211,321			—		(5,301		)	329,531
Income (loss) from continuing operations before income taxes	(122,261		)	10,973			—		5,301			(105,987		)
Income tax (expense) benefit	42,792			(3,841		)	—		(1,410		)	37,541
Equity in income of subsidiaries	7,132			—			—		(7,132		)	—
Income (loss) from continuing operations	(72,337		)	7,132			—		(3,241		)	(68,446		)
Income from discontinued operations, net of income taxes	1,104			—			—		—			1,104
Net income (loss)		($71,233	)		$7,132			$—		($3,241	)		($67,342	)



	Six Months Ended June 30, 2014
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$2,772			$347,915			$—		$—			$350,687
Total costs and expenses	133,640			198,997			—		2,209			334,846
Income (loss) from continuing operations before income taxes	(130,868		)	148,918			—		(2,209		)	15,841
Income tax (expense) benefit	45,803			(52,121		)	—		312			(6,006		)
Equity in income of subsidiaries	96,797			—			—		(96,797		)	—
Income from continuing operations	11,732			96,797			—		(98,694		)	9,835
Loss from discontinued operations, net of income taxes	(1,540		)	—			—		—			(1,540		)
Net income		$10,192			$96,797			$—		($98,694	)		$8,295

-16-

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended June 30, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($29,397	)		$195,049			$—		$—			$165,652
Net cash used in investing activities from continuing operations	(337,518		)	(342,695		)	—		297,646			(382,567		)
Net cash provided by financing activities from continuing operations	360,238			147,646			—		(297,646		)	210,238
Net cash used in discontinued operations	(2,157		)	—			—		—			(2,157		)
Net decrease in cash and cash equivalents	(8,834		)	—			—		—			(8,834		)
Cash and cash equivalents, beginning of period	10,838			—			—		—			10,838
Cash and cash equivalents, end of period		$2,004			$—			$—		$—			$2,004



	Six Months Ended June 30, 2014
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($122,961	)		$318,607			$—			$—			$195,646
Net cash used in investing activities from continuing operations	(146,432		)	(464,288		)	(21,554		)	167,235			(465,039		)
Net cash provided by financing activities from continuing operations	126,158			145,681			21,554			(167,235		)	126,158
Net cash used in discontinued operations	(5,582		)	—			—			—			(5,582		)
Net decrease in cash and cash equivalents	(148,817		)	—			—			—			(148,817		)
Cash and cash equivalents, beginning of period	157,439			—			—			—			157,439
Cash and cash equivalents, end of period		$8,622			$—			$—			$—			$8,622

-17-

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

The following is management’s discussion and analysis of the significant factors that affected the Company’s financial position and results of operations during the periods included in the accompanying unaudited consolidated financial statements. You should read this in conjunction with the unaudited interim consolidated financial statements included 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 the audited Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2014.

General Overview

Production and Commodity Prices. Total production for the three months ended June 30, 2015 was 36,118 Boe/d, an increase of 8% from the 33,319 Boe/d for the three months ended June 30, 2014 primarily driven by increased crude oil production in the Eagle Ford, partially offset by decreased natural gas production due to voluntary curtailments in Marcellus. Average realized crude oil, natural gas liquids and natural gas prices for the second quarter of 2015 were $54.86 per Bbl, $11.95 per Bbl and $1.49 per Mcf, respectively, which represent decreases of 45%, 58% and 52% from the second quarter of 2014, respectively. As a result, despite the increase in crude oil production, our second quarter of 2015 revenues of $123.5 million were 36% lower than our second quarter of 2014 revenues of $193.5 million.

Drilling and Completion Activity. See the table below for details of our operated drilling and completion activity by region:



	Three Months Ended June 30, 2015				As of June 30, 2015
	Drilled		Wells Brought on Production		Waiting on Completion		Producing		Rig count
Region	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Rig count
Eagle Ford	20	16.8	17	14.1	26	21.6	226	199.9	3
Niobrara	5	3.0	3	1.5	17	9.6	115	48.8	—
Marcellus	—	—	—	—	11	4.3	82	26.3	—
Utica	—	—	—	—	—	—	4	3.1	—
Permian	—	—	—	—	—	—	—	—	1
Total	25	19.8	20	15.6	54	35.5	427	278.1	4

Financing Activities. On April 14, 2015, we commenced a cash tender offer for any or all of the outstanding $600.0 million aggregate principal amount of our 8.625% Senior Notes. In connection with the cash tender offer, we also redeemed on May 14, 2015 all of the 8.625% Senior Notes that remained outstanding following the cash tender offer. See “—Financing Arrangements—8.625% Senior Notes” for details of the tender offer and redemption of our 8.625% Senior Notes.

On April 28, 2015, we closed a public offering of $650.0 million aggregate principal amount of 6.25% Senior Notes due 2023. The 6.25% Senior Notes bear interest at 6.25% per annum which is payable semi-annually on each April 15 and October 15 and mature on April 15, 2023. The proceeds of $640.3 million, net of underwriting discounts and commissions, were used to fund the repurchase of the 8.625% Senior Notes in the tender offer described above, redeem the remaining outstanding 8.625% Senior Notes, and repay borrowings outstanding under our senior secured revolving credit facility.

On May 5, 2015, we entered into the sixth amendment to the credit agreement governing the revolving credit facility. The revolving credit facility was amended to, among other things, (i) establish an approved borrowing base of $685.0 million until the next redetermination, (ii) establish a swing line commitment under our revolving credit facility not to exceed $15.0 million and (iii) include seven additional banks to our banking syndicate, bringing the total number of banks to 19 as of the date of such amendment. As of June 30, 2015, $117.0 million of borrowings and $0.6 million in letters of credit were outstanding under our revolving credit facility.

-18-

Results of Operations

Three Months Ended June 30, 2015, Compared to the Three Months Ended June 30, 2014

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended June 30, 2015 and 2014:



	Three Months Ended June 30,				2015 Period Compared to 2014 Period
	2015		2014		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	2,028		1,678		350			21	%
NGLs (MBbls)	318		208		110			53	%
Natural gas (MMcf)	5,646		6,879		(1,233		)	(18	%)
Total Natural gas and NGLs (MMcfe)	7,554		8,127		(573		)	(7	%)
Total barrels of oil equivalent (MBoe)	3,287		3,032		255			8	%

Daily production volumes by product -
Crude oil (Bbls/d)	22,284		18,440		3,844			21	%
NGLs (Bbls/d)	3,494		2,286		1,208			53	%
Natural gas (Mcf/d)	62,042		75,593		(13,551		)	(18	%)
Total Natural gas and NGLs (Mcfe/d)	83,006		89,308		(6,302		)	(7	%)
Total barrels of oil equivalent (Boe/d)	36,118		33,319		2,799			8	%

Daily production volumes by region (Boe/d) -
Eagle Ford	24,976		19,978		4,998			25	%
Niobrara	3,428		2,542		886			35	%
Marcellus	6,054		9,895		(3,841		)	(39	%)
Utica	1,480		123		1,357			1,103	%
Other	180		781		(601		)	(77	%)
Total barrels of oil equivalent (Boe/d)	36,118		33,319		2,799			8	%

Average realized prices -
Crude oil ($ per Bbl)		$54.86		$98.90		($44.04	)	(45	%)
NGLs ($ per Bbl)	11.95		28.76		(16.81		)	(58	%)
Natural gas ($ per Mcf)	1.49		3.13		(1.64		)	(52	%)
Total Natural gas and NGLs ($ per Mcfe)		$1.62		$3.39		($1.77	)	(52	%)
Total average realized price ($ per Boe)		$37.57		$63.81		($26.24	)	(41	%)

Revenues (In thousands) -
Crude oil		$111,257		$165,962		($54,705	)	(33	%)
NGLs	3,799		5,983		(2,184		)	(37	%)
Natural gas	8,438		21,530		(13,092		)	(61	%)
Total revenues		$123,494		$193,475		($69,981	)	(36	%)

Revenues for the three months ended June 30, 2015 decreased 36% to $123.5 million from $193.5 million for the same period in 2014 primarily due to the decrease in crude oil and natural gas prices, partially offset by the increase in crude oil production. Production volumes for the three months ended June 30, 2015 and 2014 were 36,118 Boe/d and 33,319 Boe/d, respectively. The increase in production from the second quarter of 2014 to the second quarter of 2015 was primarily due to increased production from new wells in the Eagle Ford, partially offset by normal production declines and voluntary curtailments of natural gas production in the Marcellus due to unfavorable natural gas prices.

Lease operating expenses for the three months ended June 30, 2015 increased to $23.4 million ($7.11 per Boe) from $17.4 million ($5.73 per Boe) for the same period in 2014. The increase in lease operating expenses is primarily due to increased production from new wells in the Eagle Ford. The increase in lease operating expense per Boe is primarily due to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties.

-19-

Production taxes decreased to $5.0 million (or 4.1% of revenues) for the three months ended June 30, 2015 from $8.2 million (or 4.2% of revenues) for the same period in 2014 as a result of the decrease in crude oil and natural gas revenues, partially offset by increased crude oil production.

Ad valorem taxes decreased to $1.7 million ($0.52 per Boe) for the three months ended June 30, 2015 from $1.9 million ($0.63 per Boe) for the same period in 2014. The decrease in ad valorem taxes and ad valorem taxes per Boe is primarily due to a decrease in our annual estimate of ad valorem taxes, partially offset by an increase in ad valorem taxes due to new wells drilled in Eagle Ford in 2014.

DD&A expense for the second quarter of 2015 decreased $1.4 million to $79.3 million ($24.13 per Boe) from the DD&A expense for the second quarter of 2014 of $80.7 million ($26.63 per Boe). The decrease in DD&A expense is attributable to the decrease in the DD&A rate per Boe, partially offset by increased production. The decrease in the DD&A rate per Boe from the second quarter of 2014 to the second quarter of 2015 is primarily due to crude oil reserves added at lower future development costs. The components of our DD&A expense were as follows:



	Three Months Ended June 30,
	2015		2014
	(In thousands)
DD&A of proved oil and gas properties		$78,262		$79,859
Depreciation of other property and equipment	364		437
Amortization of other assets	435		297
Accretion of asset retirement obligations	270		153
Total DD&A		$79,331		$80,746

General and administrative expense decreased to $19.1 million for the three months ended June 30, 2015 from $27.7 million for the corresponding period in 2014. The decrease was primarily due to a decrease in stock-based compensation expense associated with stock appreciation rights as a result of a decline in the fair value of stock appreciation rights for the three months ended June 30, 2015 as compared to an increase in the fair value of stock appreciation rights for the same period of 2014, as well as a decrease in the number of stock appreciation rights outstanding during the second quarter of 2015 due to exercises during 2014, partially offset by accruals for estimated 2015 bonuses.

The loss on derivatives, net for the three months ended June 30, 2015 amounted to $12.6 million primarily due to new crude oil hedge positions executed during 2015 and the upward shift in the futures curve of forecasted commodity prices for crude oil from April 1, 2015 to June 30, 2015. The loss on derivatives, net for the three months ended June 30, 2014 amounted to $40.0 million primarily due to the upward shift in the futures curve of forecasted commodity prices for crude oil from April 1, 2014 (or the subsequent date on which new contracts were entered into) to June 30, 2014.

Interest expense, net for the three months ended June 30, 2015 was $17.0 million as compared to $11.9 million for the same period in 2014. The increase was primarily due to the interest expense on the $300.0 million aggregate principal amount of our 7.50% Senior Notes that were issued in October 2014.

The effective income tax rate for the second quarter of 2015 and 2014 was 35.7% and 39.2%, respectively. The variance from the U.S. Federal statutory rate of 35% for the three months ended June 30, 2015 was due to the impact of state income taxes including a rate reduction in the Texas Franchise Tax and other items. The variance from the U.S. Federal statutory rate of 35% for the three months ending June 30, 2014 was due to the impact of state income taxes.

-20-

Results of Operations

Six Months Ended June 30, 2015, Compared to the Six Months Ended June 30, 2014

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the six months ended June 30, 2015 and 2014:



	Six Months Ended June 30,				2015 Period Compared to 2014 Period
	2015		2014		Increase (Decrease)			% Increase (Decrease)
Total production volumes -
Crude oil (MBbls)	3,951		3,030		921			30	%
NGLs (MBbls)	636		374		262			70	%
Natural gas (MMcf)	10,880		12,097		(1,217		)	(10	%)
Total Natural gas and NGLs (MMcfe)	14,694		14,341		353			2	%
Total barrels of oil equivalent (MBoe)	6,400		5,420		980			18	%

Daily production volumes by product -
Crude oil (Bbls/d)	21,831		16,740		5,091			30	%
NGLs (Bbls/d)	3,512		2,066		1,446			70	%
Natural gas (Mcf/d)	60,111		66,834		(6,723		)	(10	%)
Total Natural gas and NGLs (Mcfe/d)	81,183		79,232		1,951			2	%
Total barrels of oil equivalent (Boe/d)	35,361		29,945		5,416			18	%

Daily production volumes by region (Boe/d) -
Eagle Ford	24,741		18,024		6,717			37	%
Niobrara	3,230		2,348		882			38	%
Marcellus	6,014		8,665		(2,651		)	(31	%)
Utica	1,105		252		853			338	%
Other	271		656		(385		)	(59	%)
Total barrels of oil equivalent (Boe/d)	35,361		29,945		5,416			18	%

Average realized prices -
Crude oil ($ per Bbl)		$49.18		$97.80		($48.62	)	(50	%)
NGLs ($ per Bbl)	13.01		31.74		(18.73		)	(59	%)
Natural gas ($ per Mcf)	1.93		3.51		(1.58		)	(45	%)
Total Natural gas and NGLs ($ per Mcfe)		$1.99		$3.79		($1.80	)	(47	%)
Total average realized price ($ per Boe)		$34.93		$64.70		($29.77	)	(46	%)

Revenues (In thousands) -
Crude oil		$194,315		$296,324		($102,009	)	(34	%)
NGLs	8,272		11,871		(3,599		)	(30	%)
Natural gas	20,957		42,492		(21,535		)	(51	%)
Total revenues		$223,544		$350,687		($127,143	)	(36	%)

Revenues for the six months ended June 30, 2015 decreased 36% to $223.5 million from $350.7 million for the same period in 2014 primarily due to the decrease in crude oil and natural gas prices, partially offset by the increase in crude oil production. Production volumes for the six months ended June 30, 2015 and 2014 were 35,361 Boe/d and 29,945 Boe/d, respectively. The increase in production from the six months ended June 30, 2014 to the six months ended June 30, 2015 was primarily due to increased production from new wells in the Eagle Ford, partially offset by normal production declines and voluntary curtailments of natural gas production in the Marcellus due to unfavorable natural gas prices.

Lease operating expenses for the six months ended June 30, 2015 increased to $45.1 million ($7.05 per Boe) from $30.0 million ($5.53 per Boe) for the same period in 2014. The increase in lease operating expenses is primarily due to increased production from new wells in the Eagle Ford. The increase in lease operating expense per Boe is primarily due to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties.

-21-

Production taxes decreased to $9.0 million (or 4.0% of revenues) for the six months ended June 30, 2015 from $14.3 million (or 4.1% of revenues) for the same period in 2014 as a result of the decrease in crude oil and natural gas revenues, partially offset by increased crude oil production.

Ad valorem taxes increased to $4.8 million ($0.74 per Boe) for the six months ended June 30, 2015 from $3.3 million ($0.62 per Boe) for the same period in 2014. The increase in ad valorem taxes and ad valorem taxes per Boe for the six months ended June 30, 2015 is primarily due to new wells drilled in Eagle Ford in 2014, partially offset by a decrease in our annual estimate of ad valorem taxes.

DD&A expense for the six months ended June 30, 2015 increased $7.9 million to $153.2 million ($23.94 per Boe) from the DD&A expense for the six months ended June 30, 2014 of $145.3 million ($26.82 per Boe). The increase in DD&A expense is attributable to increased production, partially offset by the decrease in the DD&A rate per Boe. The decrease in the DD&A rate per Boe is primarily due to crude oil reserves added at lower future development costs. The components of our DD&A expense were as follows:



	Six Months Ended June 30,
	2015		2014
	(In thousands)
DD&A of proved oil and gas properties		$151,234		$143,572
Depreciation of other property and equipment	750		876
Amortization of other assets	691		601
Accretion of asset retirement obligations	527		291
Total DD&A		$153,202		$145,340

General and administrative expense decreased to $50.7 million for the six months ended June 30, 2015 from $55.9 million for the same period in 2014. The decrease was primarily due to a decrease in stock-based compensation expense resulting from a decrease in the number of stock appreciation rights outstanding during the six months ended June 30, 2015 due to exercises during 2014 and a decrease in the fair value of stock appreciation rights for the six months ended June 30, 2015 compared to the same period in 2014, partially offset by accruals for estimated 2015 bonuses.

The gain on derivatives, net for the six months ended June 30, 2015 amounted to $13.8 million primarily due to the downward shift in the futures curve of forecasted commodity prices for crude oil during the first quarter of 2015, prior to our lock-in of our then existing crude oil derivative positions, and the downward shift in the futures curve of forecasted commodity prices for natural gas from January 1, 2015 to June 30, 2015. The loss on derivatives, net for the six months ended June 30, 2014 amounted to $60.6 million primarily due to the upward shift in the futures curve of forecasted commodity prices for crude oil from January 1, 2014 (or the subsequent date new contracts were entered into) to June 30, 2014.

Interest expense, net for the six months ended June 30, 2015 was $35.2 million as compared to $24.4 million for the same period in 2014. The increase was primarily due to the interest expense on the $300.0 million aggregate principal amount of our 7.50% Senior Notes that were issued in October 2014 and the accretion of the discount on the deferred purchase payment due to Eagle Ford Minerals, LLC in February 2015, partially offset by the associated increase in capitalized interest.

The effective income tax rate for the six months ended June 30, 2015 and 2014 was 35.4% and 37.9%, respectively. The variance from the U.S. Federal statutory rate of 35% for the six months ended June 30, 2015 was due to the impact of state income taxes including a rate reduction in the Texas Franchise Tax and other items. The variance from the U.S. Federal statutory rate of 35% for the six months ended June 30, 2014 was due to the impact of state income taxes.

-22-

Liquidity and Capital Resources

2015 Capital Expenditure Plan. As previously announced in May 2015, we allocated approximately $30.0 million to our 2015 drilling and completion capital expenditure plan in order to fund the Delaware Basin activity, which increased it to $470.0 million to $490.0 million from $440.0 million to $460.0 million at that time. Our leasehold and seismic capital expenditure plan has since been increased by $10.0 million to $45.0 million to account for the larger than expected acreage acquisitions during the second quarter of 2015. We currently intend to finance the remainder of our 2015 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 the availability and cost of drilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. Below is a summary of capital expenditures through June 30, 2015:



	Three Months Ended						Six Months Ended
	March 31, 2015		June 30, 2015				June 30, 2015
	(In thousands)
Drilling and completion
Eagle Ford		$103,338		$105,833				$209,171
Niobrara	20,486		12,976				33,462
Utica	22,971		(2,591		)		20,380
Marcellus	3,280		557				3,837
Other	1,487		692				2,179
Total drilling and completion	151,562		117,467				269,029
Leasehold and seismic	12,440		18,770			(1)	31,210
Total		$164,002		$136,237				$300,239


(1)	Leasehold and seismic is presented net of approximately $6.5 million of proceeds related to acreage positions offered to and accepted by joint venture partners.

Our capital expenditure plan and the capital expenditures included above exclude capitalized general and administrative costs, interest and asset retirement obligations.

Sources and Uses of Cash. Our primary use of cash is capital expenditures related to our drilling and completion programs and, to a lesser extent, our leasehold and seismic data acquisition programs. For the six months ended June 30, 2015, capital expenditures and acquisitions of oil and gas properties, net of proceeds from sales of oil and gas properties, exceeded our net cash provided by operations for continuing operations. For the six months ended June 30, 2015, we funded our capital expenditures with cash provided by operations, borrowings under our revolving credit facility and a portion of the net proceeds from our March 2015 equity offering and, to a lesser degree, our April 2015 debt offering, which were also used to repay 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 commodity prices. As such, we hedge a portion of our forecasted production to mitigate the risk of a decline in crude oil and natural gas prices.

•

Borrowings under our revolving credit facility. As of July 31, 2015, we had $133.2 million of borrowings outstanding and $0.6 million in letters of credit outstanding under our revolving credit facility, which reduce the amounts available under our revolving credit facility. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility.


•	Asset sales. In order to fund our capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us.

•

Securities offerings. As situations or conditions arise, we may choose to issue debt, equity or other instruments 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. In March 2015, we sold 5.2 million shares of our common stock in an underwritten public offering at a price of $44.75 per share. We used the proceeds of approximately $231.3 million, net of offering costs, to repay borrowings under our revolving credit facility and for general corporate purposes. On April 28, 2015, we closed a public offering of $650.0 million aggregate principal amount of 6.25% Senior Notes due 2023. The proceeds of $640.3 million, net of underwriting discounts and commissions, were used to repurchase and redeem our 8.625% Senior Notes and temporarily repay borrowings outstanding under our revolving credit facility.

-23-


•	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 from continuing operations was $165.7 million and $195.6 million for the six months ended June 30, 2015 and 2014, respectively. The change was primarily due to a decrease in oil and gas revenues and an increase in operating expenses, partially offset by an increase in the net cash from derivative settlements and a decrease in working capital requirements.

Net cash used in investing activities from continuing operations were $382.6 million and $465.0 million for the six months ended June 30, 2015 and 2014, respectively and relate primarily to oil and gas capital expenditures associated with our capital expenditure plan.

Net cash provided by financing activities from continuing operations were $210.2 million and $126.2 million for the six months ended June 30, 2015 and 2014, respectively. The increase was due to net proceeds related to the issuances of common stock in March 2015 and the 6.25% Senior Notes in April 2015, partially offset by the tender and redemption of the 8.625% Senior Notes and the payment of the deferred purchase payment in February 2015.

Liquidity/Cash Flow Outlook

Economic downturns may adversely affect our ability to access capital markets in the future. We currently believe that cash flows from operations and borrowings under our revolving credit facility will be sufficient to fund our immediate cash flow requirements. Cash flows from operations are primarily driven by production and commodity prices. Crude oil prices have declined significantly beginning in the fourth quarter of 2014. To manage our exposure to commodity price risk and to provide a level of certainty in the cash flows to support our drilling and completion capital expenditure program, we hedge a portion of our forecasted production. On February 11, 2015, we entered into derivative transactions offsetting our then existing crude oil derivative positions covering the periods from March 2015 through December 2016, which locked in $166.4 million of cash flows, of which $40.0 million was received due to contract settlements during the three and six months ended June 30, 2015. Subsequent to the offsetting derivative transactions, we entered into costless collars for periods from March 2015 through December 2016. As of June 30, 2015, we have costless collars on 16,200 Bbls/d of crude oil for the remainder of 2015 and 5,490 Bbls/d of crude oil for 2016, at weighted average floor prices of $50.00 per Bbl and $50.96 per Bbl, respectively, and weighted average ceiling prices of $67.34 per Bbl and $74.73 per Bbl, respectively. In addition, we have 30,000 MMBtu/d of natural gas fixed price swaps at $4.29 per MMBtu.

As of July 31, 2015, we had $133.2 million of borrowings outstanding under our revolving credit facility and had issued $0.6 million in letters of credit outstanding, which reduce the amounts available under our revolving credit facility. The borrowing base under our revolving credit facility is affected by our lenders’ assumptions with respect to future crude oil and natural gas prices. Our borrowing base may decrease if our lenders reduce their expectations with respect to future crude oil and natural gas prices from those assumptions used to determine our existing borrowing base. The Spring 2015 borrowing base redetermination resulted in a borrowing base of $685.0 million, reflecting a reduction from the prior borrowing base of $800.0 million but consistent with our prior elected commitment amount. Looking forward to the Fall 2015 borrowing base redetermination, based on currently available bank pricing assumptions and current pricing differentials, drilling and completion plans, and reserve and cost assumptions, we currently expect the Fall 2015 redetermination to result in a borrowing base of approximately $725.0 million. These assumptions and other matters may change materially. Additionally, the borrowing base amount is subject to considerable discretion by the banks. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing the revolving credit facility.

If cash flows from operations and borrowings under our revolving credit facility and the other sources of cash described under “—Sources and Uses of Cash” are insufficient to fund the remainder of our 2015 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 2015 capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from asset sales, 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.

-24-

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of June 30, 2015 (in thousands):



	July - December 2015		2016		2017		2018		2019		2020 and Thereafter		Total
Long-term debt (1)		$—		$—		$—		$117,000		$—		$1,254,425		$1,371,425
Cash interest on long-term debt (2)	44,983		89,903		89,903		87,875		85,819		188,817		587,300
Operating leases	2,018		4,029		4,158		4,232		4,357		10,753		29,547
Drilling rig contracts (3)	20,544		24,251		20,513		3,957		—		—		69,265
Pipeline volume commitments	7,190		6,249		2,488		2,465		2,390		5,475		26,257
Asset retirement obligations and other (4)	2,610		4,105		2,030		3		24		13,829		22,601
Total Contractual Obligations		$77,345		$128,537		$119,092		$215,532		$92,590		$1,473,299		$2,106,395


(1)	Long-term debt consists of the principal amounts of the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, other long-term debt due 2028 and borrowings outstanding under our revolving credit facility which matures in 2018.

(2)

Cash interest on long-term debt includes cash payments for interest on the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, other long-term debt due 2028 and the borrowings outstanding under our revolving credit facility which matures in 2018. Cash payments for interest on our revolving credit facility were calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of June 30, 2015 of 1.67%.


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


(4)	Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of June 30, 2015. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results.

Financing Arrangements

Senior Secured Revolving Credit Facility

We have a senior secured revolving credit facility with a syndicate of banks that, as of June 30, 2015, had a borrowing base of $685.0 million, with $117.0 million of borrowings outstanding with a weighted average interest rate of 1.67% and $0.6 million in letters of credit outstanding. The credit agreement governing our revolving credit facility provides for interest only payments until July 2, 2018, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under our credit agreement is subject to regular redeterminations in the Spring and Fall of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base.

Our obligations under the credit agreement are guaranteed by our material domestic subsidiaries and are secured by liens on substantially all of our assets, including a mortgage lien on oil and gas properties having at least 80% of the proved reserve value of the oil and gas properties included in the determination of the borrowing base.

We are 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 (as defined in the credit agreement) of not more than 4.00 to 1.00; and (2) a Current Ratio (as defined in the credit agreement) of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt discounts and premiums and is net of cash and cash equivalents, EBITDA is for the last four quarters after giving pro forma effect to certain material acquisitions and dispositions of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of June 30, 2015, the ratio of Total Debt to EBITDA was 2.61 to 1.00 and the Current Ratio was 2.75 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 amounts outstanding under the credit agreement are dependent on the timing of cash flows from operations, capital expenditures, acquisitions and dispositions of oil and gas properties and securities offerings.

On May 5, 2015, we entered into the sixth amendment to our senior secured revolving credit agreement to, among other things, (i) establish an approved borrowing base of $685.0 million until the next redetermination thereof, (ii) establish a swing line commitment under our revolving credit facility not to exceed $15.0 million and (iii) include seven additional banks to our banking syndicate, bringing the total number of banks to 19 as of the date of such amendment.

8.625% Senior Notes

On April 14, 2015, we commenced a cash tender offer for any or all of the outstanding $600.0 million aggregate principal amount of our 8.625% Senior Notes at a price of 104.613% of the principal amount plus accrued and unpaid interest. In connection with the cash tender offer, we also sent a notice of redemption to the trustee for our 8.625% Senior Notes to conditionally call for redemption on May 14, 2015 all of the 8.625% Senior Notes then outstanding at a price of 104.313% of the principal amount plus

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accrued and unpaid interest, conditioned upon and subject to our receipt of specified net proceeds from one or more securities offerings, which conditions were satisfied. On April 28, 2015, we made an aggregate cash payment of $276.4 million for the $264.2 million aggregate principal amount of 8.625% Senior Notes validly tendered in the tender offer, which excluded accrued interest paid of $0.8 million. We paid $352.6 million to redeem the 8.625% Senior Notes that remained outstanding, which represented $335.8 million of outstanding aggregate principal amount of 8.625% Senior Notes, the redemption premium of $14.5 million, and accrued and unpaid interest of $2.3 million from the last interest payment date up to, but not including, the redemption date. The total price to repurchase and redeem all of the outstanding $600.0 million aggregate principal amount of our 8.625% Senior Notes was $629.8 million. As a result of the cash tender offer and the redemption of our 8.625% Senior Notes, we recorded a loss on extinguishment of debt of approximately $38.1 million during the three and six months ended June 30, 2015.

6.25% Senior Notes

On April 28, 2015, we closed a public offering of $650.0 million aggregate principal amount of 6.25% Senior Notes due 2023. The 6.25% Senior Notes mature on April 15, 2023, with interest payable semi-annually. Before April 15, 2018, we may redeem all or a portion of our 6.25% Senior Notes at 100% of the principal amount plus a make-whole premium. Thereafter, we may redeem all or a portion of our 6.25% Senior Notes at redemption prices decreasing from 104.688% to 100% of the principal amount on April 15, 2018, plus accrued and unpaid interest. In addition, prior to April 15, 2018, we may, at our option, redeem up to 35% of the aggregate principal amount of the 6.25% Senior Notes with the proceeds of certain equity offerings at a redemption price of 106.25%, of the principal amount, plus accrued and unpaid interest. Holders of our 6.25% Senior Notes may require us to repurchase some or all of their 6.25% Senior Notes for cash in the event of a Change of Control (as defined in the indenture governing the 6.25% Senior Notes), at 101% of the principal amount plus accrued and unpaid interest. The 6.25% Senior Notes were guaranteed by the same subsidiaries that also guarantee our 7.50% Senior Notes and the revolving credit facility.

The indenture governing our 6.25% Senior Notes, which is substantially similar to the indenture governing our 7.50% Senior Notes, contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: pay distributions on, purchase or redeem our common stock or other capital stock or redeem our subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of our assets; enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing our senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments.

Securities Offering

In March 2015, we sold 5.2 million shares of our common stock in an underwritten public offering at a price of $44.75 per share. We used the proceeds of approximately $231.3 million, net of offering costs, to repay borrowings under our revolving credit facility and for general corporate purposes.

Critical Accounting Policies

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, income taxes and commitments and contingencies. These policies and estimates are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2014. We evaluate subsequent events through the date the financial statements are issued.

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The table below presents results of the full cost ceiling test as of June 30, 2015, along with various pricing scenarios to demonstrate the sensitivity of our cost center ceiling to changes in 12 month average benchmark crude oil and natural gas prices underlying our average realized prices. Prices do not include the impact of crude oil and natural gas derivative instruments. This sensitivity analysis is as of June 30, 2015 and, accordingly, does not consider drilling results, production, changes in oil and gas prices, and changes in future development and operating costs subsequent to June 30, 2015 that may require revisions to our proved reserve estimates and resulting cash flows used in the full cost ceiling test. Based on forecasted costs and estimates of the expected 12 month average benchmark crude oil and natural gas prices at September 30, 2015, we anticipate recognizing after-tax full cost ceiling test impairments of our oil and gas properties in the third and fourth quarters of 2015. The estimated range of after-tax impairment for the third quarter of 2015 is $300.0 million to $400.0 million. The full cost ceiling test impairment estimate is driven primarily by the significant decrease in crude oil prices beginning in the fourth quarter of 2014. We do not expect the impairments to have significant adverse effects to our proved oil and gas reserves.



	12 Month Average Realized Prices		Excess (Deficit) of cost center ceiling over net capitalized costs (after-tax)	Increase (Decrease) in excess of cost center ceiling over net capitalized costs (after-tax)
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
June 30, 2015 Actual	$68.92	$2.32	$43

Oil and Gas Price Sensitivity
Oil and Gas +10%	$76.08	$2.66	$328	$285
Oil and Gas -10%	$61.76	$1.98	($252)	($295)

Oil Price Sensitivity
Oil +10%	$76.08	$2.32	$303	$260
Oil -10%	$61.76	$2.32	($227)	($270)

Gas Price Sensitivity
Gas +10%	$68.92	$2.66	$63	$20
Gas -10%	$68.92	$1.98	$13	($30)

Recent Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (the “ASU”). The objective of this ASU is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt rather than as an asset. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and applied retrospectively with early adoption permitted. The adoption of the ASU will not have an impact on our consolidated financial statements, other than balance sheet reclassifications.

Volatility of Crude Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of crude oil and natural gas, which are affected by changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. For the three months ended June 30, 2015, average realized crude oil prices decreased 45% to $54.86 per Bbl from $98.90 per Bbl for the same period in 2014. Average natural gas prices decreased 52% to $1.49 per Mcf for the first quarter of 2015 from $3.13 per Mcf for the first quarter of 2014.

We review the carrying value of our oil and gas properties on a quarterly basis using the full cost method of accounting. See Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Summary of Critical Accounting Policies—Oil and Gas Properties” and Part I, “Item 1A. Risk Factors—We may record impairments of oil and gas properties that would reduce our shareholders’ equity.” in our Annual Report on Form 10-K for the year ended December 31, 2014.

We use commodity derivative instruments, primarily fixed price swaps and costless collars, to reduce our exposure to commodity price volatility for a substantial, but varying, portion of our forecasted crude oil and natural gas production up to 36 months and thereby achieve a more predictable level of cash flows to support our drilling and completion capital expenditure program. Costless collars are designed to establish floor and ceiling prices on anticipated future production. While the use of collars

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limit the downside risk of adverse price movements below the floor price, collars also limit the benefit of favorable price movements above the ceiling price. We do not enter into derivative instruments for speculative or trading purposes.

We typically have numerous hedge positions that span several time periods and often result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. We net our derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value of derivative instruments where we are in a net asset position with our counterparties as of June 30, 2015 and December 31, 2014 totaled $134.4 million and $214.8 million, respectively, and is summarized by counterparty in the table below:



Counterparty	June 30, 2015		December 31, 2014
Wells Fargo	57	%	37	%
Societe Generale	27	%	26	%
Regions	10	%	8	%
Union Bank	5	%	4	%
Royal Bank of Canada	1	%	1	%
Credit Suisse	—	%	24	%
Total	100	%	100	%

The counterparties to our derivative instruments are lenders under our credit agreement. Because each of the lenders have investment grade credit ratings, we believe we do not have significant credit risk and accordingly do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, we are exposed to credit risk to the extent of nonperformance by the counterparties to our derivative instruments. Although we do not currently anticipate such nonperformance, we continue to monitor the credit ratings of our counterparties.

For the three months ended June 30, 2015 and 2014, we recorded in the consolidated statements of operations a loss on derivatives, net of $12.6 million and $40.0 million, respectively. For the six months ended June 30, 2015 and 2014, we recorded in the consolidated statements of operations a gain on derivatives, net of $13.8 million and a loss on derivatives, net of $60.6 million, respectively.

On February 11, 2015, we entered into derivative transactions offsetting our then existing crude oil derivative positions covering the periods from March 2015 through December 2016. As a result of the offsetting derivative transactions, we locked in $166.4 million of cash flows, of which $40.0 million was received due to contract settlements during the three and six months ended June 30, 2015. As of June 30, 2015, the remaining locked in value of cash flows is $126.4 million, of which $106.5 million is classified as a current derivative asset and $19.9 million is classified as a noncurrent derivative asset in the consolidated balance sheets. These locked in cash flows are not subject to price risk and will be received as the applicable contracts settle. Included in the $13.8 million gain on derivatives, net for the six months ended June 30, 2015 is an $8.4 million gain representing the increase in fair value of the crude oil derivative positions from December 31, 2014 to February 11, 2015. Additionally, on February 13, 2015, we entered into costless collars for the periods from March 2015 through December 2016 which will continue to provide us with downside protection at crude oil prices below the weighted average floor prices yet allow us to benefit from an increase in crude oil prices up to the weighted average ceiling prices.

The following sets forth a summary of our crude oil derivative positions, including additional costless collars entered into subsequent to the February 13, 2015 costless collars described above, at average NYMEX prices as of June 30, 2015:



Period	Type of Contract	Volumes (in Bbls/d)	Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
July - December 2015	Costless Collars	16,200		$50.00	$67.34
January - December 2016	Costless Collars	5,490		$50.96	$74.73

The following sets forth a summary of our natural gas derivative positions at average NYMEX prices as of June 30, 2015:



Period	Type of Contract	Volumes (in MMBtu/d)	Weighted Average Floor Price ($/MMBtu)
July - December 2015	Fixed Price Swaps	30,000		$4.29

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Forward-Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, including our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, timing and amounts of production, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, capital expenditure plans, planned evaluation of prospects, probability of prospects having oil and gas, expected production or reserves, pipeline connections, increases in reserves, acreage, working capital requirements, commodity price risk management activities and the impact on our average realized prices, the availability of expected sources of liquidity to implement the Company’s business strategies, future borrowing base matters, accessibility of borrowings under our revolving credit facility, debt repayments, redemptions or tender offers, future exploration activity, drilling, completion and fracturing of wells, land acquisitions, production rates, forecasted production, growth in production, development of new drilling programs, participation of our industry partners, exploration and development expenditures, the impact of our business strategies, the benefits, results, effects, availability of and results of new and existing joint ventures and sales transactions, receipt of receivables, proceeds from sales, use of proceeds and all and any other statements regarding future operations, financial results, business plans and cash needs and other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “plan,” “believe” and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in crude oil and natural gas prices, the need to replace reserves depleted by production, operating risks of crude oil and natural 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, actions and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, borrowing base determinations and availability under our revolving credit facility, evaluations of the Company by lenders under our revolving credit facility the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information, property acquisition risks, availability of equipment, actions by our midstream and other industry partners, weather, availability of financing, market conditions, actions by lenders, our ability to obtain permits and licenses, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability of and completion of land acquisitions, completion and connection of wells, and other factors detailed in the “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the year ended December 31, 2014 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 forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to certain market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2014. Other than the offsetting derivative transactions described in “Note 10. Derivative Instruments” and “—Volatility of Crude Oil and Natural Gas Prices” in this Form 10-Q, there have been no material changes from the disclosure made in our Annual Report on Form 10-K for the year ended December 31, 2014 regarding our exposure to certain market risks.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of June 30, 2015 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

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provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended June 30, 2015 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

Item 1A. Risk Factors

There were no material changes to the factors discussed in “Part I. Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014.

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

Exercise of Warrants to Purchase Common Stock under the Land Agreement. On November 24, 2009, the Company entered into an agreement with an unrelated third party and its affiliate, under which the Company issued 118,200 warrants to purchase shares of common stock. In May 2015, the holders of the warrants exercised all warrants outstanding on a “cashless” basis at an exercise price of $22.09 resulting in the issuance on May 4, 2015 of 71,913 net shares of the Company’s common stock. Such shares of common stock were issued pursuant to an exemption from registration under §3(a)(9) of the Securities Act of 1933, as amended.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

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



Exhibit Number		Exhibit Description
4.1	–	Sixteenth Supplemental Indenture dated April 28, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on April 28, 2015 (File No. 000-29187-87)).
4.2	–	Seventeenth Supplemental Indenture dated May 20, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 22, 2015 (File No. 000-29187-87)).
4.3	–	Eighteenth Supplemental Indenture dated May 20, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 22, 2015 (File No. 000-29187-87)).
4.4	–	Nineteenth Supplemental Indenture dated May 20, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on May 22, 2015 (File No. 000-29187-87)).
10.1	–	Sixth Amendment to Credit Agreement, dated as of May 5, 2015, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 (File No. 000-29187-87)).
*31.1	–	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	–	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	–	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	–	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101	–	Interactive Data Files

* Filed herewith.

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Signatures

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



		Carrizo Oil & Gas, Inc. (Registrant)

Date:	August 6, 2015	By:	/s/ David L. Pitts
			Vice President and Chief Financial Officer (Principal Financial Officer)

Date:	August 6, 2015	By:	/s/ Gregory F. Conaway
			Vice President and Chief Accounting Officer (Principal Accounting Officer)

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