Edgar Filing: Rosetta Resources Inc.

Large accelerated filer

Accelerated filer

Non-Accelerated filer

¨ (Do not check if smaller reporting company)

Smaller Reporting Company

Form 10-Q for quarterly period ended March 31, 2011

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 March 31, 2011

¨	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)

(Registrant’s telephone number, including area code) (713) 335-4000

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

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

The number of shares of the registrant’s Common Stock, $.001 par value per share, outstanding as of May 2, 2011 was 52,993,563.

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	16
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	26
	Item 4. Controls and Procedures	26
Part II –	Other Information
	Item 1. Legal Proceedings	27
	Item 1A. Risk Factors	27
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	27
	Item 3. Defaults upon Senior Securities	27
	Item 4. Removed and Reserved	27
	Item 5. Other Information	27
	Item 6. Exhibits	27
Signatures		29

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except par value and share amounts)


	March 31, 2011			December 31, 2010
	(Unaudited)

Assets
Current assets:
Cash and cash equivalents	$	81,904		$	41,634
Accounts receivable, net		48,399			44,028
Derivative instruments		5,154			19,145
Prepaid expenses		3,280			2,711
Other current assets		5,287			5,454
Deferred tax assets		407			—

Total current assets		144,431			112,972

Oil and natural gas properties, full cost method, of which $94,691 thousand at March 31, 2011 and $91,148 thousand at December 31, 2010 were excluded from amortization		2,296,563			2,262,161
Other fixed assets		15,031			14,459

		2,311,594			2,276,620
Accumulated depreciation, depletion, and amortization, including impairment		(1,578,714	)		(1,546,631	)

Total property and equipment, net		732,880			729,989

Deferred loan fees		7,033			7,652
Deferred tax asset		144,122			142,710
Derivative instruments		—			1,523
Other assets		2,482			2,463

Total other assets		153,637			154,348

Total assets	$	1,030,948		$	997,309


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	4,690		$	3,669
Accrued liabilities		101,991			57,006
Royalties payable		11,985			14,542
Derivative instruments		7,100			—
Prepayment on gas sales		6,534			7,869
Deferred income taxes		—			7,132

Total current liabilities		132,300			90,218

Long-term liabilities:
Derivative instruments		14,307			1,011
Long-term debt		350,000			350,000
Other long-term liabilities		19,055			27,264

Total liabilities		515,662			468,493


Commitments and Contingencies (Note 9)

Stockholders’ equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2011 or 2010		—			—
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 52,364,268 shares and 52,031,004 shares at March 31, 2011 and December 31, 2010, respectively		52			52
Additional paid-in capital		796,086			793,293
Treasury stock, at cost; 426,320 and 343,093 shares at March 31, 2011 and December 31, 2010, respectively		(10,232	)		(6,896	)
Accumulated other comprehensive (loss) income		(12,725	)		11,259
Accumulated deficit		(257,895	)		(268,892	)

Total stockholders’ equity		515,286			528,816

Total liabilities and stockholders’ equity	$	1,030,948		$	997,309

The accompanying notes to the financial statements are an integral part hereof.

Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2011			2010
Revenues:
Natural gas sales	$	49,780		$	55,807
Oil sales		28,749			6,983
NGL sales		18,542			7,358

Total revenues		97,071			70,148
Operating costs and expenses:
Lease operating expense		14,520			14,677
Depreciation, depletion, and amortization		34,029			23,814
Treating, transportation and marketing		3,451			1,481
Production taxes		1,656			2,290
General and administrative costs		21,070			11,807

Total operating costs and expenses		74,726			54,069

Operating income		22,345			16,079

Other (income) expense:
Interest expense, net of interest capitalized		6,346			4,746
Interest (income)		(28	)		(11	)
Other expense (income), net		273			(203	)

Total other expense		6,591			4,532


Income before provision for income taxes		15,754			11,547
Income tax expense		4,757			4,284

Net income	$	10,997		$	7,263


Earnings per share:
Basic	$	0.21		$	0.14

Diluted	$	0.21		$	0.14


Weighted average shares outstanding:
Basic		51,854			51,219
Diluted		52,521			51,920

The accompanying notes to the financial statements are an integral part hereof.

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities
Net income	$	10,997		$	7,263
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		34,029			23,814
Deferred income taxes		5,842			4,164
Amortization of deferred loan fees recorded as interest expense		595			481
Amortization of original issue discount recorded as interest expense		—			114
Stock compensation expense		10,590			2,631
Realized gain on derivative instruments		(2,867	)		—
Change in operating assets and liabilities:
Accounts receivable		(4,371	)		248
Prepaid expenses		(542	)		643
Other current assets		167			922
Other assets		(20	)		(8	)
Accounts payable		1,021			1,264
Accrued liabilities		759			(2,762	)
Royalties payable		(3,893	)		(1,894	)
Other long-term operating liabilities		(46	)		—

Net cash provided by operating activities		52,261			36,880

Cash flows from investing activities
Additions of oil and gas assets		(70,741	)		(73,591	)
Disposals of oil and gas properties and assets		60,953			21

Net cash used in investing activities		(9,788	)		(73,570	)

Cash flows from financing activities
Borrowings on revolving credit facility		—			25,000
Proceeds from stock options exercised		1,132			1,591
Purchases of treasury stock		(3,335	)		(1,250	)

Net cash (used in) provided by financing activities		(2,203	)		25,341


Net increase (decrease) in cash		40,270			(11,349	)
Cash and cash equivalents, beginning of period		41,634			61,256

Cash and cash equivalents, end of period	$	81,904		$	49,907


Supplemental disclosures:
Capital expenditures included in accrued liabilities	$	40,181		$	25,027

The accompanying notes to the financial statements are an integral part hereof.

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 oil and gas company engaged in onshore oil and natural gas exploration, development, production and acquisition activities in the United States. The Company’s operations are concentrated in South Texas, primarily 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 United States of America. 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, 2010 (“2010 Annual Report”).

Certain reclassifications of prior year balances have been made to conform them to the current year presentation. 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 2010 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 January 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures will be required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance requires additional disclosures but did not impact our consolidated financial position, results of operations or cash flows. See Note 5 – Fair Value Measurements.

(3) Property and Equipment

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


	March 31, 2011			December 31, 2010
	(In thousands)
Proved properties	$	2,161,349		$	2,124,615
Unproved/unevaluated properties		94,691			91,148
Gas gathering system and compressor stations		40,523			46,398
Other fixed assets		15,031			14,459

Total property and equipment, gross		2,311,594			2,276,620
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,578,714	)		(1,546,631	)

Total property and equipment, net	$	732,880		$	729,989

As part of our strategic decision to focus on the development of the Eagle Ford shale, the Company executed a purchase and sale agreement on February 22, 2011 for $55.0 million for the divestiture of the DJ Basin assets in Colorado. The sale of these assets closed on March 31, 2011 with an effective date of January 1, 2011 and the agreement was subject to due diligence and post-closing purchase price adjustments. Proceeds from the divestiture were recorded as an adjustment to the full cost pool with no gain or loss recognized.

Subsequently, on February 24, 2011, the Company executed a purchase and sale agreement for $200.0 million for the divestiture of the Sacramento Basin assets in California. The sale of these assets closed on April 15, 2011 with an effective date of January 1, 2011. The agreement was also subject to post-closing purchase price adjustments. Approximately $43.6 million associated with a certain portion of the properties was placed in escrow pending the Company’s receipt of appropriate consents for assignment. On April 25, 2011 and May 4, 2011, the Company closed on a portion of the properties for which consents were received after the first closing. The Company has accordingly received from the escrow account approximately $7.8 million and $5.6 million, respectively, for these properties, which have been conveyed to the buyer. Once the Company is in receipt of the outstanding consents, title to these remaining properties will be released to the purchaser and the residual escrowed funds will be remitted to the Company. The completion of the remaining transaction is anticipated to occur in the third quarter of 2011. The Company does not expect a gain or a loss to be recognized as a result of this transaction and the proceeds will be recorded as an adjustment to the full cost pool.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.5 million and $1.7 million of internal costs for the three months ended March 31, 2011 and 2010, respectively.

Included in the Company’s oil and gas properties are asset retirement costs of $18.0 million and $18.7 million as of March 31, 2011 and December 31, 2010, respectively.

Oil and gas properties include costs of $94.7 million and $91.1 million as of March 31, 2011 and December 31, 2010, 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. The increase from December 31, 2010 to March 31, 2011 is a result of leasehold acquisitions and the costs associated with unevaluated wells in the Southern Alberta Basin and in the Eagle Ford shale.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its oil and gas assets within each separate cost center. The Company’s ceiling test was calculated using a trailing twelve-month, unweighted-average first-day-of-the-month price, adjusted for hedges, of gas and oil as of March 31, 2011, which were based on a Henry Hub gas price of $4.10 per MMBtu and a West Texas Intermediate oil price of $80.04 per Bbl (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 at March 31, 2011. It is possible that a write-down of the Company’s oil and gas properties could occur in the future should oil and natural gas prices decline, the Company experiences significant downward adjustments to its estimated proved reserves, and/or the Company’s commodity hedges settle and are not replaced.

In 2010, the Company’s ceiling test was also calculated using a trailing twelve-month, unweighted-average first-day-of-the-month price, adjusted for hedges, of gas and oil as of March 31, 2010, which were based on a Henry Hub gas price of $3.98 per MMBtu and a West Texas Intermediate oil price of $66.13 per Bbl (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount also exceeded the net capitalized cost of oil and gas properties. As a result, no write-down was recorded for the quarter ended March 31, 2010.

(4) Commodity Hedging Contracts and Other Derivatives

At March 31, 2011, the following financial fixed price swap and costless collar transactions 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	Hedge Strategy	Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu		Average Ceiling Prices per MMBtu		Fair Market Value Asset/(Liability) (In thousands)
Natural gas		2011	Swap	Cash flow		15,000		4,125,000	$	5.99	$	—	$	6,058
Natural gas		2011	Costless Collar	Cash flow		35,000		9,625,000		5.79		7.27		11,905
Natural gas		2012	Costless Collar	Cash flow		20,000		7,320,000		5.13		6.31		3,571

								21,070,000					$	21,534


Product	Settlement Period		Derivative Instrument	Hedge Strategy	Notional Daily Volume Bbl		Total of Notional Volume Bbl		Average Floor/Fixed Prices per Bbl		Average Ceiling Prices per Bbl		Fair Market Value Asset/ (Liability) (In thousands)
Crude oil		2011	Costless Collar	Cash flow		3,400		935,000	$	75.59	$	103.29	$	(9,291	)
Crude oil		2012	Costless Collar	Cash flow		3,400		1,244,400		75.88		108.00		(11,070	)
Crude oil		2013	Costless Collar	Cash flow		2,600		949,000		75.00		124.65		(2,226	)

								3,128,400					$	(22,587	)


NGL - Propane		2011	Swap	Cash flow		1,000		275,000	$	47.98	$	—	$	(2,800	)
NGL - Isobutane		2011	Swap	Cash flow		270		74,250		64.02		—		(1,234	)
NGL - Normal Butane		2011	Swap	Cash flow		330		90,750		63.79		—		(1,298	)
NGL - Pentanes Plus		2011	Swap	Cash flow		400		110,000		83.04		—		(2,385	)
NGL - Propane		2012	Swap	Cash flow		1,000		366,000		47.20		—		(3,253	)
NGL - Isobutane		2012	Swap	Cash flow		260		95,160		66.63		—		(980	)
NGL - Normal Butane		2012	Swap	Cash flow		280		102,480		65.30		—		(996	)
NGL - Pentanes Plus		2012	Swap	Cash flow		410		150,060		86.62		—		(2,254	)

								1,263,700					$	(15,200	)

The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities. This eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations. As of March 31, 2011, the Company had no deposits for collateral in regards to commodity hedge positions.

The following table sets forth the results of derivative settlements for the respective periods as reflected in the Consolidated Statement of Operations:


	Three Months Ended March 31,
	2011			2010
Natural Gas
Quantity settled (MMBtu)		4,500,000			2,250,000
Increase in natural gas sales revenue (In thousands) (1)	$	7,271		$	2,877
Crude Oil
Quantity settled (Bbl)		24,800			—
Decrease in crude oil sales revenue (In thousands)	$	(321	)	$	—
NGL
Quantity settled (Bbl)		63,000			—
Decrease in NGL sales revenue (In thousands)	$	(1,186	)	$	—
Interest Rate Swaps
(Increase) in interest expense (In thousands)	$	—		$	(252	)

(1)	Excludes approximately $2.9 million of realized gain associated with the 2011 terminations of derivatives used to hedge production from divested DJ Basin properties.

As of March 31, 2011, the Company expects to reclassify net losses of $1.9 million from Accumulated other comprehensive income on the Consolidated Balance Sheet to earnings based upon settlement dates in the next twelve months and based upon current forward prices as of March 31, 2011.

Subsequent to March 31, 2011, the Company terminated existing hedge transactions and entered into additional hedging transactions to hedge a portion of expected future natural gas production. See Note 15 – Subsequent Events.

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed through derivative instruments are commodity price risk and interest rate risk. Forward contracts on various commodities are entered into to manage the price risk associated with forecasted sales of the Company’s natural gas, oil and NGL production. Interest rate swaps are utilized to manage interest rate risk associated with the Company’s variable-rate borrowings.

Authoritative guidance for derivatives requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the statement of financial position. In accordance with this guidance, the Company designates commodity forward contracts as cash flow hedges of forecasted sales of natural gas, oil and NGL production and interest rate swaps as cash flow hedges of interest rate payments due under variable-rate borrowings.

Additional Disclosures about Derivative Instruments and Hedging Activities

Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

As of March 31, 2011, the Company had outstanding natural gas, oil and NGL commodity forward contracts with notional volumes of 21,070,000 MMBtus, 3,128,400 Bbls and 1,263,700 Bbls, respectively, that were entered into to hedge forecasted natural gas, oil and NGL sales.

Information on the location and amounts of derivative fair values in the Consolidated Balance Sheet as of March 31, 2011 and December 31, 2010 and derivative gains and losses in the Consolidated Statement of Operations for the three months ended March 31, 2011 and 2010, respectively, is as follows:


	Fair Values of Derivative Instruments
	Derivative Assets (Liabilities)
	Balance Sheet Location	Fair Value
		March 31, 2011			December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments

Commodity contracts - natural gas	Derivative instruments - current assets		11,069			24,959
Commodity contracts - natural gas	Derivative instruments - non-current assets		—			3,614
Commodity contracts - crude oil	Derivative instruments - current assets		—			(2,696	)
Commodity contracts - crude oil	Derivative instruments - non-current assets		—			(2,207	)
Commodity contracts - NGL	Derivative instruments - current assets		(5,915	)		(3,118	)
Commodity contracts - NGL	Derivative instruments - non-current assets		—			116
Commodity contracts - natural gas	Derivative instruments - current liabilities		7,741			—
Commodity contracts - natural gas	Derivative instruments - long-term liabilities		2,725			—
Commodity contracts - crude oil	Derivative instruments - current liabilities		(11,410	)		—
Commodity contracts - crude oil	Derivative instruments - long-term liabilities		(11,178	)		—
Commodity contracts - NGL	Derivative instruments - current liabilities		(3,431	)		—
Commodity contracts - NGL	Derivative instruments - long-term liabilities		(5,854	)		(1,011	)


Total derivatives designated as hedging instruments		$	(16,253	)	$	19,657


Total derivatives not designated as hedging instruments		$	—		$	—


Total derivatives		$	(16,253	)	$	19,657


Derivatives in Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)			Location of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (1)
Derivatives in Cash Flow Hedging Relationships	Three Months Ended March 31, 2011				Three Months Ended March 31, 2011				Three Months Ended March 31, 2011
	(In thousands)				(In thousands)				(In thousands)

Commodity contracts - natural gas		656		Natural gas sales		7,271		Natural gas sales		2,867
Commodity contracts - crude oil		(18,005	)	Crude oil sales		(321	)	Crude oil sales		—
Commodity contracts - NGL		(12,373	)	NGL sales		(1,186	)	NGL sales		—


Total	$	(29,722	)	Total	$	5,764		Total	$	2,867


Derivatives in Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)			Location of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in Cash Flow Hedging Relationships	Three Months Ended March 31, 2010				Three Months Ended March 31, 2010				Three Months Ended March 31, 2010
	(In thousands)				(In thousands)				(In thousands)

Interest rate swap	$	(263	)	Interest expense, net of interest capitalized	$	(252	)	Interest expense, net of interest capitalized	$	—
Commodity contracts - natural gas		32,513		Natural gas sales		2,877		Natural gas sales		—
Commodity contracts - crude oil		—		Crude oil sales		—		Crude oil sales		—
Commodity contracts - NGL		—		NGL sales		—		NGL sales		—

Total	$	32,250		Total	$	2,625		Total	$	—

(1)	This amount represents the realized gain which resulted from the 2011 terminations of derivatives used to hedge production from divested DJ Basin properties.

(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. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. As none of the Company’s non-financial assets and liabilities were impaired during the period ended March 31, 2011, and the Company had no other material assets or liabilities that are reported at fair value on a non-recurring basis, no additional disclosures are provided as of March 31, 2011.

As defined in the 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 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.

Level 3 instruments include money market funds, natural gas and NGL fixed price swaps and natural gas and crude oil zero cost collars. The Company’s money market funds represent cash equivalents whose investments are limited to United States

Government Securities, securities backed by the United States Government, or securities of United States Government agencies. The fair value represents cash held by the fund manager as of March 31, 2011 and December 31, 2010. The Company identified the money market funds as Level 3 instruments due to the fact that quoted prices for the underlying investments cannot be obtained and there is not an active market for the underlying investments. The Company utilizes, as one of its inputs, counterparty and third party broker quotes to determine the valuation of its derivative instruments. Fair values derived from counterparties and brokers are further verified using relevant New York Mercantile Exchange (“NYMEX”) futures contracts and exchange traded contracts for each derivative settlement location.

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 as of March 31, 2011. 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.


	Fair value as of March 31, 2011
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (liabilities):
Money market funds	$	—	$	—	$	1,035		$	1,035
Commodity derivative contracts		—		—		(16,253	)		(16,253	)

Total	$	—	$	—	$	(15,218	)	$	(15,218	)


	Fair value as of December 31, 2010
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (liabilities):
Money market funds	$	—	$	—	$	1,035		$	1,035
Commodity derivative contracts		—		—		19,657			19,657

Total	$	—	$	—	$	20,692		$	20,692

The determination of the fair values above incorporates various factors. These factors include the credit standing of the counterparty involved, the impact of credit enhancements and the impact of the Company’s nonperformance risk on its liabilities. The Company considered credit adjustments for the counterparties using the current credit default swap value and default probability for the Company in determining fair value and recorded a downward adjustment to the fair value of its derivative liabilities in the amount of $0.3 million at March 31, 2011.

The tables below present reconciliations of the assets and liabilities classified as Level 3 in the fair value hierarchy during the quarters ended March 31, 2011 and 2010. Level 3 instruments presented in the table consist of net derivatives and money market funds that, in management’s judgment, reflect the assumptions a marketplace participant would have used at March 31, 2011 and 2010.


	For the Three Months Ended March 31, 2011
	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 (1)		(424	)		—		(424	)
Included in Other Comprehensive Income		(29,722	)		—		(29,722	)
Purchases, Issuances and Settlements
Settlements		(8,631	)		—		(8,631	)
Purchases		2,867			—		2,867
Transfers in and out of Level 3		—			—		—

Balance at March 31, 2011	$	(16,253	)	$	1,035	$	(15,218	)


	For the Three Months Ended March 31, 2010
	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)		Total
	(In thousands)

Balance at January 1, 2010	$	6,787		$	2,035	$	8,822
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings (1)		—			—		—
Included in Other Comprehensive Income		32,250			—		32,250
Purchases, Issuances and Settlements		(2,625	)		—		(2,625	)
Transfers in and out of Level 3		—			—		—

Balance at March 31, 2010	$	36,412		$	2,035	$	38,447

(1)	No gains or losses were included in earnings attributable to the change in unrealized gains or losses relating to financial assets and liabilities still held at the end of the period.

As of March 31, 2011, the carrying value of cash and cash equivalents, accounts receivable, other current assets and current liabilities reported in the consolidated balance sheet approximate fair value because of their short-term nature. The carrying amount of long-term debt reported in the consolidated balance sheet as of March 31, 2011 is $350.0 million. The Company calculated the fair value of its long-term debt as of March 31, 2011, in accordance with the authoritative guidance for fair value measurements using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality, and risk profile. Based on this calculation, the Company has determined the fair market value of its debt to be $378.0 million at March 31, 2011.

(6) Asset Retirement Obligations

The following table provides a roll forward of the asset retirement obligations. Liabilities incurred during the period include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. 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:


	Three Months Ended March 31, 2011
	(In thousands)
ARO as of December 31, 2010	$	27,934
Revision of previous estimates		—
Liabilities incurred during period		8
Liabilities settled during period		(710	)
Accretion expense		505

ARO as of March 31, 2011	$	27,737

As of March 31, 2011, the current portion of the total ARO is approximately $9.4 million and is included in Accrued liabilities and the long-term portion of ARO is approximately $18.3 million and is included in Other long-term liabilities on the Consolidated Balance Sheet.

(7) Long-Term Debt

Senior Secured Revolving Credit Facility. The Company’s amended and restated revolving credit agreement (the “Restated Revolver”) provides for a senior secured revolving line of credit of up to $600.0 million and matures on July 1, 2012. 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 borrowing base is dependent on a number of factors, including the Company’s level of reserves as well as the pricing outlook at the time of the redetermination. A reduction in capital spending could result in a reduced level of reserves thus causing a reduction in the borrowing base.

As of March 31, 2011, the Company had $130.0 million outstanding with $195.0 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 2.25% to 3.00%. 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 the financial covenants as defined in the credit agreement. The terms of the agreement require the maintenance of 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 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. At March 31, 2011, the Company’s current ratio was 2.6 and the leverage ratio was 1.5. 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. The Company was in compliance with all covenants at March 31, 2011.

The Company’s semi-annual borrowing base review was completed on April 19, 2011 and the borrowing base was confirmed by the lenders at $325.0 million. The confirmed borrowing base reflects the Sacramento Basin and DJ Basin divestitures as well as positive factors such as increased production from the Eagle Ford shale and increased levels of reserves. On April 21, 2011, the Company utilized a portion of asset divestiture proceeds and repaid $100.0 million of outstanding debt under the Restated Revolver. As of May 2, 2011, the Company had $30.0 million outstanding, with $295.0 million available for borrowing under the Restated Revolver.

Second Lien Term Loan. The Company’s amended and restated term loan (the “Restated Term Loan”) matures on October 2, 2012. As of March 31, 2011, the Company had $20.0 million of fixed rate borrowings outstanding bearing interest at 13.75% under the Restated Term Loan. The loan is collateralized by second priority liens on substantially all of the Company’s assets. The Company is subject to the financial covenants as defined in the term loan agreement. The Company is required under the term loan agreement 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. At March 31, 2011, the Company’s reserve coverage ratio was 2.4 and the leverage ratio was 1.5. 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. The Company was in compliance with all covenants at March 31, 2011. The Company also 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.

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. Proceeds from the Senior Notes offering were used to repay $114.0 million outstanding under the Restated Revolver and $80.0 million of variable rate borrowings outstanding under our Restated Term Loan and to pay for fees and expenses associated with the offering. 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 March 31, 2011, the Company had total outstanding borrowings of $350.0 million and for the year ended March 31, 2011, the Company’s weighted average borrowing rate was 7.10%.

(8) Income Taxes

The effective tax rate for the three months ended March 31, 2011 and 2010 was 30.2% and 37.1%, respectively. The provision for income taxes for the three months ended March 31, 2011 differs from the tax computed at the federal statutory income tax rate primarily due to the non-deductibility of certain incentive compensation and an approximate $0.9 million adjustment for 2010 federal income taxes that should have been recorded in the fourth quarter of 2010. We have determined that the impact of the 2010 tax adjustment was immaterial to our results of operations in all applicable prior interim and annual periods as well as to the projected results of operations for 2011. For the three months ended March 31, 2010, the provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes. As of March 31, 2011 and December 31, 2010, 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 statute of limitations 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 March 31, 2011, the Company has a deferred tax asset of $144.1 million resulting primarily from the difference between the book basis and

tax basis of oil and natural gas properties and net operating loss carryforwards. 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.

In connection with the planned asset divestitures in the DJ Basin in Colorado and in the Sacramento Basin in California, the Company concluded that it is more likely than not that the deferred tax assets for these states including NOLs will not be realized. Therefore, valuation allowances were established at December 31, 2010 for these items as well as state NOLs in other jurisdictions in which the Company previously operated but has since divested of operating assets. 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

The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and 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) Comprehensive Income (Loss)

For the periods indicated, the Company’s Accumulated other comprehensive income consisted of the following:


	Three Months Ended March 31,
	2011						2010
	(In thousands)
Accumulated other comprehensive income, beginning of period				$	11,259					$	4,259
Net income	$	10,997					$	7,263

Change in fair value of derivative hedging instruments	$	(29,722	)				$	32,250
Hedge settlements reclassed to income		(8,631	)					(2,625	)
Tax provision related to hedges		14,369						(11,036	)

Total other comprehensive (loss) income	$	(23,984	)	$	(23,984	)	$	18,589		$	18,589


Comprehensive (loss) income	$	(12,987	)				$	25,852

Accumulated other comprehensive (loss) income, end of period				$	(12,725	)				$	22,848

(11) Earnings Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted earnings per share 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 March 31,
	2011		2010
	(In thousands)
Basic weighted average number of shares outstanding		51,854		51,219
Dilution effect of stock option and awards at the end of the period		667		701

Diluted weighted average number of shares outstanding		52,521		51,920


Anti-dilutive stock awards and shares		27		111

(12) Geographic Area Information

The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with authoritative guidance regarding disclosure about segments of an enterprise and related information. Also, as all of the Company’s operations are located in the United States, all of the Company’s costs are included in one cost pool.

Geographic Area Information

The Company owns oil and natural gas interests in six main geographic areas, all within the United States or its territorial waters. Geographic revenue information below is based on physical location of the assets at the end of each period. Certain amounts in prior periods have been reclassified to conform to the current presentation.


	Three Months Ended March 31,
	2011 (1)		2010 (1)
	(In thousands)
Natural gas, Oil and NGL Revenue
Eagle Ford	$	59,940	$	4,322
South Texas		12,676		26,353
California (2)		11,951		21,397
Rockies (2)		3,434		8,517
Gulf Coast		440		4,150
Other Onshore		—		2,532


Total revenue, excluding gains on hedges	$	88,441	$	67,271

(1)	Excludes the effects of hedging gains of $8.6 million and $2.9 million for the three months ended March 31, 2011 and 2010, respectively.

(2)

The California and Rockies assets include the Sacramento Basin and DJ Basin assets. The DJ Basin assets were sold during the three months ended March 31, 2011 and the Sacramento Basin assets were sold in April 2011. See Note 3 – Property and Equipment and Note 15- Subsequent Events. The decline in revenues is primarily due to the suspension of drilling programs in these areas that produce primarily from dry gas reservoirs.

(13) Restructuring and Reorganization Costs

In 2010, the Company announced an office closure affecting the Denver office and the restructuring and reorganization of Houston personnel as a result of strategic asset divestitures. All affected positions are located in the United States. Of the total 44 employees covered under the programs, 40 employees have been terminated and the programs are expected to be completed by the end of 2011.

A before-tax charge of $0.8 million ($0.5 million after-tax) was recorded in the first quarter of 2011 as General and administrative costs on the Consolidated Statement of Operations. The associated accrued liability is classified as current on the Consolidated Balance Sheet. Of the expenses incurred during the three months ended March 31, 2011, approximately $0.5 million related to severance costs, $0.2 million related to the cease-use of the Denver office space and approximately $0.1 million related to relocation costs. While all future costs associated with the restructuring and reorganization cannot be fully anticipated, the total amount estimated that will be incurred is approximately $5.0 million.

During the three months ended March 31, 2011, the Company made payments of approximately $2.7 million associated with these liabilities.


	Amounts before tax
	(In thousands)
Balance at January 1, 2011	$	3,224
Accruals		760
Adjustments		—
Payments		(2,740	)

Balance at March 31, 2011	$	1,244

(14) 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

subsidiaries of Rosetta Resources Inc. other than the subsidiary guarantors are minor. In addition, there are no restrictions on the ability of Rosetta Resources Inc. to obtain funds from its subsidiaries by dividend or loan. Finally, none of Rosetta Resources Inc.’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 parent company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

(15) Subsequent Events

On April 13, 2011, the Company terminated its 25,000 MMbtu/d costless collars priced at PG&E Citygate in anticipation of the close of the sale of the Sacramento Basin assets on April 15, 2011. In consideration for these terminated hedges, the Company entered into additional costless collar transactions to hedge 25,000 MMbtu/d of its natural gas production priced at Houston Ship Channel for the period May 2011 through December 2011. The new costless collars have an average floor price of $5.58 per MMbtu and an average ceiling price of $7.58 per MMbtu.

The Company closed the sale of the Sacramento Basin assets on April 15, 2011. The divestiture for $200.0 million was effective as of January 1, 2011 and is subject to post-closing purchase price adjustments. Under the terms of the closing, approximately $43.6 million associated with a certain portion of the properties was placed in escrow pending the Company’s receipt of appropriate consents for assignment. On April 25, 2011 and May 4, 2011, the Company closed on a portion of the properties for which consents were received after the first closing. The Company has accordingly received from the escrow account approximately $7.8 million and $5.6 million, respectively, for these properties, which have been conveyed to the buyer. Once the Company is in receipt of the outstanding consents, title to these remaining properties will be released to the purchaser and the residual escrowed funds will be remitted to the Company. The completion of the remaining transaction is anticipated to occur in the third quarter of 2011.

On April 19, 2011, the Company’s semi-annual borrowing base review was completed and the borrowing base under the Restated Revolver was confirmed at $325.0 million. The confirmed borrowing base reflects the Sacramento Basin and DJ Basin divestitures as well as positive factors such as increased production from the Eagle Ford shale and increased levels of reserves.

The Company utilized a portion of asset divestiture proceeds to repay $100.0 million of outstanding debt under the Restated Revolver on April 21, 2011.

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 2010 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 natural gas, oil and NGLs;

•

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

•

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;

•

changes or advances in technology;

•

potential reserve revisions;

•

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

•

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

•

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

•

present and possible future claims, litigation and enforcement actions;

•

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

•

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

•

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; and

•

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

Overview

The following discussion addresses material changes in our results of operations for the three months ended March 31, 2011 compared to the three months ended March 31, 2010, and material changes in our financial condition since December 31, 2010. This discussion includes the operations of our DJ Basin and Sacramento Basin assets which were divested in March and April 2011 and should be read in conjunction with our 2010 Annual Report, which includes as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations disclosures regarding critical accounting policies.

The following summarizes our performance for the three months ended March 31, 2011 as compared to the same period for 2010:

•

production on a Bcfe basis increased 25% to 14.0 Bcfe for the three months ended March 31, 2011 from 11.2 Bcfe for the three months ended March 31, 2010;

•

11 gross (11 net) wells were drilled with a net success rate of 100% for the three months ended March 31, 2011 compared to 36 gross (35 net) wells drilled with a net success rate of 97% for the same period in 2010;

•

49% of revenue for the three months ended March 31, 2011 was generated from crude oil, condensate and NGL sales as compared to 20% for the same period in 2010, reflecting our shift to a higher total liquids mix;

•

average realized gas prices, including hedging, decreased $0.51 per Mcf, or 9%, to $5.30 per Mcf for the three months ended March 31, 2011 from $5.81 per Mcf for the three months ended March 31, 2010;

•

average realized oil prices, including hedging, increased $8.45 per Bbl, or 11%, to $84.68 per Bbl for the three months ended March 31, 2011 from $76.23 per Bbl for the three months ended March 31, 2010;

•

average realized NGL prices, including hedging, decreased $0.47 per Bbl, or 1%, to $44.02 per Bbl for the three months ended March 31, 2011 from $44.49 per Bbl for the three months ended March 31, 2010;

•

total revenue, including the effects of hedging, increased $27.0 million, or 38%, to $97.1 million for the three months ended March 31, 2011 from $70.1 million for the three months ended March 31, 2010; and

•

diluted earnings per share increased $0.07 to $0.21 for the three months ended March 31, 2011 from $0.14 for the three months ended March 31, 2010.

Rosetta entered 2011 positioned as an unconventional resource player with a portfolio of high-quality shale assets and a project inventory offering visible and sustainable growth. Our success was the result of a transition which began three years ago to change our business model from a primarily natural gas-focused operator in more mature U.S. basins to that of an unconventional resource company with a significant position in emerging U.S. shale plays.

We were an early entrant into the Eagle Ford shale in South Texas, accumulating a significant leasehold position during 2008 and 2009 in the highly-competitive industry play. Our efforts were underpinned with a conservative fiscal approach and a focus on cost control and efficiency. Overall, we now hold approximately 65,000 net acres with roughly 50,000 net acres located in the liquids-rich area of the play. Our 2010 activities were focused in the Gates Ranch area in Webb county where we successfully delineated a 26,500-acre position within the Gates Ranch. Well results have exceeded expectations and the Eagle Ford shale has become our largest producing area. More than 57% of our total production for the three months ended March 31, 2011 is from the Eagle Ford shale and approximately 51% of that amount was from crude oil, condensate and natural gas liquids.

The timely and efficient development of our Eagle Ford resources remains challenging in a region where oilfield services are in high demand and infrastructure is still under construction. In response, Rosetta has entered into long-term contracts for firm transportation and processing capacity to reduce our exposure to production constraints. We also have secured firm processing capacity agreements with multiple providers to meet our projected growth in volumes from the area.

During 2011, we plan approximately 40 completions in the Eagle Ford shale and have a fracture stimulation agreement in place to handle the increased activity. More than 90 percent of our announced $360 million capital program for the year will be allocated toward development of the area. We believe that the program economics of the Eagle Ford play provide some of the strongest returns among U.S. onshore basins and our progress in the area will further shift our product mix toward a higher percentage of liquids.

Our other shale focus area lies in the Southern Alberta Basin in northwest Montana. Rosetta holds approximately 300,000 net acres in the play that we believe is an analog to the prolific Williston Basin. In late 2009, we began a vertical drilling program to assess the commerciality of the play. As of March 31, 2011, eight vertical delineation wells had been drilled. Another three wells are planned for the second quarter of 2011 as well as fracture stimulation on up to eight of the eleven wells. The evaluation of the results of this program will be used to design a horizontal drilling program that we expect to commence in the second quarter of 2011.

With the success of our shale activities, we have divested assets that no longer fit our operating model and plan to redeploy the proceeds into our growth shale activities. During 2010, we raised approximately $90 million through the sale of properties in Arkansas, Oklahoma, Mississippi, Texas, Louisiana, New Mexico and Wyoming. In February 2011, we announced the divestiture of assets in the DJ Basin in Colorado and the Sacramento Basin in California for a total sales price of $255 million, subject to customary adjustments. These closings concluded on March 31, 2011 and April 15, 2011, respectively, with an effective date of January 1, 2011. In light of the

favorable timing of these sales, Rosetta is currently reviewing its capital program with the option of directing more funds to its Eagle Ford and Southern Alberta Basin growth efforts.

At this time, we believe that Rosetta has sufficient internal investment opportunities to grow without acquiring additional properties. However, we continue to evaluate opportunities that fit our business model and our strategic and economic objectives.

While our unconventional resource strategy is proving 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 our 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 toward crude oil, condensate and natural gas liquids that continue to be priced at more favorable levels than natural gas. With increasing industry activity in the Eagle Ford shale, our largest producing area, we have taken aggressive steps to ensure access to necessary services and infrastructure.

As part of our transition to an unconventional resource player, we announced the closing of our Denver office and the reorganization of Houston personnel starting in 2010. Since the initiation of the restructuring, we have incurred approximately $4.2 million of expenses primarily related to severance costs and the cease-use of our Denver office lease. We expect the reorganization to be completed by December 31, 2011 and while all future costs associated with the reorganization cannot be fully anticipated, we estimate that we will incur total costs of approximately $5.0 million. We believe the consolidation of our technical resources to Houston will enable us to capitalize on the dynamics and efficiencies of operating in a central location.

We are confident that we can execute our 2011 capital program from internally generated cash flows, cash on hand and the proceeds from our asset divestitures. We monitor our liquidity continuously and will respond to changing market conditions, commodity prices or service costs. In the event we encounter a situation in which there is not sufficient internal funds to meet projected funding, we would consider curtailing our capital spending, drawing on the unused capacity under our existing revolving credit facility or accessing capital markets.

Our semi-annual borrowing base redetermination was completed in April 2011 and our borrowing base under the Restated Revolver has been reconfirmed by our lenders at $325.0 million. The redetermination of our borrowing base took into consideration the impact of our Sacramento Basin and DJ Basin asset divestitures as well as our increased production and levels of reserves. There has not been any indication that draws under our Restated Revolver will be restricted below current availability or that outstanding balances will be called immediately due by our lenders. In connection with our asset divestitures, we utilized $100.0 million of asset divestiture proceeds to reduce our outstanding debt associated with this debt facility. As of May 2, 2011, we had $30.0 million outstanding, with $295.0 million available for borrowing under the Restated Revolver.

Results of Operations

Revenues

Our revenues are derived from the sale of our natural gas, oil and NGL production, which includes the effects of qualifying commodity hedge contracts. Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold.

Total revenue, including the effects of hedging, for the three months ended March 31, 2011 was $97.1 million, which is an increase of $27.0 million, or 38%, from $70.1 million for the three months ended March 31, 2010. Total revenue, excluding the effects of hedging, for the three months ended March 31, 2011 was $88.4 million, which is an increase of $21.1 million, or 31%, from $67.3 million for the three months ended March 31, 2010. Approximately 49% of our revenue for the three months ended March 31, 2011 was attributable to oil and NGL sales as compared to 20% for the same period in 2010.

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


	Three Months Ended March 31,
	2011		2010		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Revenues:
Natural gas sales	$	49,780	$	55,807		(11	%)
Oil sales		28,749		6,983		312	%
NGL sales		18,542		7,358		152	%

Total revenue	$	97,071	$	70,148		38	%


Production:
Gas (Bcf)		9.4		9.6		(2	%)
Oil (MBbls)		339.5		91.6		271	%
NGLs (MBbls)		421.2		165.4		155	%
Total Equivalents (Bcfe)		14.0		11.2		25	%

$ per unit:
Avg. natural gas price per Mcf, excluding hedging	$	4.22	$	5.51		(23	%)
Avg. natural gas price per Mcf		5.30		5.81		(9	%)
Avg. oil price per Bbl, excluding hedging		85.63		76.23		12	%
Avg. oil price per Bbl		84.68		76.23		11	%
Avg. NGL price per Bbl, excluding hedging		46.84		44.49		5	%
Avg. NGL price per Bbl		44.02		44.49		(1	%)
Avg. revenue per Mcfe		6.93		6.26		11	%

Natural Gas. For the three months ended March 31, 2011, natural gas revenue, including the effects of hedging, decreased by $6.0 million, or 11%, from the same period in 2010, to $49.8 million from $55.8 million. This decrease was primarily due to the decline in the average gas price, including the effects of hedging, and a decrease in production during the first quarter of 2011 due to the divestitures of our more gas-based assets. The average gas price, including the effects of hedging, decreased by $0.51 per Mcf to $5.30 per Mcf for the three months ended March 31, 2011 from $5.81 per Mcf for the same period in 2010. The effect of natural gas hedging activities on natural gas revenue for the three months ended March 31, 2011 was a gain of $10.1 million as compared to a gain of $2.9 million for the three months ended March 31, 2010.

Crude Oil. For the three months ended March 31, 2011, oil revenue, including the effects of hedging, increased by $21.7 million, or 312%, to $28.7 million from $7.0 million for the same period in 2010. This increase was attributable to an increase in production by 271%, or 247.9 MBbls, to 339.5 MBbls for the three months ended March 31, 2011 from 91.6 MBbls for the three months ended March 31, 2010 due to newly drilled wells in the Eagle Ford play that flowed to sales. The average realized price, including the effects of hedging, also increased to $84.68 per Bbl for the three months ended March 31, 2011 from $76.23 per Bbl for the three months ended March 31, 2011. The effect of oil hedging activities on oil revenue for the three months ended March 31, 2011 was a loss of $0.3 million. There was no effect of oil hedging activities on oil revenue for the three months ended March 31, 2010 as no oil derivative transactions settled during the respective period.

NGLs. For the three months ended March 31, 2011, NGL revenue, including the effects of hedging, increased by $11.1 million, or 152%, to $18.5 million from $7.4 million for the same period in 2010. This increase was attributable to an increase in production by 155%, or 255.8 MBbls, to 421.2 MBbls for the three months ended March 31, 2011 from 165.4 MBbls for the three months ended March 31, 2010 due to newly drilled wells in the Eagle Ford play that flowed to sales. The increase is offset by a marginal decline in the average realized price, including the effects of hedging, to $44.02 per Bbl for the three months ended March 31, 2011 from $44.49 per Bbl for the three months ended March 31, 2010. The effect of NGL hedging activities on NGL revenue for the three months ended March 31, 2011 was a loss of $1.2 million. There was no effect of NGL hedging activities on NGL revenue for the three months ended March 31, 2010 as no NGL derivative transactions settled during the respective period.

Operating Expenses

The following table presents information regarding our operating expenses:


	Three Months Ended March 31,
	2011		2010		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	14,520	$	14,677		(1	%)
Production taxes		1,656		2,290		(28	%)
Depreciation, depletion and amortization		34,029		23,814		43	%
General and administrative costs		21,070		11,807		78	%

$ per unit:
Avg. lease operating expense per Mcfe	$	1.04	$	1.31		(21	%)
Avg. production taxes per Mcfe		0.12		0.20		(40	%)
Avg. DD&A per Mcfe		2.43		2.13		14	%
Avg. production costs per Mcfe (1)		3.47		3.44		1	%
Avg. production costs per Mcfe, excluding taxes (2)		3.23		3.16		2	%
Avg. General and administrative costs per Mcfe		1.51		1.05		44	%
Avg. General and administrative costs per Mcfe, excluding stock-based compensation		0.75		0.83		(10	%)

(1)	Production costs per Mcfe includes lease operating expense and depreciation, depletion and amortization (“DD&A”).

(2)	Production costs per Mcfe includes lease operating expense and DD&A and excludes production and ad valorem taxes.

Lease Operating Expense. Lease operating expense decreased $0.2 million to $14.5 million from $14.7 million for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The overall decrease was due primarily to our asset divestiture program.

Production Taxes. Production taxes as a percentage of unhedged natural gas, oil and NGL sales were 1.9% for the three months ended March 31, 2011 as compared to 3.4% for the three months ended March, 31, 2010. This decrease in rate was primarily due to asset divestitures and certain production tax credits in the State of Texas.

Depreciation, Depletion and Amortization. DD&A expense increased $10.2 million to $34.0 million for the three months ended March 31, 2011 from $23.8 million for the three months ended March 31, 2010. The increase was due to an increase in production for the three months ended March 31, 2011 from the same period in 2010. The DD&A rate increased to $2.43 per Mcfe for the three months ended March 31, 2011 from $2.13 per Mcfe for the same period in 2010 primarily due to increased development costs in the Eagle Ford play.

General and Administrative Costs. General and administrative costs increased $9.3 million to $21.1 million for the three months ended March 31, 2011 from $11.8 million for the three months ended March 31, 2010. This increase was primarily the result of an increase of $8.5 million in stock based compensation expense, bonus accrual, and salaries, wages and benefits and a $0.8 million increase in financial services related to asset divestitures.

Total Other Expense

Total other expense includes Interest expense, net of interest capitalized; Interest income; and Other income/expense, net, and increased $2.1 million to $6.6 million for the three months ended March 31, 2011 from $4.5 million for the three months ended March 31, 2010.

The increase in Total other expense was due to an increase in Interest expense, net of interest capitalized, and Other expense. The weighted average interest rate for the first quarter of 2011 was 7.10% compared to 6.22% for the same period in 2010. This increase in the weighted average interest rate was primarily due to the higher interest rate associated with the Senior Notes. The increase in Other expense was primarily due to $0.2 million recorded during the three months ended March 31, 2011 associated with the rental expense of the Denver office space. While rental expense associated with the Denver office historically has been presented in General and administrative costs, the Denver office lease is now considered an investment as a result of the cease-use of the space. See Note 13 – Restructuring and Reorganization.

Provision for Income Taxes

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our 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 March 31, 2011, we have a deferred tax asset of $144.1 million resulting primarily from the difference between the book basis and tax basis of our oil and natural gas properties and net operating loss carryforwards. 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.

Liquidity and Capital Resources

Our primary source of liquidity and capital is our operating cash flow. 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 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 natural gas, oil and NGL sales are discussed above under “Results of Operations – Revenues - Natural Gas,” “Results of Operations – Revenues – Crude Oil,” and “Results of Operations – Revenues – NGLs.” 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. Our amended and restated revolving credit agreement (the “Restated Revolver”) provides for a senior secured revolving line of credit of up to $600.0 million and matures on July 1, 2012. 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 borrowing base is dependent on a number of factors, including the level of reserves as well as the pricing outlook at the time of the redetermination. A reduction in capital spending could result in a reduced level of reserves thus causing a reduction in the borrowing base. Amounts outstanding under the Restated Revolver bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. 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 equity interests of domestic subsidiaries. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants as defined in the credit agreement. The terms of the agreement require the maintenance of 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 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. At March 31, 2011, our current ratio was 2.6 and the leverage ratio was 1.5. 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 at March 31, 2011.

We had $130.0 million outstanding with $195.0 million of available borrowing capacity under our Restated Revolver as of March 31, 2011. Our semi-annual borrowing base review was completed in April 2011 and the borrowing based was confirmed by our lenders at $325.0 million. The confirmed borrowing base reflects the Sacramento Basin and DJ Basin divestitures as well as positive factors such as increased production from the Eagle Ford shale and increased levels of reserves. On April 21, 2011, we utilized a portion of asset divestiture proceeds and repaid $100.0 million of outstanding debt under the Restated Revolver. As of May 2, 2011, our outstanding debt under the Restated Revolver was $30.0 million with $295.0 million still available for borrowing.

Second Lien Term Loan. Our amended and restated term loan (the “Restated Term Loan”) matures on October 2, 2012. As of March 31, 2011, we had $20.0 million of fixed rate borrowings outstanding bearing interest at 13.75% under the Restated Term

Loan. The loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants as defined in the term loan agreement. We are required under the term loan agreement 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 us 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. At March 31, 2011, our reserve coverage ratio was 2.4 and the leverage ratio was 1.5. 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 at March 31, 2011. We also have 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.

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 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. We used proceeds from the Senior Notes offering to repay $114.0 million outstanding under the Restated Revolver and $80.0 million of variable rate borrowings outstanding under our Restated Term Loan and to pay for fees and expenses associated with the offering. 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:


	Three Months Ended March 31,
	2011			2010
	(In thousands)
Cash flows provided by operating activities	$	52,261		$	36,880
Cash flows used in investing activities		(9,788	)		(73,570	)
Cash flows (used in) provided by financing activities		(2,203	)		25,341

Net increase/(decrease) increase in cash and cash equivalents	$	40,270		$	(11,349	)

Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation and general and administrative expenses. Net cash provided by operating activities continued to be a primary source of liquidity and capital used to finance our capital program.

Cash flows provided by operating activities increased by $15.4 million for the three months ended March 31, 2011 as compared to the same period for 2010. The increase primarily resulted from an increase in production of 25% for the three months ended March 31, 2011 compared to the same period for 2010. In addition, at March 31, 2011, we had a working capital surplus of $12.1 million. This surplus for the first quarter of 2011 was primarily attributable to the cash and cash equivalents balance and the balance of accounts receivable.

Investing Activities. The primary driver of cash used in investing activities is capital spending and asset divestitures.

Cash flows used in investing activities decreased by $63.8 million for the three months ended March 31, 2011 as compared to the same period for 2010. During the three months ended March 31, 2011, we participated in the drilling of 11 gross wells as compared to the drilling of 36 gross wells during the same period in 2010. Capital spending during the three months ended March 31, 2011 was offset by the receipt of sales proceeds from the closing of our DJ Basin asset divestiture.

Financing Activities. The primary drivers of cash (used in) provided by financing activities are borrowings and repayments on the Company’s debt facilities, equity transactions associated with the exercise of stock options and the acquisition of treasury shares from employees and directors to pay tax withholding upon the vesting of restricted stock.

Cash flows provided by financing activities decreased by $27.5 million for the three months ended March 31, 2011 as compared to the same period for 2010. The net decrease is primarily related to the borrowings on the Restated Revolver of $25.0 million during the three months ended March 31, 2010 while no funds were borrowed under any debt facility during the three months ended March 31, 2011.

Capital Expenditures and Requirements

The historical capital expenditures summary table is included in Items 1 and 2 Business and Properties in our 2010 Annual Report and is incorporated herein by reference.

Our capital expenditures for the three months ended March 31, 2011 increased by $7.7 million to $88.1 million, from $80.4 million compared to the same period in 2010. During the three months ended March 31, 2011, we participated in the drilling of 11 gross wells with the majority of these being in the Eagle Ford shale. At current commodity prices, our positive operating cash flow and asset sales proceeds should be sufficient to fund planned capital expenditures for 2011, which are projected to be $360.0 million. Our planned capital expenditures primarily reflect development drilling in the Eagle Ford play where the vast majority of our planned drilling capital is allocated.

We have the discretion to use our available borrowing base 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.

Commodity Price Risk and Related Hedging Activities

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, costless collars and put options. Although not risk free, we believe these activities will reduce our exposure to commodity price fluctuations and thereby achieve a more predictable cash flow. Consistent with this policy, we have entered into a series of natural gas, oil and NGL fixed price swaps and costless collars for each year through 2013. Our fixed price swap and costless collar agreements require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of oil, NGLs, and natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments were based on expected production from existing wells at inception of the hedge instruments.

The following table sets forth the results of commodity fixed price and costless collars derivative settlements:


	Three Months Ended March 31,
	2011			2010
Natural Gas
Quantity settled (MMBtu)		4,500,000			2,250,000
Increase in natural gas sales revenue (In thousands) (1)	$	7,271		$	2,877
Crude Oil
Quantity settled (Bbl)		24,800			—
Decrease in crude oil sales revenue (In thousands)	$	(321	)	$	—
NGL
Quantity settled (Bbl)		63,000			—
Decrease in NGL sales revenue (In thousands)	$	(1,186	)	$	—
Interest Rate Swaps
(Increase) in interest expense (In thousands)	$	—		$	(252	)

(1)	Excludes approximately $2.9 million of realized gain associated with the 2011 terminations of derivatives used to hedge production from divested DJ Basin properties.

In accordance with the authoritative guidance for derivatives, all derivative instruments, not designated as a normal purchase sale, are recorded on the balance sheet at fair market value and changes in the fair market value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair market value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions on a quarterly basis, consistent with documented risk management strategy for the particular hedging relationship. Changes in the fair market value of the ineffective portion of cash flow hedges, if any, are included in other income (expense).

As of March 31, 2011, our commodity hedge positions were with counterparties that were also lenders in our credit facilities. This allows us to secure any margin obligation resulting from a negative change in the fair market value of the derivative contracts in connection with our credit obligations and eliminate the need for independent collateral postings. As of March 31, 2011, we had no deposits for collateral in regards to our commodity hedge positions.

Governmental Regulation

Climate Change. Current and future regulatory initiatives directed at climate change may increase our operating costs and may, in the future, reduce the demand for some of our produced materials. The United States Congress is currently considering legislation on climate change. In September 2009, the U.S. House of Representatives passed a comprehensive clean energy and climate bill (H.R. 2454, also known as “Waxman-Markey”). The U.S. Senate is working on a variety of proposed climate bills, including the American Power Act of 2010 (proposed by Senators Kerry and Lieberman). These bills or new legislation may be

considered by the current Congress. In substance, most legislative proposals contain a “cap and trade” approach to greenhouse gas regulation. Under such an approach, companies would be required to hold sufficient emission allowances to cover their greenhouse gas emissions. Over time, the total number of allowances would be reduced or expire, thereby relying on market-based incentives to allocate investment in emission reductions across the economy. As the number of available allowances declines, the cost would presumably increase. In addition to the prospect of federal legislation, several states have adopted or are in the process of adopting greenhouse gas reporting or cap-and-trade programs. Therefore, while the outcome of the federal and state legislative processes is currently uncertain, if such an approach were adopted (either by domestic legislation, international treaty obligation or domestic regulation), we would expect our operating costs to increase as we buy additional allowances or embark on emission reduction programs.

Even without further federal legislation, the United States Environmental Protection Agency (“EPA”) has begun to regulate greenhouse gas emissions. In December 2009, the EPA released an Endangerment and Cause or Contribute Findings for Greenhouse Gases, which became effective in January 2010. This regulatory finding sets the foundation for future EPA greenhouse gas regulation under the Clean Air Act. The EPA also promulgated a new greenhouse gas reporting rule, which became effective in December 2009, and which requires facilities that emit more than 25,000 tons per year of carbon dioxide-equivalent emissions to prepare and file certain emission reports. Finally, on November 8, 2010, the EPA adopted rules expanding the industries subject to greenhouse gas reporting to include certain petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in 2012. Some of our facilities are subject to these rules. On May 12, 2010, the EPA issued a new “tailoring” rule, which proposed and imposes additional permitting requirements on certain stationary sources emitting over 75,000 tons per year of carbon dioxide equivalent emissions. This rule does not currently affect our operations but may as our operations grow. Finally, the EPA is considering additional rulemaking to apply these requirements to broader classes of emission sources by 2012, which may apply to some of our facilities. As a result of these regulatory initiatives, our operating costs may increase in compliance with these programs, although we are not situated differently in this respect from our competitors in the industry.

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.

We are party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters. Net of available insurance and 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.

Critical Accounting Policies and Estimates

In our 2010 Annual Report, we identified our most critical accounting policies upon which our financial condition depends as those relating to oil and natural gas reserves, full cost method of accounting, derivative transactions and hedging activities, fair value measurements, revenue recognition, income taxes and stock-based compensation.

We assess the impairment for oil and natural gas properties under the full cost accounting method on a quarterly basis by using a ceiling test to determine if impairment is necessary. If the net capitalized costs of oil and natural gas properties exceed the cost ceiling, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, it would reduce earnings and impact shareholders’ equity in the period of occurrence and could result in a lower depreciation, depletion and amortization expense in the future.

Our ceiling test was calculated using a trailing twelve-month, unweighted-average first-day-of-the-month price, adjusted for hedges, of gas and oil at March 31, 2011, based on a Henry Hub gas price of $4.10 per MMBtu and a West Texas Intermediate oil price of $80.04 per Bbl (adjusted for basis and quality differentials). 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 at March 31, 2011. It is possible that a write-down of our oil and gas properties could occur in the future should oil and natural gas prices decline, we experience significant downward adjustments to the estimated proved reserves, and/or our commodity hedges settle and are not replaced.

We enter into derivative transactions to hedge against changes in natural gas, oil and NGL prices primarily through the use of fixed price swap agreements, basis swap agreements, costless collars and put options. Consistent with our hedge policy, we entered into a series of derivative transactions to hedge a portion of our expected natural gas, oil and NGL production through 2013. As of March 31, 2011, approximately 100% of total hedged natural gas transactions represented hedged prices of natural gas at the PG&E Citygate and Houston Ship Channel, 100% of hedged crude oil transactions represented hedged prices

of crude oil at the West Texas Intermediate on the NYMEX and approximately 59% of the total hedged NGL transactions represented hedged NGL prices at Mont Belvieu Propane (Non-TET) OPIS and Mont Belvieu Natural Gasoline (Non-TET) OPIS.

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 on a quarterly basis.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 2 to the Consolidated Financial Statements in Part I. Item 1. Financial Statements of this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk primarily related to adverse changes in natural gas, oil and NGL 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 Disclosure About Market Risk” in our 2010 Annual Report and Note 4 - Commodity Hedging Contracts and Other Derivatives included in Part I. Item 1. Financial Statements of this Form 10-Q.

As of March 31, 2011, we had open natural gas derivative hedges in an asset position with a fair value of $21.5 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $8.6 million, while a 10 percent decrease in natural gas prices would increase the fair value by approximately $9.0 million. The effects of these derivative transactions on our natural gas sales are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations – Revenues – Natural Gas”.

As of March 31, 2011, we had open crude oil derivative hedges in a liability position with a fair value of $22.6 million. A 10 percent increase in crude oil prices would reduce the fair value by approximately $21.3 million, while a 10 percent decrease in crude oil prices would increase the fair value by approximately $16.6 million. The effects of these derivative transactions on our crude oil sales are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues – Crude Oil”.

As of March 31, 2011, we had open NGL derivative hedges in a liability position with a fair value of $15.2 million. A 10 percent increase in NGL prices would reduce the fair value by approximately $9.2 million, while a 10 percent decrease in NGL prices would increase the fair value by approximately $9.2 million. The effects of these derivative transactions on our NGL sales are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues – NGLs”.

These fair value changes assume volatility based on prevailing market parameters at March 31, 2011.

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 hedge arrangement, or the counterparties to our hedging agreements fail to perform under the contracts.

Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities. This arrangement eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with our hedge related credit obligations. As of March 31, 2011, we had no deposits for collateral in regards to commodity hedge positions. 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 March 31, 2011. We evaluated non-performance risk using the current credit default swap value and default probability for the Company and recorded a downward adjustment to the fair value of our derivative liabilities in the amount of $0.3 million at March 31, 2011.

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 March 31, 2011. Based on that evaluation,

the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2011, 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 March 31, 2011 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 the liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and 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 consolidated financial statements.

Item 1A. Risk Factors

There have been no material changes in our risk factors from those previously disclosed in Item 1A of our 2010 Annual Report.

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 March 31, 2011:


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
January 1 - January 31		49,113	$	37.60		—		—
February 1 - February 28		6,519		40.06		—		—
March 1 - March 31		27,595		44.48		—		—

Total		83,227	$	40.07		—		—

(1)

All of the shares were surrendered by our employees and directors to pay tax withholding 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. Removed and Reserved

Item 5. Other Information

None.

Item 6. Exhibits


Exhibit Number		Description

2.1*		Purchase Agreement dated February 24, 2011 (California assets).

3.1		Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).

3.2		Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 10, 2010 (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 Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension 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/ MICHAEL J. ROSINSKI
Michael J. Rosinski
Executive Vice President, Chief Financial Officer and Treasurer

(Duly Authorized Officer and Principal Financial Officer)

Date: May 6, 2011

ROSETTA RESOURCES INC.

EXHIBIT INDEX


Exhibit Number		Description

2.1*		Purchase Agreement dated February 24, 2011 (California assets).

3.1		Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).

3.2		Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 10, 2010 (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 Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith