Edgar Filing: Rosetta Resources Inc.

Form 10-Q for quarterly period ended June 30, 2012

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, 2012

¨	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.)

717 Texas, Suite 2800, 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.


Large accelerated filer	x	Accelerated filer	¨
Non-Accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller Reporting Company	¨

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, $.001 par value per share, outstanding as of July 31, 2012 was 52,884,798.

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	18
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	27
	Item 4. Controls and Procedures	28
Part II –	Other Information
	Item 1. Legal Proceedings	28
	Item 1A. Risk Factors	28
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3. Defaults upon Senior Securities	30
	Item 4. Mine Safety Disclosures	30
	Item 5. Other Information	30
	Item 6. Exhibits	31
Signatures		31

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except par value and share amounts)


	June 30, 2012			December 31, 2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	60,084		$	47,050
Accounts receivable, net		69,428			77,374
Derivative instruments		35,449			10,171
Prepaid expenses		4,296			2,962
Deferred income taxes		—			11,015
Other current assets		1,870			2,942

Total current assets		171,127			151,514

Oil and natural gas properties using the full cost method of accounting:
Proved properties		2,570,178			2,297,312
Unproved/unevaluated properties, not subject to amortization		55,357			141,016
Gas gathering systems and compressor stations		67,653			38,580
Other fixed assets		9,231			9,494

		2,702,419			2,486,402
Accumulated depreciation, depletion, and amortization, including impairment		(1,720,834	)		(1,657,841	)

Total property and equipment, net		981,585			828,561
Other assets:
Deferred loan fees		8,795			8,575
Deferred income taxes		33,259			74,150
Derivative instruments		21,542			1,633
Other long-term assets		1,078			912

Total other assets		64,674			85,270

Total assets	$	1,217,386		$	1,065,345

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	4,935		$	2,489
Accrued liabilities		106,754			107,594
Royalties and other payables		50,392			50,689
Derivative instruments		—			6,788
Deferred income taxes		4,086			—
Current portion of long-term debt		20,000			20,000

Total current liabilities		186,167			187,560

Long-term liabilities:
Derivative instruments		—			1,351
Long-term debt		290,000			230,000
Other long-term liabilities		9,197			13,598

Total liabilities		485,364			432,509

Commitments and Contingencies (Note 9)
Stockholders’ equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2012 or 2011		—			—
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 53,105,614 shares and 52,630,483 shares at June 30, 2012 and December 31, 2011, respectively		53			52
Additional paid-in capital		817,460			810,794
Treasury stock, at cost; 577,388 and 450,173 shares at June 30, 2012 and December 31, 2011, respectively		(17,287	)		(11,296	)
Accumulated other comprehensive income		876			1,632
Accumulated deficit		(69,080	)		(168,346	)

Total stockholders’ equity		732,022			632,836

Total liabilities and stockholders’ equity	$	1,217,386		$	1,065,345

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,
	2012			2011			2012			2011
Revenues:
Oil sales	$	66,227		$	39,096		$	129,197		$	67,845
NGL sales		35,928			30,788			79,688			49,330
Natural gas sales		16,107			46,457			39,796			96,237
Derivative instruments		79,719			(4,784	)		63,758			(4,784	)

Total revenues		197,981			111,557			312,439			208,628
Operating costs and expenses:
Lease operating expense		10,236			9,010			18,737			23,530
Treating and transportation		12,525			4,875			24,523			8,326
Production taxes		2,921			2,973			6,149			4,629
Depreciation, depletion, and amortization		33,997			33,355			66,896			67,384
General and administrative costs		11,191			16,307			28,482			37,377

Total operating costs and expenses		70,870			66,520			144,787			141,246

Operating income		127,111			45,037			167,652			67,382

Other expense (income):
Interest expense, net of interest capitalized		6,509			5,066			11,970			11,412
Interest income		(2	)		(5	)		(4	)		(33	)
Other (income) expense, net		(114	)		381			(1	)		654

Total other expense		6,393			5,442			11,965			12,033

Income before provision for income taxes		120,718			39,595			155,687			55,349
Income tax expense		43,749			14,195			56,421			18,952

Net income	$	76,969		$	25,400		$	99,266		$	36,397

Earnings per share:
Basic	$	1.47		$	0.49		$	1.89		$	0.70

Diluted	$	1.46		$	0.48		$	1.88		$	0.69

Weighted average shares outstanding:
Basic		52,502			51,991			52,450			51,923
Diluted		52,837			52,581			52,841			52,567

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,
	2012			2011			2012			2011
Net income	$	76,969		$	25,400		$	99,266		$	36,397
Other comprehensive (loss) income:
Change in fair value of hedging instruments		—			3,223			—			(26,499	)
Reclassification of loss (gain) on settled hedging instruments		—			2,456			—			(6,175	)
Tax provision related to cash flow derivative instruments		399			(1,705	)		434			12,664
Amortization of accumulated other comprehensive gain related to de-designated hedges		(1,102	)		—			(1,190	)		—

Other comprehensive (loss) income		(703	)		3,974			(756	)		(20,010	)

Comprehensive income	$	76,266		$	29,374		$	98,510		$	16,387

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	99,266		$	36,397
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		66,896			67,384
Deferred income taxes		56,421			18,829
Amortization of deferred loan fees recorded as interest expense		1,760			1,232
Stock-based compensation expense		5,482			16,132
Derivative instruments		(54,516	)		(6,234	)
Change in operating assets and liabilities:
Accounts receivable		7,946			(13,588	)
Prepaid expenses		(1,334	)		(1,335	)
Other current assets		265			282
Long-term assets		(165	)		(52	)
Accounts payable		2,446			(1,066	)
Accrued liabilities		(28,865	)		(2,502	)
Royalties and other payables		(297	)		10,057
Other long-term liabilities		(16	)		4,928

Net cash provided by operating activities		155,289			130,464

Cash flows from investing activities:
Additions to oil and gas assets		(277,961	)		(175,030	)
Disposals of oil and gas assets		82,816			242,910

Net cash (used in) provided by investing activities		(195,145	)		67,880

Cash flows from financing activities:
Borrowings on Restated Revolver		130,000			—
Payments on Restated Revolver		(70,000	)		(100,000	)
Deferred loan fees		(1,980	)		(3,141	)
Proceeds from stock options exercised		861			1,829
Purchases of treasury stock		(5,991	)		(3,988	)

Net cash provided by (used in) financing activities		52,890			(105,300	)

Net increase in cash		13,034			93,044
Cash and cash equivalents, beginning of period		47,050			41,634

Cash and cash equivalents, end of period	$	60,084		$	134,678

Supplemental disclosures:
Capital expenditures included in accrued liabilities	$	83,401		$	52,774

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			Retained Earnings / Accumulated Deficit			Total Stockholders’ Equity
	Shares		Amount		Additional Paid-In Capital		Shares		Amount			(Loss)/Income			Retained Earnings / Accumulated Deficit			Total Stockholders’ Equity
Balance at December 31, 2011		52,630,483	$	52	$	810,794		450,173	$	(11,296	)	$	1,632		$	(168,346	)	$	632,836
Stock options exercised		65,862		1		861		—		—			—			—			862
Treasury stock—employee tax payment		—		—		—		127,215		(5,991	)		—			—			(5,991	)
Stock-based compensation		—		—		5,805		—		—			—			—			5,805
Vesting of restricted stock		409,269		—		—		—		—			—			—			—
Comprehensive (loss) income		—		—		—		—		—			(756	)		99,266			98,510

Balance at June 30, 2012		53,105,614	$	53	$	817,460		577,388	$	(17,287	)	$	876		$	(69,080	)	$	732,022

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”) 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 primarily located in South Texas, including its largest producing area in the Eagle Ford shale, and in the Southern Alberta Basin in Northwest Montana.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only 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, 2011 (“2011 Annual Report”).

Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income.

(2) Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2011 Annual Report.

Recent Accounting Developments

The following recently issued accounting developments have been applied or may impact the Company in future periods.

Fair Value Measurements. In May 2011, the Financial Accounting Standards Board (“FASB”) further expanded authoritative guidance clarifying common requirements for measuring fair value instruments and for disclosing information about fair value measurements in accordance with GAAP and International Financial Reporting Standards (“IFRS”). This guidance requires disclosure of quantitative and qualitative information about unobservable inputs used in measuring the fair value of Level 3 instruments. The Company has adopted this guidance effective January 1, 2012. This guidance requires additional disclosures but did not impact the Company’s consolidated financial position, results of operations or cash flows. See Note 5 – Fair Value Measurements.

Comprehensive Income. In June 2011, the FASB issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. Irrespective of the presentation method chosen, an entity will be required to present on the face of the financial statement reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement where the component is presented. In December 2011, the FASB issued additional guidance deferring the effective date related to the presentation of reclassification adjustments only. The Company has adopted the provisions of this guidance, excluding the requirements deferred in the December 2011 guidance, effective January 1, 2012, and has presented two separate but consecutive statements of net income and comprehensive income.

(3) Property and Equipment

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


	June 30, 2012				December 31, 2011
	(In thousands)
Proved properties		$	2,570,178			$	2,297,312
Unproved/unevaluated properties			55,357				141,016
Gas gathering systems and compressor stations			67,653				38,580
Other fixed assets			9,231				9,494

Total property and equipment, gross			2,702,419				2,486,402
Less: Accumulated depreciation, depletion, and amortization, including impairment			(1,720,834	)			(1,657,841	)

Total property and equipment, net		$	981,585			$	828,561

On February 15, 2012, the Company entered into an agreement to sell its Lobo assets and a portion of its Olmos assets for $95.0 million, subject to customary adjustments and the receipt of appropriate consents for assignment. During the first and second quarters of 2012, the Company closed on the properties for which consents for assignment were received. Net proceeds received, after adjusting for a January 1, 2012 effective date, were $83.3 million. Proceeds from the closings of the divestiture were recorded as adjustments to the full cost pool, with no gain or loss recognized.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.5 million and $0.9 million of internal costs for the three months ended June 30, 2012 and 2011, respectively, and $3.5 million and $2.4 million for the six months ended June 30, 2012 and 2011, respectively.

Oil and gas properties include costs of $55.4 million and $141.0 million as of June 30, 2012 and December 31, 2011, respectively, which were excluded from amortized capitalized costs. These amounts primarily represent acquisition costs of unproved properties and unevaluated exploration projects in which the Company owns a direct interest. During the second quarter of 2012, exploration work was completed in the Southern Alberta Basin and the Company’s assessment indicated an impairment. As a result, accumulated costs of approximately $82.8 million were transferred to the full cost pool.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within its U.S. cost center. 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, 2012, which were based on a West Texas Intermediate oil price of $92.17 per Bbl and a Henry Hub natural gas price of $3.15 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and gas properties. As a result, no write-down was recorded as of June 30, 2012. It is possible that a write-down of the Company’s oil and gas properties could occur in future periods in the event that oil and natural gas prices decline or the Company experiences significant downward adjustments to its estimated proved reserves.

(4) Commodity Derivative Contracts and Other Derivatives

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, New York Mercantile Exchange (“NYMEX”) roll 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, 2012, 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 Bbl		Total of Notional Volume Bbl		Average Floor Prices per Bbl			Average Ceiling Prices per Bbl
Crude oil		2012		Costless Collar		7,600		1,398,400	$	78.82		$	115.02
Crude oil		2013		Costless Collar		6,750		2,463,750		79.44			117.29
Crude oil		2014		Costless Collar		2,000		730,000		82.50			111.95

								4,592,150


Product	Settlement Period		Derivative Instrument		Notional Daily Volume Bbl		Total of Notional Volume Bbl		Fixed Prices per Bbl
Crude oil		2012		Basis Swap		2,500		460,000	$	8.70
Crude oil		2012		NYMEX Roll Swap		2,500		460,000		(0.30	)
Crude oil		2013		Basis Swap		1,875		684,375		5.80
Crude oil		2013		NYMEX Roll Swap		1,875		684,375		(0.18	)

								2,288,750


Product	Settlement Period		Derivative Instrument		Notional Daily Volume Bbl		Total of Notional Volume Bbl		Fixed Prices per Bbl
NGL-Propane		2012		Swap		2,500		460,000	$	53.22
NGL-Isobutane		2012		Swap		760		139,840		71.70
NGL-Normal Butane		2012		Swap		780		143,520		67.86
NGL-Pentanes Plus		2012		Swap		660		121,440		89.77
NGL-Propane		2013		Swap		1,270		463,550		51.82
NGL-Isobutane		2013		Swap		380		138,700		72.59
NGL-Normal Butane		2013		Swap		420		153,300		70.57
NGL-Pentanes Plus		2013		Swap		430		156,950		88.75
NGL-Propane		2014		Swap		535		195,275		51.04
NGL-Isobutane		2014		Swap		155		56,575		71.82
NGL-Normal Butane		2014		Swap		165		60,225		70.47
NGL-Pentanes Plus		2014		Swap		145		52,925		89.22

								2,142,300


Product	Settlement Period		Derivative Instrument		Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor Prices per MMBtu			Average Ceiling Prices per MMBtu
Natural gas		2012		Costless Collar		20,000		3,680,000	$	5.13		$	6.31

								3,680,000

As of June 30, 2012, the Company’s derivative instruments are with counterparties who are lenders under the Company’s credit facilities or were lenders under the Company’s credit facilities upon origination of the derivative instrument. This 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 facilities, 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 below in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Government Regulation. As of June 30, 2012, the Company had no deposits for collateral regarding its commodity derivative positions.

Discontinuance of Hedge Accounting

Effective January 1, 2012, the Company elected to de-designate all commodity contracts that were previously designated as cash flow hedges as of December 31, 2011, and elected to discontinue hedge accounting prospectively. Accumulated other comprehensive income included $2.6 million ($1.6 million after tax) of unrealized net gains, representing the marked-to-market value of the Company’s cash flow hedges as of December 31, 2011. As a result of discontinuing hedge accounting, the marked-to-market values included in Accumulated other comprehensive income as of the de-designation date were frozen and will be reclassified into earnings in future periods as the underlying hedged transactions affect earnings. During the three and six months ended June 30, 2012, the Company reclassified unrealized net gains of $1.1 million ($0.7 million after tax) and $1.2 million ($0.8 million after tax), respectively, into earnings from Accumulated other comprehensive income. The Company expects to reclassify an additional $1.5 million ($0.9 million after tax) of unrealized net gains during the last six months of 2012 and $0.1 million of unrealized net losses during 2013 into earnings from Accumulated other comprehensive income.

With the election to de-designate hedging instruments, all of the Company’s derivative instruments continue to be recorded at fair value with unrealized gains and losses recognized immediately in earnings rather than in Accumulated other comprehensive income. These marked-to-market adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract.

Additional Disclosures about Derivative Instruments and Hedging Activities

Authoritative guidance for derivatives 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, 2012 and December 31, 2011, respectively:


	Fair Values of Derivative Instruments
	Assets (Liabilities)
	(In thousands)
Commodity derivative contracts	Location on Consolidated Balance Sheet		Fair Value
Commodity derivative contracts	Location on Consolidated Balance Sheet		June 30, 2012		December 31, 2011
Oil		Derivative instruments - current assets	$	—	$	(2,937	)
Oil		Derivative instruments - non-current assets		—		1,254
Oil		Derivative instruments - current liabilities		—		(695	)
Oil		Derivative instruments - long-term liabilities		—		(167	)
NGL		Derivative instruments - current assets		—		(1,029	)
NGL		Derivative instruments - current liabilities		—		(6,948	)
NGL		Derivative instruments - long-term liabilities		—		(1,184	)
Natural gas		Derivative instruments - current assets		—		14,137

		Total derivatives designated as hedging instruments	$	—	$	2,431

Oil		Derivative instruments - current assets	$	7,237	$	—
Oil		Derivative instruments - non-current assets		9,850		379
Oil		Derivative instruments - current liabilities		—		855
NGL		Derivative instruments - current assets		20,171		—
NGL		Derivative instruments - non-current assets		11,692		—
Natural gas		Derivative instruments - current assets		8,041		—

		Total derivatives not designated as hedging instruments	$	56,991	$	1,234

		Total derivatives	$	56,991	$	3,665

The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the three and six months ended June 30, 2012 and 2011, respectively:


Location on Consolidated Statement of Operations	Description of Gain (Loss)	Three Months Ended June 30,					Six Months Ended June 30,
Location on Consolidated Statement of Operations	Description of Gain (Loss)	2012		2011 (1)			2012		2011 (1)
		(in thousands)
Oil sales	Loss reclassified from Accumulated OCI	$	—	$	(1,133	)	$	—	$	(1,454	)
NGL sales	Loss reclassified from Accumulated OCI		—		(3,039	)		—		(4,225	)
Natural gas sales	Gain reclassified from Accumulated OCI		—		3,133			—		10,404
Natural gas sales (2)	Gain recognized in income		—		8,151			—		11,018
Derivative instruments	Gain recognized in income		7,251		—			9,242		—

	Realized gain recognized in income	$	7,251	$	7,112		$	9,242	$	15,743

Derivative instruments (3)	Gain (loss) recognized in income due to changes in fair value	$	71,366	$	(4,784	)	$	53,326	$	(4,784	)
Derivative instruments	Gain reclassified from Accumulated OCI		1,102		—			1,190		—

	Unrealized gain (loss) recognized in income	$	72,468	$	(4,784	)	$	54,516	$	(4,784	)

	Total commodity derivative gain recognized in income	$	79,719	$	2,328		$	63,758	$	10,959

(1)	Includes realized gains (losses) from derivative instruments designated as hedging instruments. Effective January 1, 2012, the Company de-designated all commodity contracts and discontinued hedge accounting.

(2)	For the three and six months ended June 30, 2011, amounts represent the realized gains associated with the termination of derivatives in 2011 used to hedge production from the Company’s divested DJ Basin and Sacramento Basin properties.

(3)	For the three and six months ended June 30, 2011, amounts represent the unrealized loss associated with the change in fair value of the Company’s crude oil basis and NYMEX roll swaps, which did not qualify for hedge accounting.

As a result of the Company’s election to de-designate all commodity contracts that were previously designated as cash flow hedges as of December 31, 2011 and to discontinue hedge accounting prospectively, the Company recognized no gain or loss in Accumulated other comprehensive income for the three and six months ended June 30, 2012. The Company recognized an unrealized gain of $3.2 million and unrealized loss of $26.5 million, respectively, in Accumulated other comprehensive income for the three and six months ended June 30, 2011.

(5) 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 FASB’s guidance, 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 or 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 and 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, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets (liabilities):
Money market funds (1)	$	—	$	1,035	$	—	$	1,035
Commodity derivative contracts		—		—		56,991		56,991

Total	$	—	$	1,035	$	56,991	$	58,026


	Fair value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets (liabilities):
Money market funds	$	—	$	—	$	1,035	$	1,035
Commodity derivative contracts		—		—		3,665		3,665

Total	$	—	$	—	$	4,700	$	4,700

(1)	The value related to the money market funds was transferred from Level 3 to Level 2 as a result of the Company’s ability to obtain independent market-corroborated data. The Company recognized the transfer between Level 3 and Level 2 during the first quarter of 2012.

The Company’s Level 3 instruments include commodity derivative contracts which are measured based upon counterparty and third-party broker quotes. The fair values derived from counterparties and third-party brokers are verified using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific valuation models or certain inputs used by its counterparties or third-party brokers. In addition, the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.

The following table presents a range of the unobservable inputs utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of June 30, 2012:


	Asset			Valuation Technique		Range					Weighted
Level 3 Instrument	(Liability)			Valuation Technique	Unobservable Input	Minimum			Maximum		Average
Oil NYMEX roll swap	$	112		Discounted cash flow	Forward price curve - NYMEX roll swaps	$	0.07		$	0.31	$	0.24
Oil NYMEX roll swap		(44	)	Discounted cash flow	Forward price curve - NYMEX roll swaps		(0.35	)		0.38		(0.06	)
Oil basis swaps		(1,229	)	Discounted cash flow	Forward price curve - basis swaps		4.35			12.57		1.08
Oil costless collars		18,248		Option model	Forward price curve - costless collar option value		(6.11	)		12.10		4.02
NGL swaps		31,863		Discounted cash flow	Forward price curve - swaps		34.65			76.60		15.07
Natural gas costless collars		8,041		Option model	Forward price curve - costless collar option value		—			2.97		2.21

	$	56,991

The determination of derivative fair values also incorporates a credit adjustment for nonperformance risk, including the credit standing of the counterparties involved, the impact of credit enhancements and the impact of the Company’s nonperformance risk on its liabilities. The Company considered credit adjustments for its counterparties using their current credit default swap values in determining fair value and recorded a downward adjustment to the fair value of its derivative instruments in the amount of $0.7 million as of June 30, 2012.

The significant unobservable inputs for Level 3 derivative contracts include forward price curves, option values and credit risk adjustments. Significant increases (decreases) in the quoted forward prices for commodities, option values and credit risk adjustments 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.


	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2012	$	3,665		$	1,035		$	4,700
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		62,568			—			62,568
Purchases, Issuances and Settlements:
Settlements		(9,242	)		—			(9,242	)
Transfers in and out of Level 3 (1)		—			(1,035	)		(1,035	)

Balance at June 30, 2012	$	56,991		$	—		$	56,991


	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2011	$	19,657		$	1,035		$	20,692
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings (2)		(10,959	)		—			(10,959	)
Included in Other Comprehensive Income		(26,499	)		—			(26,499	)
Purchases, Issuances and Settlements:
Settlements		(3,829	)		—			(3,829	)
Purchases		11,018			—			11,018

Balance at June 30, 2011	$	(10,612	)	$	1,035		$	(9,577	)

(1)	The value related to the money market funds was transferred from Level 3 to Level 2 as a result of the Company’s ability to obtain independent market-corroborated data. The Company recognized the transfer between Level 3 and Level 2 during the first quarter of 2012.

(2)	Includes an unrealized derivative loss of $4.8 million associated with the change in fair value of the Company’s crude oil basis and NYMEX roll swaps, which did not qualify for hedge accounting.

Fair Value of Other Financial Instruments

All of the Company’s financial instruments, except derivatives, are presented on the balance sheet at carrying value. As of June 30, 2012, the carrying value of cash and cash equivalents (excluding money market funds), other current assets and current liabilities reported in the consolidated balance sheet approximate fair value because of their short-term nature and are considered Level 1 instruments.

The Company’s debt consists of publicly traded Senior Notes, borrowings under the Restated Revolver and fixed rate borrowings outstanding under the Second Lien Term Loan. The fair value of the Company’s publicly traded Senior Notes is based upon an unadjusted quoted market price and is considered a Level 1 instrument. The Company’s borrowings under the Restated Revolver approximate fair value as the interest rates are variable and reflective of market rates and are therefore considered a Level 1 instrument. The fair value of the Company’s borrowings under the Second Lien Term Loan is estimated using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile, which results in a Level 2 instrument. As of June 30, 2012, the carrying amount and estimated fair value of total debt was $310.0 million and $327.4 million, respectively.

(6) Asset Retirement Obligations

The following table provides a roll forward of the Company’s asset retirement obligations. Liabilities incurred during the period include additions to obligations. Liabilities settled during the period include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Activity related to the Company’s asset retirement obligations (“ARO”) is as follows:


	Six Months Ended June 30, 2012
	(In thousands)
ARO as of December 31, 2011	$	14,313
Liabilities incurred during period		46
Liabilities settled during period		(5,108	)
Revision of previous estimates		2,067
Accretion expense		514

ARO as of June 30, 2012	$	11,832

As of June 30, 2012, the $3.8 million current portion of the total ARO is included in Accrued liabilities, and the $8.0 million long-term portion of ARO is included in Other long-term liabilities on the Consolidated Balance Sheet.

(7) Long-Term Debt

Senior Secured Revolving Credit Facility. On April 25, 2012, the Company entered into an amendment to its Amended and Restated Senior Revolving Credit Agreement (the “Restated Revolver”). Under this amendment, among other things, the Company’s borrowing base was increased from $325.0 million to $625.0 million and the Company’s capacity to hedge its production was increased. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements as well as asset divestitures. The amount of the borrowing base is affected by a number of factors, including the Company’s level of reserves, as well as the pricing outlook at the time of the redetermination. Therefore, a significant reduction in capital spending could result in a reduced level of reserves that could cause a reduction in the borrowing base.

As of June 30, 2012, the Company had $90.0 million outstanding with $535.0 million of available borrowing capacity under its Restated Revolver. Amounts outstanding under the Restated Revolver bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50%. The weighted average borrowing rate for the six months ended June 30, 2012 under the Restated Revolver was 1.93%. Borrowings under the Restated Revolver are collateralized by perfected first priority 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 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 subject to certain financial covenants such as the requirement to maintain a minimum 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 maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 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, 2012, the Company’s current ratio was 4.1 and the leverage ratio was 0.6. 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.

In July 2012, the Company borrowed $30.0 million under the Restated Revolver, and the available borrowing capacity was reduced to $505.0 million.

Second Lien Term Loan. The Company’s amended and restated term loan (the “Restated Term Loan”) matures on October 2, 2012. As of June 30, 2012, the Company had $20.0 million of fixed rate borrowings outstanding under the Restated Term Loan bearing interest at 13.75%. The Company has the right to prepay the fixed rate borrowings outstanding under the Restated Term Loan with a make-whole amount at a discount factor equal to 1% plus the U.S. Treasury yield security having a maturity closest to the remaining life of the loan. The loan is collateralized by second priority liens on substantially all of the Company’s assets. The Company is subject to certain financial covenants, including the requirement to maintain a minimum reserve ratio of total reserve value to total debt of not less than 1.5 to 1.0 as of the end of each fiscal quarter. The terms of the agreement also require the Company to maintain a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as

depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended. As of June 30, 2012, the Company’s reserve coverage ratio was 1.8 and the leverage ratio was 0.6. In addition, the Company is subject to covenants, including limitations on dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties.

Senior Notes. On April 15, 2010, the Company issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes due 2018 (the “Senior Notes”) in a private offering. The Senior Notes were issued under an indenture (the “Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the 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 Indenture also contains customary events of default. Interest is payable on the Senior Notes semi-annually on April 15 and October 15. On September 21, 2010, the Company exchanged all of the privately placed Senior Notes for registered Senior Notes which contain terms substantially identical to the terms of the privately placed notes.

As of June 30, 2012, the Company had total outstanding borrowings of $310.0 million. For the six months ended June 30, 2012, the Company’s weighted average borrowing rate was 8.23%.

(8) Income Taxes

The Company’s effective tax rate for both the three and six months ended June 30, 2012 was 36.2% and the effective tax rate for the three and six months ended June 30, 2011 was 35.9% and 34.2%, respectively. The provision for income taxes for the three and six months ended June 30, 2012 differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes and the non-deductibility of certain incentive compensation. As of June 30, 2012 and December 31, 2011, the Company had no unrecognized tax benefits. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

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. As of June 30, 2012, the Company had a net deferred tax asset of $29.2 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of oil and natural gas properties. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income from the production of oil and natural gas properties prior to the expiration of loss carryforwards. The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

(9) Commitments and Contingencies

Firm Oil and Gas Transportation Commitments. The Company has various production volume transportation commitments related to its operations in the Eagle Ford shale and has an aggregate minimum commitment to deliver 7.8 MMBbls of oil by the end of 2017 and 417 million MMBtus of natural gas by the end of 2023. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume under these commitments. As of June 30, 2012, the Company has accrued deficiency fees of $2.6 million and expects to continue to accrue additional deficiency fees until resources are more fully developed to increase production to fulfill the delivery commitments. Future obligations under firm oil and natural gas transportation agreements as of June 30, 2012 are as follows:


	June 30, 2012
	(In thousands)
2012	$	5,531
2013		28,530
2014		33,717
2015		33,717
2016		33,809
Thereafter		166,667

	$	301,971

Drilling Rig and Completion Services Commitments. Drilling rig and completion services commitments represent obligations with certain contractors primarily to execute the Company’s Eagle Ford shale and Southern Alberta Basin drilling programs. As of June 30, 2012, the Company had no outstanding drilling commitments with terms greater than one year and future obligations due in the next twelve months are $12.0 million.

The Company has agreements with completion service contractors for the stimulation, cementing and delivery of drilling fluids to support current operations. As of June 30, 2012, the minimum contractual commitments for these agreements are $10.8 million. Payments under these agreements are accounted for as capital additions to oil and gas properties.

Contingencies. The Company is party to various legal and regulatory proceedings 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, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

(10) Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if outstanding common stock awards and stock options were exercised at the end of the period.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands)
Basic weighted average number of shares outstanding		52,502		51,991		52,450		51,923
Dilution effect of stock option and awards at the end of the period		335		590		391		644

Diluted weighted average number of shares outstanding		52,837		52,581		52,841		52,567

Anti-dilutive stock awards and shares		53		1		6		2

(11) Stock-Based Compensation Expense

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 executive management. As of the indicated dates, stock-based compensation expense consisted of the following:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Total stock-based compensation expense	$	221		$	5,743		$	5,805		$	16,474
Capitalized in oil and gas properties		(162	)		(201	)		(323	)		(342	)

Net stock-based compensation expense	$	59		$	5,542		$	5,482		$	16,132

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, 2012, the Company recorded compensation expense of approximately $1.4 million and $2.8 million, respectively, related to these equity awards. As of June 30, 2012, unrecognized stock-based compensation expense related to unvested restricted stock was approximately $8.4 million.

Stock-based compensation expense associated with the PSUs granted to executive management is recognized over a three-year vesting period when certain conditions have been met. For the three and six months ended June 30, 2012, the Company recognized compensation expense of $(1.2) million and $3.0 million, respectively, associated with the PSUs.

At the current fair value as of June 30, 2012 and assuming that the Board elects the maximum available payout of 200% for all PSU metrics, total stock-based compensation expense related to the PSUs to be recognized over the three-year service periods would be $11.2 million, $5.5 million and $4.4 million, respectively, for the 2010, 2011 and 2012 PSU plans. The Company’s total stock-based compensation expense will be measured and adjusted quarterly until settlement occurs, based on the Company’s quarter-end closing common stock prices and Monte Carlo model valuation. For a more detailed description of the Company’s PSU plans, conditions and structure, see the definitive proxy statement filed with respect to the Company’s 2012 annual meeting under the heading “Compensation Discussion and Analysis” and the Company’s 2011 Annual Report.

(12) 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 and the Company’s non-guarantor subsidiaries are minor. 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,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “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, 2011 (the “2011 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:

•

the supply and demand for oil, natural gas liquids (“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;

•

the occurrence of property acquisitions or divestitures;

•

reserve levels;

•

inflation;

•

competition in the oil and natural gas industry;

•

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

•

the availability and cost of processing and transportation of oil, NGLs and natural gas;

•

changes or advances in technology;

•

potential reserve revisions;

•

limitations, availability, and constraints on infrastructure required to process, transport, and market oil, NGLs and natural gas;

•

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

•

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

•

drilling and 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 applicable laws and regulations, including changes in such regulations or the interpretation thereof;

•

present and future claims, litigation and enforcement actions;

•

lease termination due to lack of activity or other disputes with mineral lease and royalty owners regarding the 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, 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; and

•

any other factors that impact or could impact the exploration of oil 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 and natural gas.

Overview

The following discussion addresses material changes in our results of operations for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011 and material changes in our financial condition since December 31, 2011. This discussion should be read in conjunction with our 2011 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, 2012 included the following:

•

production of 3.0 MMBoe compared to 2.4 MMBoe for the three months ended June 30, 2011;

•

23 gross (22 net) wells drilled with a net success rate of 100% compared to 13 gross (12 net) wells drilled with a net success rate of 100% for the three months ended June 30, 2011;

•

net income of $77.0 million, or $1.46 per diluted share, compared to $25.4 million, or $0.48 per diluted share, for the three months ended June 30, 2011.

Results for the six months ended June 30, 2012 included the following:

•

production of 6.1 MMBoe compared to 4.8 MMBoe for the six months ended June 30, 2011;

•

38 gross (37 net) wells drilled with a net success rate of 100% compared to 24 gross (23 net) wells drilled with a net success rate of 100% for the six months ended June 30, 2011;

•

net income of $99.3 million, or $1.88 per diluted share, compared to $36.4 million, or $0.69 per diluted share, for the six months ended June 30, 2011.

We continue to build upon our success as an unconventional resource player with the development of our assets in the Eagle Ford shale in South Texas, one of the most active shale plays in the U.S. In the last three years, we have become a significant producer in the liquids-rich window of the region and have established an inventory of low-risk, high-return drilling opportunities that offer long-term production, reserve growth and a more valuable commodity mix.

Rosetta was an early entrant into the Eagle Ford area, accumulating a significant leasehold position during 2008 and 2009. Overall, we hold 65,000 net acres with approximately 50,000 acres located in the liquids-producing area of the play. During 2011, our primary focus was the development of our 26,500-acre Gates Ranch leasehold in Webb County where our success led to double-digit production increases and the doubling of our reserve base from 2010. In the first half of 2012, we expanded our development drilling program to include newly delineated leaseholds in the Karnes Trough and Briscoe Ranch areas where initial testing in 2011 indicated higher liquids yields.

As of December 31, 2011, our estimated proved reserves were 161 MMBoe, a 101% increase from our estimated proved reserves of 80 MMBoe from the prior year. As of June 30, 2012, approximately 56% of our reserves discovered in the Eagle Ford shale are liquids, shifting our production portfolio toward greater percentages of higher-valued oil and NGLs. For the quarter ended June 30, 2012, approximately 59% of our production was from oil and NGLs as compared to 46% for the same period in 2011. Our success in the development of our Eagle Ford assets combined with the sale of non-strategic assets has led to a lowering of our overall cost structure as a company. During the first half of 2012, our lease operating expenses decreased to $3.06 per Boe from $4.94 per Boe for the same period in 2011.

With the growth of our shale activities, we have streamlined our operations by divesting assets that no longer fit our operating model. Since 2010, we have executed sale agreements for aggregate consideration of approximately $440 million. During the first half of 2012, we entered into an agreement for the sale of our Lobo assets and the majority of our Olmos properties in South Texas for $95 million, subject to customary closing adjustments, with a January 1, 2012 effective date. To date, we have received net proceeds of $83.3 million for over 90% of the properties.

We successfully drilled 20 and completed 15 wells in the Eagle Ford shale during the quarter ended June 30, 2012. As of that date, we had completed a total of 91 wells in the Eagle Ford shale. In the first six months of 2012, daily production increased 28% from the same period in 2011, and we continue to record strong sequential growth in our Eagle Ford volumes. Our liquids production from the Eagle Ford shale accounted for 54% of our total production for the six months ended June 30, 2012 compared to 36% a year ago. We continue to develop multiple options for transportation and processing capacity in the highly competitive Eagle Ford service market with firm commitments in place to meet planned total production levels for the next two years.

Our other shale activity area lies in the Southern Alberta Basin in Northwest Montana. During the second quarter of 2012, exploration work was concluded on our seven-well horizontal drilling program in this basin. Of the seven horizontal wells, five have been completed. The initial three wells were open hole completions and averaged initial rates ranging from 104 to 403 Boe/d. The most recent two completions utilized cased holes and averaged 50 to 205 Boe/d. Based on these results, which are below the targeted type curve, we will suspend all capital activity on this exploration project. Our Southern Alberta Basin position has leases and lease options which begin to expire starting in January 2014.

Our business goals for 2012 are based on an announced capital program of $640.0 million with more than 90% allocated to the evaluation and development of our Eagle Ford assets, which are expected to deliver significant year-over-year production growth. Our plans for the year are based on a four-to-five-rig program in the Eagle Ford shale and the completion of 55 to 60 new wells. Approximately 5% of our capital program has been spent for evaluation of the Southern Alberta Basin. In addition to our focus in the Eagle Ford shale area, we are pursuing new opportunities to drive the long-term growth and sustainability of the Company. We will continue to consider investments in other unconventional resources that offer a viable inventory of projects including new higher-risk exploration, as well as producing property acquisitions.

While our unconventional resource strategy is proving to be successful, we recognize that there are risks inherent to our industry that could impact our ability to meet future goals. Our business model takes into account the threats that could impede achievement of our stated growth objectives and the building of our asset base. However, we cannot completely control all external factors that could affect our operating environment. We have diversified our production base to include a greater mix of crude oil and NGLs, which continue to be priced at more favorable levels than natural gas. With our high concentration of production located in the Eagle Ford shale, we have taken aggressive steps to ensure access to necessary services and infrastructure.

We believe that our 2012 capital program can be executed from internally generated cash flows, cash on hand, drawing on unused capacity under our existing revolving credit facility and the proceeds from our recent asset divestitures. We continuously monitor our liquidity to ensure that we are in a position to respond to changing market conditions, commodity prices and service costs. If our internal funds are insufficient to meet projected funding requirements, we would consider curtailing capital spending or accessing the capital markets.

Effective April 25, 2012, the borrowing base under our Restated Revolver was increased from $325.0 million to $625.0 million. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on hedging arrangements and asset divestitures. The amount of the borrowing base is dependent on a number of factors, including our level of reserves, as well as the pricing outlook at the time of the redetermination. As of August 1, 2012, we had $120 million outstanding with $505 million available for borrowing under the Restated Revolver.

Results of Operations

Revenues

Our consolidated financial statements for the three months ended June 30, 2012 reflect total revenue of $198.0 million based on total volumes of 3.0 MMBoe and net derivative gains of $79.7 million. Our consolidated financial statements for the six months ended June 30, 2012 reflect total revenue of $312.4 million based on total volumes of 6.1 MMBoe and net derivative gains of $63.8 million.

The following table summarizes the components of our revenues (including the effects of derivative instruments) 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,
	2012		2011			% Change Increase/ (Decrease)			2012		2011			% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)								(In thousands, except percentages and per unit amounts)
Revenues:
Oil sales	$	66,227	$	39,096			69	%	$	129,197	$	67,845			90	%
NGL sales		35,928		30,788			17	%		79,688		49,330			62	%
Natural gas sales		16,107		46,457			(65	%)		39,796		96,237			(59	%)
Derivative instruments		79,719		(4,784	)		(1766	%)		63,758		(4,784	)		(1433	%)

Total revenues	$	197,981	$	111,557			77	%	$	312,439	$	208,628			50	%

Production:
Oil (MBbls)		730.2		428.0			71	%		1,407.4		767.5			83	%
NGLs (MBbls)		1,063.8		687.4			55	%		1,973.3		1,108.5			78	%
Natural gas (Bcf)		7.5		7.9			(5	%)		16.4		17.3			(5	%)
Total equivalents (MBoe)		3,041.0		2,439.0			25	%		6,119.4		4,765.7			28	%

Average sales price:
Oil, excluding derivatives (per Bbl)	$	90.70	$	93.99			(4	%)	$	91.80	$	90.29			2	%
Oil, including realized derivatives (per Bbl)		89.13		91.35			(2	%)		90.91		88.40			3	%
NGL, excluding derivatives (per Bbl)		33.77		49.21			(31	%)		40.38		48.31			(16	%)
NGL, including realized derivatives (per Bbl)		36.61		44.79			(18	%)		40.70		44.50			(9	%)
Natural gas, excluding derivatives (per Mcf)		2.15		4.45			(52	%)		2.43		4.32			(44	%)
Natural gas, including realized derivatives (per Mcf)		2.87		5.88			(51	%)		3.03		5.56			(46	%)
Revenue, including realized derivatives (per Boe)		41.27		47.70			(13	%)		42.15		44.78			(6	%)

Oil. For the three and six months ended June 30, 2012, oil revenue, including realized derivative losses, increased by $26.0 million and $60.1 million, respectively, from the same periods in 2011. The increases were attributable to increased production from newly completed wells in the Eagle Ford shale. Realized derivative losses of $1.1 million and $1.3 million, respectively, for the three and six months ended June 30, 2012 are reported as a component of Derivative instruments within Revenues. For the three and six months ended June 30, 2011, the effects of oil hedging activities on oil revenue resulted in losses of $1.1 million and $1.5 million, respectively, and are reported as a component of Oil sales within Revenues.

NGLs. For the three and six months ended June 30, 2012, NGL revenues, including realized derivative gains, increased by $8.1 million and $31.0 million, respectively, from the same periods in 2011. The increases were attributable to increased production from newly completed wells in the Eagle Ford shale partially offset by lower average realized prices, including the effects of realized derivative gains, as compared to the same periods in 2011. Realized derivative gains of $3.0 million and $0.6 million, respectively, for the three and six months ended June 30, 2012 are reported as a component of Derivative instruments within Revenues. For the three and six months ended June 30, 2011, the effects of NGL hedging activities on NGL revenue resulted in losses of $3.0 million and $4.2 million, respectively, and are reported as a component of NGL sales within Revenues.

Natural Gas. For the three and six months ended June 30, 2012, natural gas revenues, including realized derivative gains, decreased by $25.0 million and $46.6 million, respectively, from the same periods in 2011. The decreases were primarily due to a decline in average realized price of natural gas, including the effects of realized derivative gains, and a 5% decline in natural gas production due to asset divestitures of dry gas properties for both the three and six months ended June 30, 2012, compared to the same periods in 2011. Realized derivative gains of $5.4 million and $9.9 million, respectively, for the three and six months ended June 30, 2012 are reported as a component of Derivative instruments within Revenues. For the three and six months ended June 30, 2011, the effects of natural gas hedging activities on natural gas revenues resulted in gains of $11.2 million and $21.4 million, respectively, and are reported as a component of Natural gas sales within Revenues.

Derivative Instruments. For the three and six months ended June 30, 2012, Derivative instruments included unrealized derivative gains of $72.5 million and $54.5 million, respectively, due to changes in fair value on commodity derivative contracts and reclassification of commodity hedging gains from Accumulated other comprehensive income, and realized derivative gains of $7.3 million and $9.2 million, respectively, from derivative settlements. These realized derivative gains represent cash settlements associated with our commodity derivative contracts. For the three and six months ended June 30, 2011, Derivative instruments included an unrealized derivative loss of $4.8 million associated with the change in fair value of our crude oil basis and NYMEX roll swaps. These instruments did not qualify for hedge accounting, and the associated derivative loss has been reclassified from Oil sales to Derivative instruments to conform to the current year presentation.

Operating Expenses

The following table presents information regarding our operating expenses:


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		% Change Increase/ (Decrease)			2012		2011		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)							(In thousands, except percentages and per unit amounts)
Lease operating expense	$	10,236	$	9,010		14	%	$	18,737	$	23,530		(20	%)
Treating and transportation		12,525		4,875		157	%		24,523		8,326		195	%
Production taxes		2,921		2,973		(2	%)		6,149		4,629		33	%
Depreciation, depletion and amortization (DD&A)		33,997		33,355		2	%		66,896		67,384		(1	%)
General and administrative costs		11,191		16,307		(31	%)		28,482		37,377		(24	%)

Costs and expenses (per Boe of production)
Lease operating expense	$	3.37	$	3.69		(9	%)	$	3.06	$	4.94		(38	%)
Treating and transportation		4.12		2.00		106	%		4.01		1.75		129	%
Production taxes		0.96		1.22		(21	%)		1.00		0.97		3	%
Depreciation, depletion and amortization (DD&A)		11.18		13.68		(18	%)		10.93		14.14		(23	%)
General and administrative costs		3.68		6.69		(45	%)		4.65		7.84		(41	%)
General and administrative costs, excluding stock-based compensation		3.66		4.41		(17	%)		3.76		4.46		(16	%)
Production costs (1)		13.72		16.51		(17	%)		13.17		17.93		(27	%)

(1)	Production costs per Boe includes lease operating expense and DD&A and excludes ad valorem taxes.

Lease Operating Expense. Lease operating expense increased $1.2 million and decreased $4.8 million, respectively, for the three and six months ended June 30, 2012 as compared to the same periods in 2011. The increase for the three months ended June 30, 2012 was a result of increased Eagle Ford operations, which contributed to an increase in direct lease operating expense of $3.1 million. The increase was partially offset by a $1.9 million decrease in direct lease operating expense attributable to the divestiture of dry gas properties. The decrease for the six months ended June 30, 2012 was primarily attributable to the divestiture of dry gas properties which contributed to a decline in direct lease operating expense, ad valorem taxes, workover expenses and insurance of $7.8 million, $3.3 million, $0.7 million and $0.1 million, respectively. The decrease was partially offset by increases in direct lease operating expense and ad valorem taxes of $4.2 million and $2.9 million, respectively, related to increased operations in the Eagle Ford shale.

Treating and Transportation. Treating and transportation expense increased $7.7 million and $16.2 million, respectively, for the three and six months ended June 30, 2012 compared to the same periods in 2011. The increases were a result of increased production in the Eagle Ford shale and accrued deficiency fees of $1.3 million and $2.6 million, respectively, related to shortfalls in delivering the minimum volumes required under our transportation and processing agreements during the three and six months ended June 30, 2012.

Production Taxes. Production taxes are highly correlated to commodity revenues, production volumes and commodity prices, which have impacted results for this expense item. Production taxes as a percentage of oil sales were 4.4% and 4.8%, respectively, for the three and six months ended June 30, 2012 compared to 7.4% and 6.7%, respectively, for the same periods in 2011. The decrease in rates was primarily due to an increased portion of our oil revenues being subject to taxation in the State of Texas and higher production tax incentives.

Depreciation, Depletion and Amortization (DD&A). DD&A expense increased $0.6 million and decreased $0.5 million, respectively, for the three and six months ended June 30, 2012 compared to the same periods in 2011. The increase for the three months ended June 30, 2012 was due to a 25% increase in production, partially offset by a lower DD&A rate driven by significant additions of proved reserves, primarily in the Gates Ranch area, in the second quarter of 2011 and the impact of asset divestitures. The decrease for the six months ended June 30, 2012 was due to a lower DD&A rate driven by significant additions of proved reserves, primarily in the Gates Ranch area, in the second quarter of 2011 and the impact of asset divestitures, partially offset by a 28% increase in production. The remainder of the decrease in DD&A was due to lower accretion and depreciation expense associated with facilities, ARO obligations and other fixed assets that were divested in 2011.

Costs associated with unevaluated properties are a significant input to our calculated DD&A rate (DD&A per Boe). Holding all other factors constant, an impairment of unevaluated properties will alter the relationship between the cost of developing reserves and the related reserve quantities and will therefore result in a higher DD&A rate. The recent impairment of our Southern Alberta Basin assets, and resulting transfer of $82.8 million to the full cost pool as of June 30, 2012, will result in an increase in our DD&A rate of up to 5% for the three months ended September 30, 2012.

General and Administrative Costs. General and administrative costs decreased $5.1 million and $8.9 million, respectively, for the three and six months ended June 30, 2012 as compared to the same periods in 2011. The decreases were primarily due to decreases of $5.5 million and $10.7 million, respectively, in stock-based compensation expense driven by the marked-to-market portion of our performance share units as a result of our lower stock price in 2012 as compared to 2011. The decreases were partially offset by increases of $0.4 million and $1.8 million, respectively, in other general and administrative expenses as compared to the same periods in 2011.

Total Other Expense

Total other expense, which includes Interest expense, net of interest capitalized; Interest income; and Other income/expense, net, increased $1.0 million and decreased $0.1 million, respectively, for the three and six months ended June 30, 2012 compared to the same periods in 2011.

In the second quarter of 2012, we entered into an amendment to our Restated Revolver which resulted in increased interest expense for the three and six months ended June 30, 2012 due to higher amortization of deferred financing fees and the write-off of certain deferred financing fees associated with our amended credit facility. The weighted average interest rate for the three and six months ended June 30, 2012 was 8.20% and 8.23%, respectively, compared to 8.65% and 8.04%, respectively, for the same periods in 2011 due to a higher proportional mix of debt outstanding under the Restated Term Loan and Senior Notes.

Provision for Income Taxes

The effective tax rate for both the three and six months ended June 30, 2012 was 36.2% and the effective tax rate for the three and six months ended June 30, 2011 was 35.9% and 34.2%, respectively. The provision for income taxes for the three and six months ended June 30, 2012 differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes and the non-deductibility of certain incentive compensation. As of June 30, 2012 and December 31, 2011, we had no unrecognized tax benefits and do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations within the next twelve months.

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. As of June 30, 2012, we had a net deferred tax asset of $29.2 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of our oil and natural gas properties. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income from the production of oil and natural gas properties prior to the expiration of loss carryforwards. We will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

Liquidity and Capital Resources

Our primary source of liquidity and capital is our operating cash flow and cash on hand. We also maintain a revolving line of credit, which can be accessed as needed to supplement operating cash flow.

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, as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of a portion of our production, 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 are discretionary and could be curtailed if our cash flows 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.

Senior Secured Revolving Credit Facility. On April 25, 2012, we entered into an amendment to our Restated Revolver. Under this amendment, among other things, our borrowing base was increased from $325.0 million to $625.0 million and our capacity to hedge production was increased. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements, as well as asset divestitures. The amount of the borrowing base is affected by a number of factors, including our level of reserves, as well as the pricing outlook at the time of the redetermination. Therefore, a significant reduction in capital spending could result in a reduced level of reserves that could cause a reduction in the borrowing base.

During the six months ended June 30, 2012, we repaid $70.0 million on the Restated Revolver. As of June 30, 2012, we had $90.0 million outstanding with $535.0 million of available borrowing capacity under the Restated Revolver. Amounts outstanding under the Restated Revolver bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of our domestic subsidiaries and a pledge of 100% of the membership and limited partnership interests of our domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to certain financial covenants such as the requirement to maintain a minimum 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 maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 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, 2012, our current ratio was 4.1 and our leverage ratio was 0.6. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties. We were in compliance with all covenants as of June 30, 2012.

In July 2012, we borrowed $30.0 million under the Restated Revolver, and our available borrowing capacity was reduced to $505.0 million.

Second Lien Term Loan. Our Restated Term Loan matures on October 2, 2012. As of June 30, 2012, we had $20.0 million of fixed rate borrowings outstanding under the Restated Term Loan bearing interest at 13.75%. We have the right to prepay the fixed rate borrowings outstanding with a make-whole amount at a discount factor equal to 1% plus the U.S. Treasury yield security having a maturity closest to the remaining life of the loan. The loan is collateralized by second priority liens on substantially all of our assets. We are also subject to certain financial covenants, including the requirement to maintain (i) a minimum reserve ratio of total reserve value to total debt of not less than 1.5 to 1.0 as of the end of each fiscal quarter and (ii) a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended. As of June 30, 2012, our reserve coverage ratio was 1.8 and our leverage ratio was 0.6. In addition, we are subject to covenants, including limitations on dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties. We were in compliance with all covenants as of June 30, 2012.

Senior Notes. On April 15, 2010, we issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes due 2018 in a private offering. The Senior Notes were issued under the Indenture with Wells Fargo Bank, National Association, as trustee. Provisions of the Indenture limit our ability to, among other things, incur additional indebtedness; pay dividends on our 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 our restricted subsidiaries to pay dividends, make loans or transfer property to us; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The Indenture also contains customary events of default. As of June 30, 2012, we were in compliance with the terms and provisions as contained within the Indenture. Interest is payable on the Senior Notes semi-annually on April 15 and October 15. On September 21, 2010, we exchanged all of the privately placed Senior Notes for registered Senior Notes which contain terms substantially identical to the terms of the privately placed notes.

Cash Flows

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


	Six Months Ended June 30,
	2012			2011
	(In thousands)
Cash provided by (used in):
Operating activities	$	155,289		$	130,464
Investing activities		(195,145	)		67,880
Financing activities		52,890			(105,300	)

Net increase in cash and cash equivalents	$	13,034		$	93,044

Operating Activities. Net cash provided by operating activities increased by $24.8 million for the six months ended June 30, 2012 compared to the same period in 2011. The increase primarily reflects higher operating income in 2012 as a result of higher oil and NGL production.

Investing Activities. Net cash used in investing activities increased by $263.0 million for the six months ended June 30, 2012 compared to the same period in 2011. The increase was primarily driven by higher capital spending in which we drilled 38 and completed 29 gross wells compared to 24 drilled and 25 completed gross wells, respectively, during the same period in 2011. In addition, we received lower proceeds from asset divestitures in 2012 as compared to 2011.

Financing Activities. Net cash provided by financing activities increased by $158.2 million for the six months ended June 30, 2012 compared to the same period in 2011. The increase was primarily related to net borrowings of $60.0 million under the Restated Revolver in 2012 as compared to net repayments of $100.0 million in 2011.

Capital Expenditures and Requirements

Our historical capital expenditures summary table is included in Items 1 and 2. Business and Properties in our 2011 Annual Report and is incorporated herein by reference.

Our capital expenditures for the six months ended June 30, 2012 increased by $98.9 million to $304.1 million from $205.2 million for the six months ended June 30, 2011. During the six months ended June 30, 2012, we drilled 38 and completed 29 gross wells, the majority of which were located in the Eagle Ford shale. At current commodity prices, our positive operating cash flow, proceeds from asset divestitures and liquidity from the Restated Revolver should be sufficient to fund planned capital expenditures for 2012, which are projected to be approximately $640 million. Our planned capital expenditures primarily reflect development drilling in the Eagle Ford.

We have the discretion to use availability under the Restated Revolver and proceeds from divestitures to fund capital expenditures. We also have the ability to adjust our capital investment plans throughout the remainder of the year in response to market conditions.

Fair Value of Financial Instruments

The energy markets have historically been very volatile, and oil, NGL and natural gas prices will be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management hedges oil, NGL and natural gas prices from time to time, primarily through the use of certain derivative instruments, including fixed price swaps, basis swaps, NYMEX roll swaps, costless collars and put options. 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, basis swaps, NYMEX roll swaps and costless collars for each year through 2014. Our fixed price swap, basis swap, NYMEX roll 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 expected production from existing wells at the inception of the derivative instruments. See Note 4 – Commodity Derivative Contracts and Other Derivatives and Note 5 – 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, 2012, a description of the applicable accounting and the estimated fair market values as of June 30, 2012. 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

Except as noted below, there have been no material changes in governmental regulations from those previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

Derivative Transactions. On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which, among other provisions, establishes federal oversight and regulation of the derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the legislation. Some rules have been finalized, while other rules are still in the proposed or earlier stages. The effect of the rules and any additional regulations on our business is currently uncertain. Some transactions that the Company engages in may be classified as derivatives such as swaps and options and therefore become subject to the CFTC’s jurisdiction and regulations. CFTC rules may require the Company to clear certain derivative instruments and comply with certain recordkeeping and reporting obligations. Additionally, the Company may be required to post margin for certain derivative instruments based on its credit support arrangements with its counterparties and may be unable to enter into certain transactions because of position limits imposed on physical commodities. These obligations could begin as early as October, 2012. The requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial and commercial risks related to fluctuations in oil, NGL and natural gas commodity prices. Any of the foregoing consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of generally accepted accounting principles 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 2011 Annual Report, except as disclosed below.

Derivative Transactions and Activities

Effective January 1, 2012, we elected to de-designate all of our commodity contracts that were previously designated as cash flow hedges as of December 31, 2011 and elected to discontinue hedge accounting prospectively. Accumulated other comprehensive income included $2.6 million ($1.6 million after tax) of unrealized gains, representing the marked-to-market value of our cash flow hedges as of December 31, 2011. As a result of discontinuing hedge accounting, the marked-to-market values included in Accumulated other comprehensive income as of the de-designation date were frozen and will be reclassified into earnings in future periods as the underlying hedged transactions affect earnings. During the three and six months ended June 30, 2012, we reclassified unrealized net gains of $1.1 million ($0.7 million after tax) and $1.2 million ($0.8 million after tax), respectively, into earnings from Accumulated other comprehensive income. We expect to reclassify an additional $1.5 million ($0.9 million after tax) of unrealized net gains during the last six months of 2012 and $0.1 million of unrealized net losses during 2013 into earnings from Accumulated other comprehensive income. With the election to de-designate hedging instruments, all of our derivative instruments continue to be recorded at fair value with unrealized gains and losses recognized immediately in earnings within Revenues—Derivative instruments on our Consolidated Statement of Operations, rather than in Accumulated other comprehensive income. Similar to our previous crude oil basis and NYMEX roll swap derivative instruments, these marked-to-market adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 2 – 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 and natural gas properties. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows. See Note 9 – Commitments and Contingencies included in Part I. Item 1. Financial Statements of this Form 10-Q.

We are party to various legal and regulatory proceedings 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, management does not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows.

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 2011 Annual Report and Note 4 – Commodity Derivative Contracts and Other Derivatives included in Part I. Item 1. Financial Statements of this Form 10-Q.

As of June 30, 2012, we had open crude oil derivative contracts in a net asset position with a fair value of $17.1 million. A ten percent increase in crude oil prices would reduce the fair value by approximately $11.1 million, while a ten percent decrease in crude oil prices would increase the fair value by approximately $12.6 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, 2012, we had open NGL derivative contracts in a net asset position with a fair value of $31.9 million. A ten percent increase in NGL prices would reduce the fair value by approximately $10.4 million, while a ten percent decrease in NGL prices would increase the fair value by approximately $10.4 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, 2012, we had open natural gas derivative contracts in an asset position with a fair value of $8.0 million. A ten percent increase in natural gas prices would reduce the fair value by approximately $1.1 million, while a ten percent decrease in natural gas prices would increase the fair value by approximately $1.1 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 expected, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement, or in the event of nonperformance under the contracts by the counterparties to our derivative agreements.

As of June 30, 2012, the Company’s derivative instruments are with counterparties who are lenders under the Company’s credit facilities or were lenders under the Company’s credit facilities upon origination of the derivative instrument. This 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 facilities, thus eliminating the need for independent collateral postings. As of June 30, 2012, we had no deposits for collateral regarding commodity derivative instruments. Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of June 30, 2012. We evaluated non-performance risk using the current credit default swap values for the counterparties and recorded a downward adjustment to the fair value of our derivative instruments in the amount of $0.7 million as of June 30, 2012.

We entered into oil, NGL and natural gas price derivative contracts with respect to a portion of our expected production through 2014. These derivative contracts may limit our potential revenue if oil, NGL and natural gas prices were to exceed the price established by the contract. As of June 30, 2012, 73% of our crude oil derivative transactions represented hedged prices of crude oil at the West Texas Intermediate on the NYMEX with the remaining 27% at Light Louisiana Sweet; 100% of the total NGL derivative transactions represented hedged prices of NGLs at Mont Belvieu, and 100% of total natural gas derivative transactions represented hedged prices of natural gas at the Houston Ship Channel.

We utilize counterparty and third party broker quotes to determine the valuation of our derivative instruments. Fair values derived from counterparties and brokers are further verified using relevant NYMEX futures contracts and exchange traded contracts, if deemed necessary, for each derivative settlement location. We have used this valuation technique since the adoption of the authoritative guidance for fair value measurements on January 1, 2008, and we have made no changes or adjustments to our technique since then. We mark-to-market the fair values of our derivative instruments on a quarterly basis and 100% of our commodity derivative assets and liabilities are 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, 2012. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2012, 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 the Company’s 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, 2012 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

We are party to various legal and regulatory proceedings arising in the ordinary 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, management does not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows.

Item 1A. Risk Factors

Except as disclosed below, there have been no material changes in our risk factors from those previously disclosed in Item 1A. of our 2011 Annual Report.

Our exploration and development activities may not be commercially successful.

Exploration and development activities involve numerous risks, including the risk that no commercially productive quantities of oil, NGLs and natural gas will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

•

Reductions in oil, NGL and natural gas prices;

•

Unexpected drilling conditions;

•

Pressure or irregularities in formations;

•

Disruptions to production from producing wells related to hydraulic fracturing operations in nearby wells;

•

Equipment failures, including corrosion of aging equipment, systems failures and extended downtime, or accidents;

•

Unavailability or high cost of drilling rigs, equipment or labor Reductions in oil, NGL and natural gas prices;

•

Lost or damaged oilfield development and services tools;

•

Limitations in midstream infrastructure or the lack of markets for oil, NGLs and natural gas;

•

Unavailability or high cost of processing and transportation;

•

Human error;

•

Community unrest;

•

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

•

Adverse weather conditions, including severe droughts resulting in new restrictions on water usage;

•

Environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

•

Compliance with environmental and other governmental regulations;

•

Possible federal, state, regional and municipal regulatory moratoriums on new permits, delays in securing new permits, changes to existing permitting requirements without “grandfathering” of existing permits and possible prohibition and limitations with regard to certain completion activities; and

•

Increase in severance taxes.

Our decisions to purchase, explore, develop and exploit prospects or properties depend, in part, on data obtained through geological and geophysical analyses, production data and engineering studies, the results of which are uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying potentially productive hydrocarbon traps and geohazards. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future financial position, results of operations and cash flows.

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, 2012:


Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
April 1 - April 30		818	$	49.49		—		—
May 1 - May 31		4,750		46.79		—		—
June 1 - June 30		746		36.98		—		—

Total		6,314	$	45.98		—		—

(1)

All of the shares were surrendered by our employees and directors to pay tax withholdings upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of common stock.

Issuance of Unregistered Securities

None.

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

10.51		Fifth Amendment to Amended and Restated Senior Revolving Credit Agreement, effective as of April 25, 2012, among Rosetta Resources Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (incorporated herein by reference to Exhibit 10.51 to the Company’s Current Report on Form 8-K filed on April 30, 2012 (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, Chief Financial Officer and Treasurer

(Duly Authorized Officer and Principal Financial Officer)

Date: August 7, 2012