Edgar Filing: Rosetta Resources Inc.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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

¨	Transition Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)


Delaware		43-2083519
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Bagby Street, Suite 1600 Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

(713) 335-4000

(Registrant’s telephone number, including area code)

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 (§ 232.405 of this chapter) 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x

The number of shares of the registrant’s Common Stock, $0.001 par value per share, outstanding as of July 10, 2015 was 75,734,762, which excludes unvested restricted stock.

Table of Contents


Part I –	Financial Information
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	24
	Item 4. Controls and Procedures	25
Part II –	Other Information
	Item 1. Legal Proceedings	26
	Item 1A. Risk Factors	26
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	27
	Item 3. Defaults Upon Senior Securities	27
	Item 4. Mine Safety Disclosures	27
	Item 5. Other Information	27
	Item 6. Exhibits	28
Signatures		29

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except par value and share amounts)


	June 30, 2015			December 31, 2014
	Unaudited
Assets
Current assets:
Cash and cash equivalents	$	7,688		$	34,397
Accounts receivable		97,293			117,070
Derivative instruments		139,307			221,250
Prepaid expenses		6,881			8,142
Other current assets		3,992			3,535

Total current assets		255,161			384,394
Oil and natural gas properties using the full cost method of accounting:
Proved properties		5,566,386			5,337,537
Unproved/unevaluated properties, not subject to amortization		517,031			550,979
Gathering systems and compressor stations		281,233			285,989
Other fixed assets		31,904			34,339

		6,396,554			6,208,844
Accumulated depreciation, depletion and amortization, including impairment		(3,660,636	)		(2,434,003	)

Total property and equipment, net		2,735,918			3,774,841
Other assets:
Debt issuance costs		24,604			25,741
Deferred tax asset		46,961			—
Derivative instruments		35,833			65,419
Other long-term assets		68			272

Total other assets		107,466			91,432

Total assets	$	3,098,545		$	4,250,667

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	109,555		$	179,353
Royalties and other payables		78,324			98,972
Deferred income taxes		46,961			72,445

Total current liabilities		234,840			350,770

Long-term liabilities:
Long-term debt		1,800,000			2,000,000
Deferred income taxes		699			207,854
Other long-term liabilities		27,499			22,930

Total liabilities		2,063,038			2,581,554

Commitments and Contingencies (Note 10)
Stockholders’ equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2015 or 2014		—			—
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 76,532,669 shares and 62,306,601 shares at June 30, 2015 and December 31, 2014, respectively		77			62
Additional paid-in capital		1,440,869			1,192,836
Treasury stock, at cost; 801,651 shares and 788,493 shares at June 30, 2015 and December 31, 2014, respectively		(27,702	)		(27,414	)
Accumulated other comprehensive loss		(215	)		(234	)
(Accumulated deficit) retained earnings		(377,522	)		503,863

Total stockholders’ equity		1,035,507			1,669,113

Total liabilities and stockholders’ equity	$	3,098,545		$	4,250,667

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues:
Oil sales	$	83,960		$	162,703		$	146,477		$	294,380
NGL sales		26,717			55,442			52,612			110,737
Natural gas sales		32,235			52,140			69,464			103,519
Derivative instruments		(41,643	)		(49,395	)		5,860			(73,180	)

Total revenues		101,269			220,890			274,413			435,456
Operating costs and expenses:
Lease operating expense		16,498			25,064			38,320			44,585
Treating and transportation		23,042			18,618			47,456			39,295
Taxes, other than income		9,262			12,259			17,941			22,465
Depreciation, depletion and amortization		86,825			90,640			187,582			165,415
Impairment of oil and gas properties		245,205			—			1,043,338			—
Reserve for commercial disputes		—			—			9,200			—
General and administrative costs		28,206			21,667			50,126			41,205

Total operating costs and expenses		409,038			168,248			1,393,963			312,965

Operating (loss) income		(307,769	)		52,642			(1,119,550	)		122,491
Other expense (income):
Interest expense, net of interest capitalized		21,165			17,327			43,213			32,617
Interest income		(1	)		(1	)		(2	)		(13	)
Other (income) expense, net		(362	)		12,496			(547	)		12,647

Total other expense		20,802			29,822			42,664			45,251

(Loss) income before provision for income taxes		(328,571	)		22,820			(1,162,214	)		77,240
Income tax (benefit) expense		13,140			8,376			(280,829	)		27,553

Net (loss) income	$	(341,711	)	$	14,444		$	(881,385	)	$	49,687

(Loss) earnings per share:
Basic	$	(4.52	)	$	0.24		$	(12.62	)	$	0.81

Diluted	$	(4.52	)	$	0.23		$	(12.62	)	$	0.81

Weighted average shares outstanding:
Basic		75,555			61,452			69,850			61,416
Diluted		75,555			61,617			69,850			61,599

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Comprehensive Income

(In thousands)

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
Net (loss) income	$	(341,711	)	$	14,444	$	(881,385	)	$	49,687
Other comprehensive income (loss):
Postretirement medical benefits prior service benefit, net of income taxes of ($4) and ($2) for the three months ended June 30, 2015 and 2014, respectively, and ($9) and ($4) for the six months ended June 30, 2015 and 2014, respectively		9			3		19			6

Other comprehensive income		9			3		19			6

Comprehensive (loss) income	$	(341,702	)	$	14,447	$	(881,366	)	$	49,693

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities:
Net (loss) income	$	(881,385	)	$	49,687
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		187,582			165,415
Impairment of oil and gas properties		1,043,338			—
Deferred income taxes		(280,828	)		26,521
Amortization of deferred loan fees recorded as interest expense		2,141			1,900
Loss on debt extinguishment		—			3,101
Stock-based compensation expense		7,753			7,393
Loss due to change in fair value of derivative instruments		111,529			59,529
Change in operating assets and liabilities:
Accounts receivable		19,777			(14,840	)
Prepaid expenses		1,856			2,578
Other current assets		(457	)		(3,320	)
Long-term assets		204			46
Accounts payable and accrued liabilities		11,948			(15,041	)
Royalties and other payables		(20,648	)		15,901
Other long-term liabilities		(1,154	)		810

Net cash provided by operating activities		201,656			299,680

Cash flows from investing activities:
Acquisitions of oil and gas assets		—			(79,020	)
Additions to oil and gas assets		(271,316	)		(675,835	)
Disposals of oil and gas assets		10,052			8

Net cash used in investing activities		(261,264	)		(754,847	)

Cash flows from financing activities:
Borrowings on Credit Facility		190,000			550,000
Payments on Credit Facility		(390,000	)		(550,000	)
Issuance of Senior Notes		—			500,000
Retirement of Senior Notes		—			(200,000	)
Proceeds from issuance of common stock		234,787			—
Deferred loan fees		(1,600	)		(8,354	)
Proceeds from stock options exercised		—			376
Purchases of treasury stock		(288	)		(2,546	)
Excess tax benefit from share-based awards		—			101

Net cash provided by financing activities		32,899			289,577

Net decrease in cash		(26,709	)		(165,590	)
Cash and cash equivalents, beginning of period		34,397			193,784

Cash and cash equivalents, end of period	$	7,688		$	28,194


Supplemental disclosures:
Capital expenditures included in Accounts payable and accrued liabilities	$	48,050		$	195,400
Operating liabilities settled in stock	$	6,419		$	—

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands, except share amounts)

(Unaudited)


	Common Stock				Additional Paid-In Capital			Treasury Stock					Accumulated Other Comprehensive Loss			Retained Earnings / Accumulated Deficit			Total Stockholders’ Equity
	Shares		Amount		Additional Paid-In Capital			Shares		Amount			Accumulated Other Comprehensive Loss			Retained Earnings / Accumulated Deficit			Total Stockholders’ Equity
Balance at December 31, 2014		62,306,601	$	62	$	1,192,836			788,493	$	(27,414	)	$	(234	)	$	503,863		$	1,669,113
Issuance of common stock		13,800,000		14		234,774			—		—			—			—			234,788
Treasury stock - employee tax payment		—		—		—			13,158		(288	)		—			—			(288	)
Tax impact of stock awards		—		—		(1,219	)		—		—			—			—			(1,219	)
Stock-based compensation		—		—		8,059			—		—			—			—			8,059
Vesting of restricted stock		170,487		—		—			—		—			—			—			—
Operating liabilities settled in stock		255,581		1		6,419			—		—			—			—			6,420
Comprehensive income (loss)		—		—		—			—		—			19			(881,385	)		(881,366	)

Balance at June 30, 2015		76,532,669	$	77	$	1,440,869			801,651	$	(27,702	)	$	(215	)	$	(377,522	)	$	1,035,507

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Notes to Consolidated Financial Statements (unaudited)

(1) Organization and Operations of the Company

Nature of Operations. Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company” or “Rosetta”) is an independent exploration and production company engaged in the acquisition and development of onshore energy resources in the United States of America. The Company’s operations are located in the Eagle Ford shale in South Texas and the Permian Basin in West Texas.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of normal recurring adjustments necessary to fairly state the financial statements, have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). These financial statements and notes should be read in conjunction with the Company’s audited Consolidated Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”).

(2) Definitive Merger Agreement

On May 10, 2015, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Noble Energy, a Delaware corporation (“Noble”), and Bluebonnet Merger Sub Inc., a Delaware corporation and an indirect, wholly owned subsidiary of Noble (“Merger Sub”), pursuant to which Noble will acquire Rosetta in exchange for shares of common stock, par value $0.01 per share, of Noble. Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will be merged with and into Rosetta (the “merger”), with Rosetta continuing as the surviving corporation in the merger and an indirect, wholly owned subsidiary of Noble. After completion of the merger, Rosetta will merge with and into its parent, NBL Texas, LLC, a Delaware limited liability company, with NBL Texas, LLC continuing as the surviving entity and an indirect, wholly owned subsidiary of Noble, in a transaction which is referred to as the second merger.

Under the terms of the Merger Agreement, at the effective time of the merger, each issued and outstanding share of common stock, par value $0.001 per share, of Rosetta will be converted into the right to receive 0.542 (the “Exchange Ratio”) Noble common shares. Following the approval by Rosetta’s stockholders, the merger is expected to close July 20, 2015.

(3) Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2014 Annual Report. There have been no changes to the Company’s significant accounting policies since December 31, 2014.

Recent Accounting Developments

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-01, Income Statement - Extraordinary and Unusual Items. The ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed, and the pronouncement is effective for interim and annual reporting periods beginning after December 15, 2015. This guidance is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

In April 2015, the FASB issued ASU No. 2015-03, Interest-Imputation of Interest. The ASU simplifies the presentation of debt issuance costs and improves consistency with International Financial Reporting Standards (“IFRS”). Under existing guidance, debt issuance costs are recognized as a deferred asset. However, this ASU will require that debt issuance costs be presented as a direct deduction from the carrying amount of the debt instrument. The pronouncement is effective for interim and annual reporting periods beginning after December 15, 2015. This guidance will require presentation adjustments to the face of the Company’s Consolidated Balance Sheet, including historical periods, and will require additional disclosure. However, this pronouncement is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

(4) Property and Equipment

The Company’s total property and equipment consists of the following:


	June 30, 2015			December 31, 2014
	(In thousands)
Proved properties	$	5,566,386		$	5,337,537
Unproved/unevaluated properties		517,031			550,979
Gathering systems and compressor stations		281,233			285,989
Other fixed assets		31,904			34,339

Total		6,396,554			6,208,844
Less: Accumulated depreciation, depletion and amortization, including impairment		(3,660,636	)		(2,434,003	)

Total property and equipment, net	$	2,735,918		$	3,774,841

Acquisitions

2014 Permian Acquisition. On December 30, 2013, the Company entered into a definitive agreement with several private parties to acquire Delaware Basin assets covering 5,034 net acres located in Reeves County (the “2014 Permian Acquisition”). These assets include 13 gross producing wells, of which 11 are operated by the Company. The Company completed the 2014 Permian Acquisition on February 28, 2014, with an effective date of December 1, 2013, for total cash consideration of $83.8 million.

Additional Disclosures about Property and Equipment

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $2.2 million and $2.1 million of internal costs for the three months ended June 30, 2015 and 2014, respectively, and $4.3 million and $3.7 million for the six months ended June 30, 2015 and 2014, respectively.

Oil and gas properties include unevaluated property costs of $517.0 million and $551.0 million as of June 30, 2015 and December 31, 2014, respectively, which are not being amortized. These amounts primarily represent acquisition costs of unproved properties and unevaluated exploration projects in which the Company owns a direct interest. Such costs are periodically evaluated for impairment, and upon evaluation or impairment are transferred to the Company’s full cost pool and amortized.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate cost center. All of the Company’s costs are included in one cost center because all of the Company’s operations are located in the United States. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of June 30, 2015, which were based on a West Texas Intermediate oil price of $68.17 per Bbl and a Henry Hub natural gas price of $3.39 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of June 30, 2015, and as a result, a pre-tax write-down of $245.2 million was recorded for the three months ended June 30, 2015. For the six months ended June 30, 2015, the Company has recorded a pre-tax write-down of $1.0 billion. Additional material write-downs of the Company’s oil and gas properties will occur in subsequent quarters in the event that oil and natural gas prices remain at current depressed levels, or if the Company experiences significant downward adjustments to its estimated proved reserves.

(5) Commodity Derivative Contracts

The Company is exposed to various market risks, including volatility in oil, natural gas liquids (“NGL”) and natural gas prices, which are managed through derivative instruments. The level of derivative activity utilized depends on market conditions, operating strategies and available derivative prices. The Company utilizes various types of derivative instruments to manage commodity price risk, including fixed price swaps, basis swaps and costless collars. Forward contracts on various commodities are entered into to manage the price risk associated with forecasted sales of the Company’s oil, NGL and natural gas production.

As of June 30, 2015, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:


Product	Settlement Period	Derivative Instrument	Notional Daily Volume (Bbls)		Total Notional Volume (Bbls)		Average Floor/Fixed Prices per Bbl		Average Ceiling Prices per Bbl
Crude oil	2015	Costless Collar		8,000		1,472,000	$	55.00	$	84.80
Crude oil	2015	Swap		12,000		2,208,000		89.81
Crude oil	2016	Swap		6,000		2,196,000		90.28

						5,876,000


Product	Settlement Period	Derivative Instrument	Notional Daily Volume (Bbls)		Total Notional Volume (Bbls)		Average Fixed Prices per Bbl
NGL-Ethane	2015	Swap		3,476		639,619	$	11.31
NGL-Propane	2015	Swap		1,750		322,000		43.35
NGL-Isobutane	2015	Swap		617		113,467		53.05
NGL-Normal Butane	2015	Swap		579		106,457		52.53
NGL-Pentanes Plus	2015	Swap		579		106,457		77.72

						1,288,000


Product	Settlement Period	Derivative Instrument	Notional Daily Volume (MMBtu)		Total Notional Volume (MMBtu)		Average Floor/Fixed Prices per MMBtu		Average Ceiling Prices per MMBtu
Natural gas	2015	Costless Collar		50,000		9,200,000	$	3.60	$	5.04
Natural gas	2016	Costless Collar		40,000		14,640,000		3.50		5.58
Natural gas	2015	Swap		50,000		9,200,000		4.13
Natural gas	2016	Swap		30,000		10,980,000		4.04

						44,020,000

As of June 30, 2015, the Company’s derivative instruments were with counterparties who are lenders under its Credit Facility. This practice allows the Company to satisfy any need for margin obligations resulting from an adverse change in the fair market value of its derivative contracts with the collateral securing its Credit Facility, thus eliminating the need for independent collateral postings. The Company’s ability to continue satisfying any applicable margin requirements in this manner may be subject to change as described in Items 1 and 2. Business and Properties – Government Regulation in the Company’s 2014 Annual Report. As of June 30, 2015, the Company had no deposits for collateral regarding commodity derivative positions.

Additional Disclosures about Derivative Instruments

Authoritative derivative guidance requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the Company’s financial statements. The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of June 30, 2015 and December 31, 2014, respectively:


		Asset (Liability) Fair Value
		June 30, 2015		December 31, 2014
Commodity derivative contracts	Location on Consolidated Balance Sheet	(In thousands)
Oil	Derivative instruments - current assets	$	93,541	$	151,363
Oil	Derivative instruments - non-current assets		27,788		54,187
NGL	Derivative instruments - current assets		17,598		35,992
Natural gas	Derivative instruments - current assets		28,168		33,895
Natural gas	Derivative instruments - non-current assets		8,045		11,232

Total derivative fair value, net, not designated as hedging instruments		$	175,140	$	286,669

The following table sets forth the type and amount of derivative gains and losses included in Derivative instruments in the Consolidated Statement of Operations for the three and six months ended June 30, 2015 and 2014, respectively:


		Three Months Ended June 30,						Six Months Ended June 30,
Location on Consolidated Statement of Operations	Description of Gain (Loss)	2015			2014			2015			2014
Location on Consolidated Statement of Operations	Description of Gain (Loss)	(In thousands)
Derivative instruments	Realized gain (loss) recognized in income	$	55,186		$	(5,714	)	$	117,389		$	(13,651	)
Derivative instruments	Unrealized loss recognized in income		(96,829	)		(43,681	)		(111,529	)		(59,529	)

	Total commodity derivative gain (loss) recognized in income	$	(41,643	)	$	(49,395	)	$	5,860		$	(73,180	)

(6) Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company measures its non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis.

As defined in the guidance of the FASB, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The FASB’s guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:

•

“Level 1” inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

•

“Level 2” inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

•

“Level 3” inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires

judgment and may affect the valuation of fair value assets and liabilities along with their placement within the fair value hierarchy levels. The Company determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis for the respective period:


	Fair value as of June 30, 2015
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Commodity derivative contracts	$	—	$	—	$	175,773		$	(633	)	$	175,140
Liabilities:
Commodity derivative contracts		—		—		(633	)		633			—

Total fair value	$	—	$	—	$	175,140		$	—		$	175,140


	Fair value as of December 31, 2014
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Commodity derivative contracts	$	—	$	—	$	289,878		$	(3,209	)	$	286,669
Liabilities:
Commodity derivative contracts		—		—		(3,209	)		3,209			—

Total fair value	$	—	$	—	$	286,669		$	—		$	286,669

(1)

Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. No margin or collateral balances are deposited with counterparties and as such, gross amounts are offset to determine the net amounts presented in the Consolidated Balance Sheet.

The Company’s Level 3 instruments include commodity derivative contracts for which fair value is determined by a third-party provider. Although the Company compares the fair values derived from the third-party provider with its counterparties, the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments and does not have access to the specific valuation models or certain inputs used by its third-party provider or counterparties. Therefore, these commodity derivative contracts are classified as Level 3 instruments.

The following table presents a range of the unobservable inputs provided by the Company’s third-party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of June 30, 2015 (in thousands):


Level 3 Instrument	Asset (Liability)		Valuation Technique	Unobservable Input	Range					Weighted Average
Level 3 Instrument	Asset (Liability)		Valuation Technique	Unobservable Input	Minimum			Maximum		Weighted Average
Oil swaps	$	120,220	Discounted cash flow	Forward price curve-swaps	$	59.60		$	65.58	$	62.58
Oil costless collars		1,109	Option model	Forward price curve-costless collar option value		(0.35	)		2.11		0.75
NGL swaps		17,598	Discounted cash flow	Forward price curve-swaps		0.20			1.24		0.43
Natural gas swaps		21,152	Discounted cash flow	Forward price curve-swaps		(0.08	)		3.41		3.04
Natural gas costless collars		15,061	Option model	Forward price curve-costless collar option value		(0.06	)		1.04		0.63

Total	$	175,140

The determination of derivative fair values by the third-party provider incorporates a credit adjustment for nonperformance risk, including the credit standing of the counterparties involved, and the impact of the Company’s nonperformance risk on its liabilities. The Company recorded a downward adjustment to the fair value of its derivative instruments in the amount of $0.3 million as of June 30, 2015 due to nonperformance risk.

The significant unobservable inputs for Level 3 derivative contracts include forward price curves and option values. Significant increases (decreases) in the quoted forward prices for commodities and option values generally lead to corresponding decreases (increases) in the fair value measurement of the Company’s oil, NGL and natural gas derivative contracts.

The tables below present reconciliations of financial assets and liabilities classified as Level 3 in the fair value hierarchy during the indicated periods.


	Derivative Asset (Liability)
	(In thousands)
Balance at January 1, 2015	$	286,669
Total Gains (Realized or Unrealized):
Included in Earnings		5,860
Purchases, Issuances and Settlements:
Settlements		(117,389	)
Transfers in and out of Level 3		—

Balance at June 30, 2015	$	175,140


	Derivative Asset (Liability)
	(In thousands)
Balance at January 1, 2014	$	4,419
Total Losses (Realized or Unrealized):
Included in Earnings		(73,180	)
Purchases, Issuances and Settlements:
Settlements		13,651
Transfers in and out of Level 3		—

Balance at June 30, 2014	$	(55,110	)

Fair Value of Other Financial Instruments

All of the Company’s other financial instruments (excluding derivatives) are presented on the balance sheet at carrying value. As of June 30, 2015, the carrying value of cash and cash equivalents, other current assets and current liabilities reported in the Consolidated Balance Sheet approximate fair value because of their short-term nature, and all such financial instruments are considered Level 1 instruments.

The Company’s debt consists of publicly traded Senior Notes (defined below) and borrowings under the Credit Facility (defined below). The fair values of the Company’s Senior Notes are based upon unadjusted quoted market prices and are considered Level 1 instruments. The Company’s borrowings under the Credit Facility approximate fair value as the interest rates are variable and reflective of current market rates, and are therefore considered a Level 1 instrument. As of June 30, 2015, the carrying amount of total debt was $1.80 billion and the estimated fair value of total debt was $1.93 billion.

(7) Asset Retirement Obligations

The following table provides a rollforward of the Company’s asset retirement obligations (“ARO”). Liabilities incurred during the period include additions to obligations and obligations incurred from acquisitions. Liabilities settled during the period include settlement payments for obligations. Activity related to the Company’s ARO is as follows:


	Six Months Ended June 30, 2015
	(In thousands)
ARO as of December 31, 2014	$	19,957
Liabilities incurred during period		67
Liabilities settled during period		(554	)
Accretion expense		646

ARO as of June 30, 2015	$	20,116

As of June 30, 2015, the $0.2 million current portion of the total ARO is included in Accrued liabilities, and the $19.9 million long-term portion of ARO is included in Other long-term liabilities on the Consolidated Balance Sheet.

(8) Debt and Credit Agreements

Senior Secured Revolving Credit Facility. As of June 30, 2015, the Company had no borrowings outstanding with $800.0 million of available borrowing capacity under its Credit Facility. Amounts outstanding under the Credit Facility bear interest at

specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.50% to 2.50% and mature in April 2018. Additionally, the Company can borrow under the Credit Facility at the Alternative Base Rate (“ABR”), which is based upon the Prime Rate in effect on such day plus a margin of 0.5% to 1.5% depending on the Company’s utilization percentage. The weighted average borrowing rate under the Credit Facility for the three and six months ended June 30, 2015 was 3.09% and 2.05%, respectively, exclusive of commitment fees. For the three and six months ended June 30, 2015, interest expense was $0.1 million and $1.2 million, respectively, and commitment fees were $0.8 million and $1.3 million, respectively, under the Credit Facility. Borrowings under the Credit Facility are collateralized by liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 proved reserve value, a guaranty by all of the Company’s domestic subsidiaries and a pledge of 100% of the membership and limited partnership interests of the Company’s domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is also subject to certain financial covenants, including the requirement to maintain a current ratio of consolidated current assets, including the unused amount of available borrowing capacity, to consolidated current liabilities, excluding certain non-cash obligations, of not less than 1.0 to 1.0 as of the end of each fiscal quarter. The terms of the credit agreement also require the maintenance of a senior secured leverage ratio of secured debt to EBITDA, of not greater than 2.5 to 1.0, and an interest coverage ratio of EBITDA to gross interest, of not less than 2.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. As of June 30, 2015, the Company’s current ratio was 3.9, senior secured leverage ratio was 0.0 and interest coverage ratio was 5.4. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties.

9.500% Senior Notes due 2018. In accordance with the provisions of the indenture governing the Company’s 9.500% Senior Notes due 2018, on May 5, 2014, the Company redeemed all of the outstanding notes in full at a price of 104.75% of the principal amount, plus accrued and unpaid interest. The Company paid an aggregate amount of $210.6 million for such redemption, consisting of a call premium of $9.5 million and $1.1 million of accrued and unpaid interest.

5.625% Senior Notes due 2021. On May 2, 2013, the Company completed its public offering of $700.0 million in aggregate principal amount of 5.625% Senior Notes due 2021 (the “5.625% Senior Notes”). Interest is payable on the 5.625% Senior Notes semi-annually on May 1 and November 1. The 5.625% Senior Notes were issued under an indenture (the “Base Indenture”), as supplemented by a first supplemental indenture (as so supplemented, the “First Supplemental Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the First Supplemental Indenture limit the Company’s ability to, among other things, incur additional indebtedness; pay dividends on capital stock or purchase, repurchase, redeem, defease or retire capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The First Supplemental Indenture also contains customary events of default.

5.875% Senior Notes due 2022. On November 15, 2013, the Company completed its public offering of $600.0 million in aggregate principal amount of 5.875% Senior Notes due 2022 (the “5.875% Senior Notes due 2022”). Interest is payable on the 5.875% Senior Notes due 2022 semi-annually on June 1 and December 1. The 5.875% Senior Notes due 2022 were issued under the Base Indenture, as supplemented by a second supplemental indenture (as so supplemented, the “Second Supplemental Indenture”) with Wells Fargo Bank, National Association, as trustee, which contains covenants and events of default substantially similar to those in the First Supplemental Indenture.

5.875% Senior Notes due 2024. On May 29, 2014, the Company completed its public offering of $500.0 million in aggregate principal amount of 5.875% Senior Notes due 2024 (the “5.875% Senior Notes due 2024” and, together with the 5.625% Senior Notes and the 5.875% Senior Notes due 2022, the “Senior Notes”). Interest is payable on the 5.875% Senior Notes due 2024 semi-annually on June 1 and December 1. The 5.875% Senior Notes due 2024 were issued under the Base Indenture, as supplemented by a third supplemental indenture (as so supplemented, together with the Base Indenture, the First Supplemental Indenture and the Second Supplemental Indenture, the “Rosetta Indentures”) with Wells Fargo Bank, National Association, as trustee, which contains covenants and events of default substantially similar to those in the First Supplemental Indenture.

Debt Exchange in Connection with the Merger. On June 29, 2015 and in connection with the merger, Noble launched a debt offering where following the merger and pursuant to the Rosetta Indentures, Noble will expressly assume, by a fourth supplemental indenture to the Base Indenture, all of the obligations of the Company under the Rosetta Indentures and the Senior Notes. The consummation of the exchange offers is subject to, and conditioned upon, among other things, the consummation of the merger. There are no financing conditions to the merger, and the merger is not conditioned upon the completion of the exchange offers or other transactions with respect to the Senior Notes.

Total Indebtedness. As of June 30, 2015, the Company had total indebtedness of $1.80 billion, and for the six months ended June 30, 2015, the Company’s weighted average borrowing rate was 5.73%, inclusive of interest and commitment fees.

(9) Income Taxes

The Company’s effective tax rate for the three and six months ended June 30, 2015 was (4.0%) and 24.1%, respectively, and the effective tax rate for the three and six months ended June 30, 2014 was 36.7% and 35.7%, respectively. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes, the non-deductibility of certain incentive compensation and the impact of valuation allowances. As of June 30, 2015 and December 31, 2014, the Company had no unrecognized tax benefits. The Company does not anticipate that the balance of unrecognized tax benefits will significantly change within the next twelve months due to the settlement of audits or expiration of statutes of limitations.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management assessed the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. As a result of the material write-downs of the Company’s carrying value of oil and natural gas properties, the Company’s operating results for the six months June 30, 2015, and considering forecasted operating results, the Company believes it is more likely than not that the deferred tax assets will not be realized and has recorded a valuation allowance against the federal net deferred tax asset.

(10) Commitments and Contingencies

Firm Oil and Natural Gas Transportation and Processing Commitments. The Company has commitments for the transportation and processing of its production in the Eagle Ford area, including an aggregate minimum commitment to deliver 8.2 MMBbls of oil by the end of 2017 and 561 million MMBtus of natural gas by mid-year 2028. The Company is required to make periodic deficiency payments for any shortfalls in delivering the minimum volumes under these commitments. Currently, the Company has insufficient production to meet all of these contractual commitments. However, as the Company develops additional reserves in the Eagle Ford area, it anticipates exceeding its current minimum volume commitments and therefore intends to enter into additional transportation and processing commitments in the future. These future transportation and processing commitments may expose the Company to additional volume deficiency payments. As of June 30, 2015, the Company has accrued deficiency fees of $9.2 million and expects to continue to accrue deficiency fees under its commitments. Future obligations under firm oil and natural gas transportation and processing agreements as of June 30, 2015 are as follows:


	June 30, 2015
	(In thousands)
2015	$	15,250
2016		31,739
2017		31,289
2018		18,159
2019		15,900
Thereafter		86,507

Total future obligations	$	198,844

Drilling Rig and Completion Services Commitments. Drilling rig and completion services commitments represent obligations with certain contractors to execute the Company’s Eagle Ford and Permian Basin drilling programs. As of June 30, 2015, the Company had no outstanding drilling rig commitments with a term greater than one year, and the minimum contractual commitments due in the next twelve months are $2.8 million. For the three and six months ended June 30, 2015, the Company recorded approximately $6.7 million and $21.8 million, respectively, in rig termination fees. As of June 30, 2015, the Company’s minimum contractual commitments due in the next twelve months for other field services were $5.1 million. Payments under these commitments are accounted for as capital additions to oil and gas properties.

Contingencies. The Company is party to various legal and regulatory proceedings and commercial disputes arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability the Company may ultimately incur with respect to any such proceeding may be in excess of amounts currently accrued, if any. After considering the Company’s available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, the Company does not believe any such matter will have a material adverse effect on its financial position, results of operations or cash flows.

Commercial Disputes. During the first quarter of 2015, the Company recorded a reserve of $9.2 million related to a commercial dispute concerning the calculation of royalty amounts earned and royalty deductions taken over specified periods in 2009 through 2013. The dispute arose in the third quarter of 2014 and the Company has been in ongoing discussions with those royalty holders

regarding their royalty claim. The Company’s total recorded reserve of $15.0 million represents its expected loss exposure associated with this dispute, and the final resolution of this matter is expected to occur in the third quarter of 2015. The reserve for this contingency is reported in Reserve for commercial disputes in the Consolidated Statement of Operations and is included in Accounts payable and accrued liabilities in the Consolidated Balance Sheet.

(11) Equity

Earnings per Share. Basic earnings per share (“EPS”) is calculated by dividing income (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock awards) outstanding during the period (the denominator). Diluted EPS incorporates the dilutive impact of outstanding stock options and unvested restricted stock awards using the treasury stock method.

The following is a calculation of basic and diluted weighted average shares outstanding:


	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(In thousands)
Basic weighted average number of shares outstanding		75,555		61,452		69,850		61,416
Dilution effect of stock options and restricted shares at the end of the period (1)		—		165		—		183

Diluted weighted average number of shares outstanding		75,555		61,617		69,850		61,599

Anti-dilutive stock awards and shares		238		—		199		5

(1)	Because the Company recognized a net loss for the three and six months ended June 30, 2015, no unvested stock awards and options were included in computing earnings per share because the effect was anti-dilutive.

Common Stock Offering. On March 13, 2015, the Company completed its public offering of 12,000,000 shares of common stock at a price to the public of $17.20 per share ($17.04 per share, net of underwriting discount) for net proceeds of approximately $204.5 million. The Company also received net proceeds of approximately $30.7 million in connection with the underwriters’ full exercise of their over-allotment option to purchase an additional 1,800,000 shares of common stock, which closed on April 8, 2015.

(12) Stock-Based Compensation and Employee Benefits

Stock-based compensation expense includes the expense associated with restricted stock granted to employees and directors and the expense associated with the Performance Share Units (“PSUs”) granted to management. As of the indicated dates, stock-based compensation expense consisted of the following:


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Total stock-based compensation expense	$	4,956		$	4,158		$	8,059		$	7,639
Capitalized in oil and gas properties		(153	)		(123	)		(306	)		(246	)

Net stock-based compensation expense	$	4,803		$	4,035		$	7,753		$	7,393

All stock-based compensation expense associated with restricted stock granted to employees and directors is recognized on a straight-line basis over the applicable remaining vesting period. For the three and six months ended June 30, 2015, the Company recorded stock-based compensation expense of approximately $3.3 million and $6.3 million, respectively, related to these equity awards. As of June 30, 2015, unrecognized stock-based compensation expense related to unvested restricted stock was approximately $19.0 million.

Stock-based compensation expense associated with the PSUs granted to management is recognized over a three-year performance period. For the three and six months ended June 30, 2015, the Company recognized compensation expense of $1.6 million and $1.8 million, respectively, associated with the PSUs. At the current fair value as of June 30, 2015, and assuming the Board elects the maximum available payout of 200% for all PSU metrics, unrecognized stock-based compensation expense related to the PSUs was approximately $16.9 million. The Company’s total stock-based compensation expense will be measured and adjusted quarterly until settlement occurs, based on the Company’s performance, expected payout and quarter-end closing common stock prices. For a more detailed description of the Company’s PSU plans, including related performance conditions and structure, see the definitive proxy statement filed with respect to the Company’s 2015 annual meeting under the heading “Compensation Discussion and Analysis” and the Company’s 2014 Annual Report.

Postretirement Health Care. The Company has a postretirement medical benefit plan covering eligible employees and their eligible dependents. The Company recognizes periodic postretirement benefits costs as a component of General and administrative costs. For the three and six months ended June 30, 2015 and 2014, this expense was immaterial.

(13) Guarantor Subsidiaries

The Company’s Senior Notes are guaranteed by its wholly owned subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiaries by dividend or loan. Finally, none of the Company’s subsidiaries has restricted assets that exceed 25% of net assets as of the most recent fiscal year which may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding the Company within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “forecast,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology. Unless the context clearly indicates otherwise, references in this report to “Rosetta,” “the Company,” “we,” “our,” “us” or like terms refer to Rosetta Resources Inc. and its subsidiaries.

The forward-looking statements contained in this report reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Annual Report”). We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

•

our ability to maintain leasehold positions that require exploration and development activities and material capital expenditures;

•

unexpected difficulties in integrating our operations as a result of any significant acquisitions;

•

the supply and demand for oil, NGLs and natural gas;

•

changes in the price of oil, NGLs and natural gas;

•

general economic conditions, either internationally, nationally or in jurisdictions where we conduct business;

•

conditions in the energy and financial markets;

•

our ability to obtain credit and/or capital in desired amounts and/or on favorable terms;

•

the ability and willingness of our current or potential counterparties or vendors to enter into transactions with us and/or to fulfill their obligations to us;

•

failure of our joint interest partners to fund any or all of their portion of any capital program and/or lease operating expenses;

•

failure of joint interest partners to pay us our share of revenue;

•

the occurrence of property acquisitions or divestitures;

•

reserve levels;

•

inflation or deflation;

•

competition in the oil and natural gas industry;

•

the availability and cost of relevant raw materials, equipment, goods, services and personnel;

•

changes or advances in technology;

•

potential reserve revisions;

•

the availability and cost, as well as limitations and constraints on infrastructure required, to gather, transport, process and market oil, NGLs and natural gas;

•

performance of contracted markets and companies contracted to provide transportation, processing and trucking of oil, NGLs and natural gas;

•

developments in oil-producing and natural gas-producing countries;

•

drilling, completion, production and facility risks;

•

exploration risks;

•

legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to, changes in national healthcare, cap and trade, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, environmental regulations and environmental risks and liability under federal, state and local environmental laws and regulations;

•

effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;

•

present and possible future claims, litigation and enforcement actions;

•

lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;

•

the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

•

factors that could impact the cost, extent and pace of executing our capital program, including but not limited to, access to oilfield services, access to water for hydraulic fracture stimulations and permitting delays, unavailability of required permits, lease suspensions, drilling, exploration and production moratoriums and other legislative, executive or judicial actions by federal, state and local authorities, as well as actions by private citizens, environmental groups or other interested persons;

•

sabotage, terrorism and border issues, including encounters with illegal aliens and drug smugglers;

•

electronic, cyber or physical security breaches; and

•

any other factors that impact or could impact the exploration and development of oil, NGLs or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil, NGLs and natural gas.

Overview

The following discussion addresses material changes in our results of operations for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 and material changes in our financial condition since December 31, 2014. This discussion should be read in conjunction with our 2014 Annual Report, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Results for the three months ended June 30, 2015 include the following:

•

production of 63.0 MBoe per day compared to 61.5 MBoe per day for the three months ended June 30, 2014;

•

no operated wells drilled compared to 34 gross (32.7 net) operated wells drilled for the three months ended June 30, 2014; and

•

net loss of $341.7 million, or ($4.52) per diluted share, compared to net income of $14.4 million, or $0.23 per diluted share, for the three months ended June 30, 2014.

Results for the six months ended June 30, 2015 include the following:

•

production of 64.4 MBoe per day compared to 57.9 MBoe per day for the six months ended June 30, 2014;

•

9 gross (7.4 net) operated wells drilled compared to 81 gross (79.2 net) operated wells drilled for the six months ended June 30, 2014; and

•

net loss of $881.4 million, or ($12.62) per diluted share, compared to net income of $49.7 million, or $0.81 per diluted share, for the six months ended June 30, 2014.

Our principal operating and business strategy is focused on the acquisition, development and production of oil, NGLs and natural gas from unconventional resource plays. Our operations are primarily located in the Eagle Ford area in South Texas and in the Delaware Basin in West Texas, two of the most active unconventional resource plays in the United States.

Rosetta is a significant producer in the liquids-rich window of the Eagle Ford region, and we have established an inventory of drilling opportunities that offer predictable, long-term production, attractive returns, reserve growth and a balanced commodity mix. Our Permian Basin assets and bolt-on activity further expand our portfolio of long-lived, oil-rich resource projects that we believe will drive our long-term growth and sustainability. We continually monitor market conditions in our cyclical industry and adjust our investment decisions accordingly.

Our development operations in the Eagle Ford shale are focused in several areas. In 2015, we have been active in the 26,230-acre Gates Ranch leasehold in Webb County where we drilled our original discovery in 2009. We have also been active in the Lasseter and Eppright leases in Central Dimmit County, and in the Tom Hanks lease in northern LaSalle County. Our Briscoe Ranch lease in Dimmit County is held by production, which provides flexibility on timing of our ongoing lower and upper Eagle Ford development activity in that area. As of June 30, 2015, we hold approximately 50,000 acres located in the liquids-producing portions of the play. Our delineation operations in the Permian are focused in Reeves County in the Delaware Basin where we are testing benches in the Wolfcamp and 3rd Bone Spring. Currently, we hold approximately 45,000 net acres in the Delaware Basin and approximately 9,000 net exploratory acres in the Midland Basin.

Proposed Merger with Noble Energy

On May 10, 2015, Rosetta and Noble entered into the Merger Agreement pursuant to which each share of common stock will be converted into the right to receive 0.542 shares of Noble common stock. The Merger Agreement was unanimously approved by Rosetta’s board of directors and by Noble’s board of directors. Completion of the merger is subject to the terms and conditions set forth in the Merger Agreement and customary closing conditions. Following the approval by Rosetta’s stockholders, the merger is expected to close July 20, 2015.

Results of Operations

Revenues

Our consolidated financial statements for the three months ended June 30, 2015 reflect total revenues of $101.3 million (including derivative losses of $41.6 million) based on total volumes of 63.0 MBoe per day. Our consolidated financial statements for the six months ended June 30, 2015 reflect total revenues of $274.4 million (including derivative gains of $5.9 million) based on total volumes of 64.4 MBoe per day.

The following table summarizes the components of our revenues for the periods indicated, as well as each period’s production volumes and average realized prices:


	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			% Change Increase/ (Decrease)			2015		2014			% Change Increase/ (Decrease)
Revenues (in thousands):
Oil sales	$	83,960		$	162,703			(48	%)	$	146,477	$	294,380			(50	%)
NGL sales		26,717			55,442			(52	%)		52,612		110,737			(52	%)
Natural gas sales		32,235			52,140			(38	%)		69,464		103,519			(33	%)
Derivative instruments		(41,643	)		(49,395	)		16	%		5,860		(73,180	)		108	%

Total revenues	$	101,269		$	220,890			(54	%)	$	274,413	$	435,456			(37	%)

Production:
Oil (MBbls)		1,654			1,731			(4	%)		3,303		3,184			4	%
NGLs (MBbls)		1,977			1,931			2	%		3,982		3,601			11	%
Natural gas (MMcf)		12,615			11,583			9	%		26,193		22,165			18	%
Total equivalents (MBoe)		5,734			5,593			3	%		11,651		10,479			11	%
Daily Production:
Oil (MBbls per day)		18.2			19.0			(4	%)		18.2		17.6			3	%
NGLs (MBbls per day)		21.7			21.2			2	%		22.0		19.9			11	%
Natural gas (MMcf per day)		138.6			127.3			9	%		144.7		122.5			18	%
Total equivalents (MBoe per day)		63.0			61.5			2	%		64.4		57.9			11	%
Average sales price:
Oil, excluding derivatives (per Bbl)	$	50.76		$	93.99			(46	%)	$	44.35	$	92.46			(52	%)
Oil, including realized derivatives (per Bbl)		71.50			90.88			(21	%)		68.20		89.84			(24	%)
NGL, excluding derivatives (per Bbl)		13.51			28.71			(53	%)		13.21		30.75			(57	%)
NGL, including realized derivatives (per Bbl)		18.24			29.20			(38	%)		17.73		30.21			(41	%)
Natural gas, excluding derivatives (per Mcf)		2.56			4.50			(43	%)		2.65		4.67			(43	%)
Natural gas, including realized derivatives (per Mcf)		3.47			4.39			(21	%)		3.44		4.52			(24	%)
Revenue, excluding derivatives (per Boe)		24.92			48.33			(48	%)		23.05		48.54			(53	%)
Revenue, including realized derivatives (per Boe)		34.55			47.30			(27	%)		33.13		47.24			(30	%)

Oil sales. For the three and six months ended June 30, 2015, oil sales, excluding the effect of derivative instruments, decreased by $78.7 million and $147.9 million, respectively, from the same periods in 2014. For the three months ended June 30, 2015, the lower average sales price for oil resulted in a $71.5 million decrease in oil sales, in addition to a $7.2 million decrease due to the 0.8 MBbls per day decrease in oil production. The decrease in oil production was primarily attributable to a 3.5 MBbls per day decline from the Eagle Ford, partially offset by a 2.7 MBbls per day increase resulting from our growth and development in the Permian Basin. For the six months ended June 30, 2015, the lower average sales price for oil resulted in a $158.9 million decrease in oil sales, partially offset by an $11.0 million increase due to the 0.6 MBbls per day increase in oil production. The increase in oil production was primarily attributable to a 2.5 MBbls per day increase resulting from our growth and development in the Permian Basin, partially offset by a 1.9 MBbls per day decline from the Eagle Ford.

Oil derivative gains and losses are reported as a component of Derivative instruments within Revenues. For the three and six months ended June 30, 2015, realized oil derivative gains were $34.3 million and $78.8 million, respectively, compared to realized oil derivative losses of $5.4 million and $8.3 million for the three and six months ended June 30, 2014, respectively.

NGL sales. For the three and six months ended June 30, 2015, NGL sales, excluding the effect of derivative instruments, decreased by $28.7 million and $58.1 million, respectively, from the same periods in 2014. For the three months ended June 30, 2015, the lower average sales price for NGLs resulted in a $30.0 million decrease in NGL sales, partially offset by a $1.3 million increase due to the 0.5 MBbls per day increase in NGL production. For the six months ended June 30, 2015, the lower average sales price for NGLs resulted in a $69.8 million decrease in NGL sales, partially offset by an $11.7 million increase due to the 2.1 MBbls per day increase in NGL production. The increase in NGL production was attributable to increases of 1.7 MBbls per day in the Eagle Ford and 0.4 MBbls per day in the Permian Basin due to development activities in those areas.

NGL derivative gains and losses are reported as a component of Derivative instruments within Revenues. For the three and six months ended June 30, 2015, realized NGL derivative gains were $9.3 million and $18.0 million, respectively, compared to a realized NGL derivative gain of $1.0 million and loss of $1.9 million for the three and six months ended June 30, 2014, respectively.

Natural gas sales. For the three and six months ended June 30, 2015, natural gas sales, excluding the effect of derivative instruments, decreased by $19.9 million and $34.1 million, respectively, from the same periods in 2014. For the three months ended June 30, 2015, the lower average sales price for natural gas resulted in a $24.5 million decrease in natural gas sales, partially offset by a $4.6 million increase due to the 11.3 MMcf per day increase in natural gas production. The increase in natural gas production was attributable to increases of 4.8 MMcf per day in the Eagle Ford and 6.5 MMcf per day in the Permian Basin due to development activities in those areas. For the six months ended June 30, 2015, the lower average sales price for natural gas resulted in a $52.9 million decrease in natural gas sales, partially offset by an $18.8 million increase due to the 22.2 MMcf per day increase in natural gas production. The increase in natural gas production was attributable to increases of 18.0 MMcf per day in the Eagle Ford and 4.2 MMcf per day in the Permian Basin due to development activities in those areas.

Natural gas derivative gains and losses are reported as a component of Derivative instruments within Revenues. For the three and six months ended June 30, 2015, realized natural gas derivative gains were $11.5 million and $20.6 million, respectively, compared to realized natural gas derivative losses of $1.3 million and $3.4 million, respectively, for the three and six months ended June 30, 2014.

Derivative instruments. For the three and six months ended June 30, 2015, Derivative instruments included (i) realized derivative gains of $55.2 million and $117.4 million, respectively, from cash settlements associated with our commodity derivative contracts, and (ii) unrealized derivative losses of $96.8 million and $111.5 million, respectively, due to changes in the fair value of our commodity derivative contracts.

For the three and six months ended June 30, 2014, Derivative instruments included (i) realized derivative losses of $5.7 million and $13.7 million, respectively, from cash settlements associated with our commodity derivative contracts, and (ii) unrealized derivative losses of $43.7 million and $59.5 million, respectively, due to changes in the fair value of our commodity derivative contracts.

Operating Expenses

The following table summarizes our production costs and operating expenses for the periods indicated:


	Three Months Ended June 30,							Six Months Ended June 30,
	2015		2014		% Change Increase/ (Decrease)			2015		2014		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)							(In thousands, except percentages and per unit amounts)
Direct lease operating expense	$	12,490	$	14,768		(15	%)	$	29,023	$	30,554		(5	%)
Insurance expense		297		312		(5	%)		593		581		2	%
Workover expense		3,711		9,984		(63	%)		8,704		13,450		(35	%)

Lease operating expense (Production costs)	$	16,498	$	25,064		(34	%)	$	38,320	$	44,585		(14	%)
Treating and transportation		23,042		18,618		24	%		47,456		39,295		21	%
Taxes, other than income		9,262		12,259		(24	%)		17,941		22,465		(20	%)
Depreciation, depletion and amortization (DD&A)		86,825		90,640		(4	%)		187,582		165,415		13	%
Impairment of oil and gas properties		245,205		—		100	%		1,043,338		—		100	%
Reserve for commercial disputes		—		—		—			9,200		—		100	%
General and administrative costs		28,206		21,667		30	%		50,126		41,205		22	%

Costs and expenses (per Boe of production)
Lease operating expense (Production costs)	$	2.88	$	4.48		(36	%)	$	3.29	$	4.25		(23	%)
Treating and transportation		4.02		3.33		21	%		4.07		3.75		9	%
Taxes, other than income		1.62		2.19		(26	%)		1.54		2.14		(28	%)
Depreciation, depletion and amortization (DD&A)		15.14		16.21		(7	%)		16.10		15.79		2	%
General and administrative costs		4.92		3.87		27	%		4.30		3.93		9	%
General and administrative costs, excluding stock-based compensation		4.08		3.15		30	%		3.64		3.23		13	%

Lease operating expense. Lease operating expense decreased during the three and six months ended June 30, 2015 as a result of lower unit costs, partially offset by increased production from the same periods in 2014. Lower unit costs were due to a decline in direct lease operating costs and decreased workover activity in the Eagle Ford area for both the three and six months ended June 30, 2015.

Treating and transportation. Treating and transportation expense increased for both the three and six months ended June 30, 2015. For the three months ended June 30, 2015, treating and transportation expense increased as a result of increased daily production in the Permian Basin in addition to higher per unit expense due to the utilization of higher-cost transportation and processing. For the six months ended June 30, 2015, treating and transportation expense increased as a result of increased daily production in both core areas in addition to higher per unit expense due to the utilization of higher-cost transportation and processing. Additionally, for the three and six months ended June 30, 2015, we have accrued deficiency fees of $4.2 million and $9.2 million, respectively, related to shortfalls in delivering the minimum volumes required under our transportation and processing agreements.

Taxes, other than income. Taxes, other than income, include production taxes and ad valorem taxes. Production taxes are based on revenues generated from production, and ad valorem taxes are based on the valuation of the underlying assets. For the three months ended June 30, 2015, Taxes, other than income, decreased as a result of a $0.57 per Boe decrease in unit costs, which represented $3.3 million of the decrease, partially offset by a $0.3 million increase due to the 1.5 MBoe per day increase in production. For the six months ended June 30, 2015, Taxes, other than income, decreased as a result of a $0.60 per Boe decrease in unit costs, which represented $7.0 million of the decrease, partially offset by a $2.5 million increase due to the 6.5 MBoe per day increase in production.

Depreciation, depletion and amortization. DD&A expense decreased $3.8 million and increased $22.2 million for the three and six months ended June 30, 2015, respectively, as compared to the same periods in 2014. The decrease for three months ended June 30, 2015 was due to a lower depletion rate due to the first quarter 2015 impairment charge being included in our depletion pool, as well as lower daily production from the prior comparable period. The increase for six months ended June 30, 2015 was due to a higher depletion rate due to the inclusion of higher-cost Permian reserves in our depletion pool, as well as increased daily production from the prior comparable period, partially offset by the first quarter 2015 impairment charge.

Impairment of oil and gas properties. Pursuant to full cost accounting rules, we must perform a ceiling test each quarter on our proved oil and natural gas assets. Our ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of June 30, 2015, which were based on a West Texas Intermediate oil price of $68.17 per Bbl and a Henry Hub natural gas price of $3.39 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount was less than the net capitalized cost of oil and natural gas properties as of June 30, 2015, and as a result, a pre-tax write-down of $245.2 million was recorded for the three months ended June 30, 2015. For the six months ended June 30, 2015, we have recorded a pre-tax write-down of $1.0 billion. Additional material write-downs of our oil and gas properties will occur in subsequent quarters in the event that oil and natural gas prices remain at current depressed levels, or if we experience significant downward adjustments to our estimated proved reserves.

Reserve for commercial disputes. We recorded a reserve of $9.2 million during the three months ended March 31, 2015 related to a commercial dispute that arose during the third quarter of 2014. Our total recorded reserve of $15.0 million as of June 30, 2015 represents our expected loss exposure associated with this dispute and the final resolution of this matter is expected to occur in the third quarter of 2015. The reserve for this contingency is reported in Reserve for commercial disputes in the Consolidated Statement of Operations and is included in Accounts payable and accrued liabilities in the Consolidated Balance Sheet.

General and administrative costs. General and administrative costs increased $6.5 million and $8.9 million for the three and six months ended June 30, 2015, respectively, as compared to the same periods in 2014. The increase for the three months ended June 30, 2015 was primarily due to $5.1 million in transaction costs associated with the Noble merger and a $2.8 million increase in personnel costs due to increased headcount, partially offset by a $1.4 million decrease in other costs. The increase for the six months ended June 30, 2015 was primarily due to $5.1 million in transaction costs associated with the Noble merger and a $6.1 million increase in personnel costs due to increased headcount, partially offset by a $2.3 million decrease in other costs. In connection with the Noble merger, we anticipate recording additional transaction costs in the third quarter of 2015 including, but not limited to, costs associated with personnel severances and benefits and professional service costs related to legal, accounting and banking fees.

Total Other Expense

Total other expense, which includes Interest expense, net of interest capitalized; Interest income; and Other expense, decreased $9.0 million and $2.6 million, respectively, for the three and six months ended June 30, 2015 compared to the same periods in 2014. The decrease was a result of a $9.5 million call premium and the write-off of $3.1 million of remaining unamortized debt issuance costs associated with the redemption of our 9.500% Senior Notes during the second quarter of 2014, partially offset by higher interest expense due to the issuance of our 5.875% Senior Notes due 2024 in May 2014 in addition to lower capitalized interest. Our weighted average interest rates, inclusive of interest and commitment fees, for the three and six months ended June 30, 2015 were 5.92% and 5.73%, respectively, compared to 5.83% and 6.04%, respectively, for the same periods in 2014.

Provision for Income Taxes

The effective tax rate for the three and six months ended June 30, 2015 was (4.0%) and 24.1%, respectively. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to the effects of state taxes, the non-deductibility of certain incentive compensation and the impact of valuation allowances. As of June 30, 2015 and December 31, 2014, we had no unrecognized tax benefits, and we do not anticipate that the balance of unrecognized tax benefits will significantly change within the next twelve months due to the settlement of audits or expiration of statutes of limitations.

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We assessed the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. As a result of the material write-downs of our carrying value of oil and natural gas properties, our operating results for the six months June 30, 2015, and considering forecasted operating results, we believe it is more likely than not that the deferred tax assets will not be realized and have recorded a valuation allowance against the federal net deferred tax asset.

Liquidity and Capital Resources

Our sources of liquidity and capital are our operating cash flow, borrowings under our Credit Facility and our cash on hand.

Operating Cash Flow. Our cash flows depend on many factors, including the price of oil, NGLs and natural gas and the success of our development and exploration activities. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge our exposure to commodity price risk, thereby mitigating our exposure to price declines, but these transactions may also limit our earnings potential in periods of rising commodity prices. The effects of these derivative transactions on our oil, NGL and natural gas sales are discussed above under Results of Operations – Revenues. The majority of our capital expenditures is discretionary and could be curtailed if our cash flows materially decline from expected levels. Economic conditions and lower commodity prices could adversely affect our cash flow and liquidity. We will continue to monitor our cash flow and liquidity and, if appropriate, we may consider adjusting our capital expenditure program or accessing the capital markets.

Cash Flows

The following table presents information regarding the change in our cash flows:


	Six Months Ended June 30,
	2015			2014
	(In thousands)
Cash provided by (used in):
Operating activities	$	201,656		$	299,680
Investing activities		(261,264	)		(754,847	)
Financing activities		32,899			289,577

Net decrease in cash and cash equivalents	$	(26,709	)	$	(165,590	)

Operating Activities. The decrease in net cash provided by operating activities for the six months ended June 30, 2015 compared to the same period in 2014 reflects lower realized commodity prices, partially offset by increased production. Working capital changes contributed $11.5 million of positive operating cash flow in the first six months of 2015 as compared with a negative impact of $13.9 million in the first six months of 2014.

Investing Activities. The reduction in net cash used in investing activities for the six months ended June 30, 2015 compared to the same period in 2014 reflects a reduction in our capital spending and acquisition activity.

Financing Activities. The reduction in net cash provided by financing activities for the six months ended June 30, 2015 compared to the same period in 2014 reflects $234.8 million in proceeds from the issuance of common stock, partially offset by net repayments of $200.0 million under the Credit Facility and $1.6 million in deferred loan fees.

Capital Expenditures and Requirements

Our historical capital expenditures summary table is included in Items 1 and 2. Business and Properties in our 2014 Annual Report and is incorporated herein by reference.

Our accrual-basis capital expenditures for the six months ended June 30, 2015 decreased by $552.0 million to $201.1 million from $753.1 million for the six months ended June 30, 2014. During the six months ended June 30, 2015, we drilled 9 and completed 24 gross operated wells. Of these totals, 3 wells were drilled and 17 were completed in the Eagle Ford area. In the Delaware Basin, we drilled 6 gross operated wells and completed 7 gross operated wells, all of which were horizontal. Our capital budget for 2015 is $350 million.

We have the discretion to use availability under the Credit Facility to fund capital expenditures. We also have the ability to adjust our capital expenditure plans throughout the remainder of the year in response to market conditions.

Commodity Price Risk and Related Derivative Activities

The energy markets have historically been very volatile and oil, NGL and natural gas prices may be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management has hedged oil, NGL and natural gas prices from time to time, primarily through the use of certain derivative instruments, including fixed price swaps, basis swaps and costless collars. Although not risk-free, we believe these activities will reduce our exposure to commodity price fluctuations and thereby enable us to achieve a more predictable cash flow. Consistent with this policy, we have entered into a series of oil, NGL and natural gas fixed price swaps and costless collars for each year through 2016. Our fixed price swap and costless collar agreements require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of oil, NGLs and natural gas, as applicable, without the exchange of underlying volumes. The notional amounts of these financial instruments were based on a portion of our anticipated production upon inception of the derivative instruments. The notional volumes hedged equate to a substantial portion of our 2015 projected equivalent production and a portion of our 2016 projected equivalent production. See

Note 5 – Commodity Derivative Contracts and Note 6 – Fair Value Measurements included in Part I. Item 1. Financial Statements of this Form 10-Q for a listing of open contracts as of June 30, 2015, a description of the applicable accounting and the estimated fair market values as of June 30, 2015. The effects of material changes in market risk exposure associated with these derivative transactions are discussed below under Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Governmental Regulation

There have been no material changes in governmental regulations that impact our business from those previously disclosed in our 2014 Annual Report.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of GAAP that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2014 Annual Report.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 3 – Summary of Significant Accounting Policies included in Part I. Item 1. Financial Statements of this Form 10-Q.

Commitments and Contingencies

As is common within the oil and natural gas industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil, NGL and natural gas properties. It is our belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

As noted in Note 10 – Commitments and Contingencies included in Part I. Item 1. Financial Statements of this Form 10-Q, we forecast long-term production from the development of our reserves in the Eagle Ford area. These forecasts are used to identify our future transportation and processing volume requirements. Based on these forecasts, we have secured firm capacity for the transportation and processing of our production in the Eagle Ford area. These commitments are typically effective prior to us having sufficient current production to meet the minimum volume commitments, and we are therefore required to make periodic deficiency payments for delivering less than the minimum required volumes. As we develop additional reserves in the Eagle Ford area, we anticipate exceeding our current minimum volume commitments, and we therefore intend to enter into additional transportation and processing commitments in the future. These future transportation and processing commitments in the Eagle Ford area could expose us to additional volume deficiency payments and as of June 30, 2015, we have accrued deficiency fees of $9.2 million. As of June 30, 2015, we had no such commitments in the Permian area, but as these assets are developed and additional firm capacity for the transportation and processing of our production is added, we could be subject to periodic deficiency payments.

We are party to various legal and regulatory proceedings and commercial disputes arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability we may ultimately incur with respect to such proceeding may be in excess of amounts currently accrued, if any. After considering our available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, we do not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows.

As noted in Note 10 – Commitments and Contingencies included in Part I. Item 1. Financial Statements of this Form 10-Q, we recorded a reserve of $9.2 million in the first quarter of 2015 related to a commercial dispute. Our total recorded reserve of $15.0 million as of June 30, 2015 represents our expected loss exposure associated with this dispute and the final resolution of this matter is expected to occur in the third quarter of 2015.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk primarily related to adverse changes in oil, NGL and natural gas prices. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our 2014 Annual Report and Note 5 – Commodity Derivative Contracts included in Part I. Item 1. Financial Statements of this Form 10-Q.

As of June 30, 2015, we had open crude oil derivative contracts in a net asset position with a fair value of $121.3 million. A 10% increase in crude oil prices would reduce the fair value by approximately $24.5 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $25.1 million. The effects of these derivative transactions on our revenues are discussed above under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.

As of June 30, 2015, we had open NGL derivative contracts in a net asset position with a fair value of $17.6 million. A 10% increase in NGL prices would reduce the fair value by approximately $2.2 million, while a 10% decrease in NGL prices would increase the fair value by approximately $2.2 million. The effects of these derivative transactions on our revenues are discussed above under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.

As of June 30, 2015, we had open natural gas derivative contracts in a net asset position with a fair value of $36.2 million. A 10% increase in natural gas prices would reduce the fair value by approximately $9.6 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $10.1 million. The effects of these derivative transactions on our revenues are discussed above under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.

These transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than anticipated, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement or the counterparties to our derivative agreements fail to perform under the contracts.

As of June 30, 2015, our derivative instruments are with counterparties who are lenders under our Credit Facility. This practice allows us to satisfy any need for margin obligations resulting from an adverse change in the fair market value of the derivative contracts with the collateral securing our Credit Facility, thus eliminating the need for independent collateral postings. As of June 30, 2015, we had no deposits for collateral regarding commodity derivative positions. Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and future market prices on hedged volumes of the commodities as of June 30, 2015. Our third-party provider evaluated nonperformance risk using the current credit default swap values or bond spreads for both the counterparties and us. We recorded a downward adjustment to the fair value of our derivative instruments in the amount of $0.3 million as of June 30, 2015. We are not aware of any circumstances which currently exist that would limit access to our Credit Facility or require a change in our debt or hedging structure.

We have entered into oil, NGL and natural gas derivative contracts through 2016 which hedge our exposure to commodity price risk. These derivative contracts may limit our potential revenue if oil, NGL and natural gas prices exceed the prices established by the contracts. As of June 30, 2015, 38% of our crude oil derivative transactions represented hedged prices of crude oil at West Texas Intermediate on the NYMEX with the remaining 62% at Light Louisiana Sweet; 100% of our total NGL derivative transactions represented hedged prices of NGLs at Mont Belvieu; and 87% of our natural gas derivative transactions represented hedged prices of natural gas at Houston Ship Channel, with the remaining 13% at Tennessee, zone 0.

We use a third-party provider to determine the valuation of our derivative instruments and compare the fair values derived from the third-party provider with values provided by our counterparties. We mark-to-market the fair values of our derivative instruments on a quarterly basis, and 100% of our derivative assets and liabilities are considered Level 3 instruments.

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of June 30, 2015. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2015, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

Item 1. Legal Proceedings

See Part I, Item 1, Note 10 - Commitments and Contingencies of this Form 10-Q, which is incorporated in this item by reference.

Item 1A. Risk Factors

As discussed above, on May 10, 2015, we entered into the Merger Agreement with Noble and Merger Sub, pursuant to which Noble will acquire Rosetta. The parties expect to complete the merger on July 20, 2015. In connection with the execution of the Merger Agreement and pending completion of the merger, we have supplemented the risk factors previously disclosed in the 2014 Annual Report as follows:

Failure to complete the merger could negatively affect Rosetta’s stock price, its future business and financial results.

If the merger is not completed, Rosetta’s ongoing businesses may be adversely affected and Rosetta will be subject to several risks and consequences, including the following:

•

Rosetta will be required to pay certain costs relating to the merger, whether or not the merger is completed, such as legal, accounting, financial advisor and printing fees;

•

Rosetta would not realize the expected benefits of the merger; under the merger agreement, Rosetta is subject to certain restrictions on the conduct of its business prior to completing the merger, which may adversely affect its ability to execute certain of its business strategies;

•

matters relating to the merger may require substantial commitments of time and resources by Rosetta management, which could otherwise have been devoted to other opportunities that may have been beneficial to Rosetta as an independent company;

•

Rosetta has been subject to certain restrictions on its ability to make acquisitions and dispositions and take other specified actions while the merger is pending, which may have prevented Rosetta from pursuing attractive business opportunities and making other changes to its business prior to termination of the merger agreement and may adversely affect its performance after any such termination; and

•

Rosetta may lose key employees during the period in which Rosetta and Noble are pursuing the merger, which may adversely affect Rosetta in the future if it is not able to hire and retain qualified personnel to replace departing employees.

In addition, if the merger is not completed, Rosetta may experience negative reactions from the financial markets and from its customers and employees. Rosetta also could be subject to litigation related to any failure to complete the merger or to enforcement proceedings commenced against Rosetta to attempt to force it to perform their respective obligations under the merger agreement.

If completed, the merger may not achieve its intended results, and Noble and Rosetta may be unable to successfully integrate their operations.

Noble and Rosetta entered into the Merger Agreement with the expectation that the merger will result in various benefits, including, among other things, expanding Noble’s asset base and creating synergies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Noble and Rosetta can be integrated in an efficient and effective manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger. The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s operations that arise or are based on events or actions that occur prior to the closing of the merger. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. The integration process is subject to a number of uncertainties, and no assurance can be given that the anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results and prospects.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended June 30, 2015:

None.

Issuance of Unregistered Securities

None.

Securities Authorized for Issuance under Equity Compensation Plans

See the definitive proxy statement filed with respect to the Company’s 2015 annual meeting under the heading “Securities Authorized for Issuance Under Equity Compensation Plans” and the Company’s 2014 Annual Report for information regarding shares of common stock authorized for issuance under our long-term incentive plans.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits


Exhibit Number		Description

2.1		Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 11, 2015 (Registration No. 000-51801)).

3.1		Text of Amendment to the Amended and Restated Bylaws of Rosetta Resources Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on May 11, 2015 (Registration No. 000-51801)).

31.1*		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Periodic Financial Reports by Chief Executive Officer and Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Schema Document

101.CAL*		XBRL Calculation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document

101.LAB*		XBRL Label Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

*	Filed herewith

SIGNATURES

Pursuant to the requirements 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.


ROSETTA RESOURCES INC.

By:		/s/ John E. Hagale
John E. Hagale Executive Vice President and Chief Financial Officer

(Duly Authorized Officer and Principal Financial Officer)

Date: July 20, 2015