Edgar Filing: Rosetta Resources Inc.

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended March 31, 2013

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

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)


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

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

(713) 335-4000

(Registrant’s telephone number, including area code)

717 Texas, Suite 2800

Houston, TX

(Former address of principal executive offices)

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

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

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


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

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

The number of shares of the registrant’s Common Stock, $0.001 par value per share, outstanding as of April 29, 2013 was 61,089,355 which excludes unvested restricted stock awards.

Table of Contents


Part I –	Financial Information
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	27
	Item 4. Controls and Procedures	28
Part II –	Other Information
	Item 1. Legal Proceedings	29
	Item 1A. Risk Factors	29
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3. Defaults upon Senior Securities	30
	Item 4. Mine Safety Disclosures	30
	Item 5. Other Information	30
	Item 6. Exhibits	30
Signatures		31

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except par value and share amounts)


	March 31, 2013			December 31, 2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	10,677		$	36,786
Accounts receivable, net		106,783			103,828
Derivative instruments		2,768			14,437
Prepaid expenses		8,539			5,742
Deferred income taxes		16,470			311
Other current assets		1,454			1,456

Total current assets		146,691			162,560

Oil and natural gas properties using the full cost method of accounting:
Proved properties		2,948,072			2,829,431
Unproved/unevaluated properties, not subject to amortization		125,494			95,540
Gathering systems and compressor stations		118,519			104,978
Other fixed assets		19,270			16,346

		3,211,355			3,046,295
Accumulated depreciation, depletion and amortization, including impairment		(1,852,665	)		(1,808,190	)

Total property and equipment, net		1,358,690			1,238,105
Other assets:
Deferred loan fees		7,162			7,699
Derivative instruments		4,350			6,790
Other long-term assets		38,663			262

Total other assets		50,175			14,751

Total assets	$	1,555,556		$	1,415,416


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	2,451		$	1,874
Accrued liabilities		107,996			120,336
Royalties and other payables		66,113			61,637

Total current liabilities		176,560			183,847

Long-term liabilities:
Derivative instruments		—			563
Long-term debt		465,000			410,000
Deferred income taxes		52,353			10,086
Other long-term liabilities		7,188			6,921

Total liabilities		701,101			611,417


Commitments and Contingencies (Note 9)
Stockholders’ equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2013 or 2012		—			—
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 53,635,966 shares and 53,145,853 shares at March 31, 2013 and December 31, 2012, respectively		53			53
Additional paid-in capital		833,685			830,539
Treasury stock, at cost; 707,401 and 581,717 shares at March 31, 2013 and December 31, 2012, respectively		(23,735	)		(17,479	)
Accumulated other comprehensive income (loss)		23			(63	)
Retained earnings (Accumulated deficit)		44,429			(9,051	)

Total stockholders’ equity		854,455			803,999

Total liabilities and stockholders’ equity	$	1,555,556		$	1,415,416

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2013			2012
Revenues:
Oil sales	$	110,052		$	62,970
NGL sales		46,461			43,760
Natural gas sales		33,576			23,689
Derivative instruments		(11,969	)		(15,961	)

Total revenues		178,120			114,458
Operating costs and expenses:
Lease operating expense		11,174			8,501
Treating and transportation		15,087			11,998
Production taxes		5,392			3,228
Depreciation, depletion and amortization		44,630			32,899
General and administrative costs		15,532			17,291

Total operating costs and expenses		91,815			73,917

Operating income		86,305			40,541

Other expense (income):
Interest expense, net of interest capitalized		6,069			5,461
Interest income		—			(2	)
Other (income) expense, net		(30	)		113

Total other expense		6,039			5,572


Income before provision for income taxes		80,266			34,969
Income tax expense		26,786			12,672

Net income	$	53,480		$	22,297


Earnings per share:
Basic	$	1.01		$	0.43

Diluted	$	1.01		$	0.42


Weighted average shares outstanding:
Basic		52,733			52,399
Diluted		53,081			52,810

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Comprehensive Income

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2013			2012

Net income	$	53,480		$	22,297
Other comprehensive income (loss):
Amortization of accumulated other comprehensive gain (loss) related to de-designated hedges, net of income taxes of ($154) and $34		271			(53	)
Postretirement medical benefits prior service cost, net of income taxes of $104		(185	)		—

Other comprehensive income (loss)		86			(53	)

Comprehensive income	$	53,566		$	22,244

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net income	$	53,480		$	22,297
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		44,630			32,899
Deferred income taxes		26,060			12,672
Amortization of deferred loan fees recorded as interest expense		538			478
Stock-based compensation expense		2,664			5,423
Derivative instruments		13,971			17,952
Change in operating assets and liabilities:
Accounts receivable		(2,955	)		9,318
Prepaid expenses		771			(367	)
Other current assets		—			296
Long-term assets		(1	)		(10	)
Accounts payable		577			471
Accrued liabilities		(1,306	)		(27,655	)
Royalties and other payables		4,476			16
Other long-term liabilities		(1,266	)		(79	)

Net cash provided by operating activities		141,639			73,711

Cash flows from investing activities:
Deposit on Permian acquisition		(38,400	)		—
Additions to oil and gas assets		(175,849	)		(127,981	)
Disposals of oil and gas assets		(2,651	)		65,624

Net cash used in investing activities		(216,900	)		(62,357	)

Cash flows from financing activities:
Borrowings on Credit Facility		140,000			50,000
Payments on Credit Facility		(85,000	)		(50,000	)
Proceeds from stock options exercised		408			387
Purchases of treasury stock		(6,256	)		(5,700	)

Net cash provided by (used in) financing activities		49,152			(5,313	)


Net (decrease) increase in cash		(26,109	)		6,041
Cash and cash equivalents, beginning of period		36,786			47,050

Cash and cash equivalents, end of period	$	10,677		$	53,091


Supplemental disclosures:
Capital expenditures included in accrued liabilities	$	77,867		$	64,649

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands, except share amounts)

(Unaudited)


	Common Stock				Additional Paid-In Capital		Treasury Stock					Accumulated Other Comprehensive Income/(Loss)			Retained Earnings / (Accumulated Deficit)			Total Stockholders’ Equity
	Shares		Amount		Additional Paid-In Capital		Shares		Amount			Accumulated Other Comprehensive Income/(Loss)			Retained Earnings / (Accumulated Deficit)			Total Stockholders’ Equity

Balance at December 31, 2012		53,145,853	$	53	$	830,539		581,717	$	(17,479	)	$	(63	)	$	(9,051	)	$	803,999
Stock options exercised		95,500		—		408		—		—			—			—			408
Treasury stock – employee tax payment		—		—		—		125,684		(6,256	)		—			—			(6,256	)
Stock-based compensation		—		—		2,738		—		—			—			—			2,738
Vesting of restricted stock		394,613		—		—		—		—			—			—			—
Comprehensive income		—		—		—		—		—			86			53,480			53,566


Balance at March 31, 2013		53,635,966	$	53	$	833,685		707,401	$	(23,735	)	$	23		$	44,429		$	854,455

See accompanying notes to the consolidated financial statements.

Rosetta Resources Inc.

Notes to Consolidated Financial Statements (unaudited)

(1) Organization and Operations of the Company

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

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of normal recurring adjustments necessary to fairly state the financial statements, have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). These financial statements and notes should be read in conjunction with the Company’s audited Consolidated Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”).

(2) Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2012 Annual Report.

Recent Accounting Developments

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

Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. In February 2013, the FASB further clarified this guidance relating to the presentation of reclassification adjustments stating that an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income. The Company adopted the provisions of the initial guidance effective January 1, 2012 and the provisions of the February 2013 amendment effective January 1, 2013. See the Consolidated Statement of Comprehensive Income, Note 4 – Commodity Derivative Contracts and Note 11 – Employee Benefits.

Offsetting Assets and Liabilities. In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements under U.S. GAAP and those entities that prepare their financial statements under IFRS. In January 2013, the FASB issued additional guidance clarifying the scope of these disclosures to include bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. The Company has adopted this guidance effective January 1, 2013. This guidance requires additional disclosures but did not impact the Company’s consolidated financial position, results of operations or cash flows. See Note 5 – Fair Value Measurements.

(3) Property and Equipment

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


	March 31, 2013			December 31, 2012
	(In thousands)
Proved properties	$	2,948,072		$	2,829,431
Unproved/unevaluated properties		125,494			95,540
Gathering systems and compressor stations		118,519			104,978
Other fixed assets		19,270			16,346

Total property and equipment, gross		3,211,355			3,046,295
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,852,665	)		(1,808,190	)

Total property and equipment, net	$	1,358,690		$	1,238,105

On March 14, 2013, the Company entered into a purchase and sale agreement with Comstock Oil & Gas, LP (“Comstock”), pursuant to which the Company will purchase from Comstock producing and undeveloped oil and natural gas interests in the Permian Basin in Gaines and Reeves Counties, Texas for $768 million, subject to customary closing adjustments, including adjustments based upon title and environmental due diligence (the “Acquisition”). The Acquisition is expected to close on or about May 14, 2013, with an effective date of January 1, 2013; however, there can be no assurance that all of the conditions to closing for the Acquisition will be satisfied.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $2.1 million and $2.0 million of internal costs for the three months ended March 31, 2013 and 2012, respectively.

Oil and gas properties include costs of $125.5 million and $95.5 million as of March 31, 2013 and December 31, 2012, 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.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within its U.S. cost center. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of March 31, 2013, which were based on a West Texas Intermediate oil price of $89.17 per Bbl and a Henry Hub natural gas price of $2.95 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and natural gas properties. As a result, no write-down was recorded as of March 31, 2013. It is possible that a write-down of the Company’s oil and gas properties could occur in future periods in the event that oil and natural gas prices decline or the Company experiences significant downward adjustments to its estimated proved reserves.

(4) Commodity Derivative Contracts

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

As of March 31, 2013, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:


Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Average Floor Prices per Bbl			Average Ceiling Prices per Bbl
Crude oil	2013	Costless Collar		7,750		2,131,250	$	80.16		$	115.71
Crude oil	2014	Costless Collar		3,000		1,095,000		83.33			109.63
Crude oil	2013	Swap		3,000		825,000		95.72
Crude oil	2014	Swap		5,000		1,825,000		93.06

						5,876,250


Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
Crude oil	2013	Basis Swap		1,875		515,625	$	5.80
Crude oil	2013	NYMEX Roll Swap		1,875		515,625		(0.18	)

						1,031,250


Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
NGL-Ethane	2013	Swap		3,000		825,000	$	14.43
NGL-Propane	2013	Swap		2,270		624,250		46.34
NGL-Isobutane	2013	Swap		705		193,875		69.30
NGL-Normal Butane	2013	Swap		730		200,750		66.86
NGL-Pentanes Plus	2013	Swap		795		218,625		86.27
NGL-Ethane	2014	Swap		2,000		730,000		15.28
NGL-Propane	2014	Swap		1,535		560,275		43.75
NGL-Isobutane	2014	Swap		480		175,200		66.71
NGL-Normal Butane	2014	Swap		475		173,375		64.54
NGL-Pentanes Plus	2014	Swap		510		186,150		83.96

						3,887,500


Product	Settlement Period	Derivative Instrument	Notional Daily Volume MMBtu		Total Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu			Average Ceiling Prices per MMBtu
Natural gas	2013	Costless Collar		20,000		5,500,000	$	3.50		$	4.90
Natural gas	2014	Costless Collar		30,000		10,950,000		3.50			4.93
Natural gas	2015	Costless Collar		30,000		10,950,000		3.50			5.11
Natural gas	2013	Swap		20,000		5,500,000		3.98			—
Natural gas	2014	Swap		20,000		7,300,000		3.98			—
Natural gas	2015	Swap		20,000		7,300,000		4.08			—

						47,500,000

As of March 31, 2013, the Company’s derivative instruments were with counterparties who are lenders under the Company’s senior secured revolving credit facility (the “Credit Facility”). This practice allows the Company to satisfy any need for any margin obligations resulting from an adverse change in the fair market value of its derivative contracts with the collateral securing its Credit Facility, thus eliminating the need for independent collateral postings. The Company’s ability to continue satisfying any applicable margin requirements in this manner may be subject to change as described in the Government Regulation section of the 2012 Annual Report. As of March 31, 2013, the Company had no deposits for collateral relating to its commodity derivative instruments.

Discontinuance of Hedge Accounting

Effective January 1, 2012, the Company elected to de-designate all commodity contracts previously designated as cash flow hedges as of December 31, 2011, and elected to discontinue hedge accounting prospectively. Accumulated other comprehensive income included $2.6 million ($1.6 million after tax) of unrealized net gains, representing the mark-to-market value of the Company’s cash flow hedges as of December 31, 2011. As a result of discontinuing hedge accounting, the mark-to-market values included in Accumulated other comprehensive income as of the de-designation date were frozen and are being reclassified into earnings as the underlying hedged transactions affect earnings. During the three months ended March 31, 2013, the Company reclassified unrealized net losses of $0.4 million ($0.3 million after tax) into earnings from Accumulated other comprehensive income. The Company expects to reclassify an additional $0.3 million of unrealized net gains during 2013 into earnings from Accumulated other comprehensive income.

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

Additional Disclosures about Derivative Instruments

Authoritative guidance for derivatives requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the Company’s financial statements. The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of March 31, 2013 and December 31, 2012, respectively:


		Asset (Liability) Fair Value
		March 31, 2013			December 31, 2012
Commodity derivative contracts	Location on Consolidated Balance Sheet	(In thousands)
Oil	Derivative instruments – current assets	$	(3,858	)	$	564
Oil	Derivative instruments – non-current assets		3,156			3,329
NGL	Derivative instruments – current assets		8,084			8,361
NGL	Derivative instruments – non-current assets		3,962			3,534
NGL	Derivative instruments – non-current liabilities		—			(563	)
Natural gas	Derivative instruments – current assets		(1,458	)		5,512
Natural gas	Derivative instruments – non-current assets		(2,768	)		(73	)


Total derivatives not designated as hedging instruments		$	7,118		$	20,664

The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the three months ended March 31, 2013 and 2012, respectively:


Location on Consolidated Statement of Operations		Three Months Ended March 31,
	Description of Gain (Loss)	2013			2012
	Description of Gain (Loss)	(In thousands)
Derivative instruments	Gain recognized in income		2,002			1,991

	Realized gain recognized in income	$	2,002		$	1,991


Derivative instruments	Loss recognized in income due to changes in fair value	$	(13,546	)	$	(18,039	)
Derivative instruments	(Loss) gain reclassified from Accumulated OCI		(425	)		87

	Unrealized loss recognized in income	$	(13,971	)	$	(17,952	)



	Total commodity derivative loss recognized in income	$	(11,969	)	$	(15,961	)

(5) Fair Value Measurements

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

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

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

•

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

•

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

•

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

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities along with their placement within the fair value hierarchy levels. The Company determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period.

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


	Fair value as of March 31, 2013
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		15,876			(8,758	)		7,118
Liabilities:
Commodity derivative contracts		—		—		(8,758	)		8,758			—

Total	$	—	$	1,035	$	7,118		$	—		$	8,153


	Fair value as of December 31, 2012
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		27,554			(6,327	)		21,227
Liabilities:
Commodity derivative contracts		—		—		(6,890	)		6,327			(563	)

Total	$	—	$	1,035	$	20,664		$	—		$	21,699

(1)

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

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

The following table presents a range of the unobservable inputs provided by our third party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of March 31, 2013:


						Range					Weighted
Level 3 Instrument	Asset (Liability)			Valuation Technique	Unobservable Input	Minimum			Maximum		Average
	(in thousands)
Oil NYMEX roll swap	$	(212	)	Discounted cash flow	Forward price curve-NYMEX rolls swaps	$	(0.77	)	$	1.03	$	0.24
Oil basis swap		(3,228	)	Discounted cash flow	Forward price curve-basis swaps		8.76			20.84		9.64
Oil swaps		(864	)	Discounted cash flow	Forward price curve-swaps		95.21			97.62		96.78
Oil swaps		626		Discounted cash flow	Forward price curve-swaps		91.04			94.73		92.72
Oil costless collars		2,976		Option model	Forward price curve- costless collar option value		(3.16	)		5.81		0.92
NGL swaps		12,274		Discounted cash flow	Forward price curve-swaps		0.30			2.05		0.84
NGL swaps		(228	)	Discounted cash flow	Forward price curve-swaps		2.04			2.15		2.08
Natural gas swaps		(3,032	)	Discounted cash flow	Forward price curve-swaps		3.95			4.46		4.17
Natural gas costless collars		(1,194	)	Option model	Forward price curve- costless collar option value		(0.39	)		0.24		0.04

	$	7,118

The determination of derivative fair values by the third party provider incorporates a credit adjustment for nonperformance risk, including the credit standing of the counterparties involved, and the impact of the Company’s nonperformance risk on its liabilities. The Company recorded an immaterial downward adjustment to the fair value of its derivative instruments as of March 31, 2013.

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

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


	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2013	$	20,664		$	—		$	20,664
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(11,544	)		—			(11,544	)
Purchases, Issuances and Settlements:
Settlements		(2,002	)		—			(2,002	)
Transfers in and out of Level 3		—			—			—

Balance at March 31, 2013	$	7,118		$	—		$	7,118


	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2012	$	3,665		$	1,035		$	4,700
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(16,048	)		—			(16,048	)
Included in Other Comprehensive Income		—			—			—
Purchases, Issuances and Settlements:
Settlements		(1,991	)		—			(1,991	)
Purchases		—			—			—
Transfers out of Level 3 (1)		—			(1,035	)		(1,035	)

Balance at March 31, 2012	$	(14,374	)	$	—		$	(14,374	)

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

Fair Value of Other Financial Instruments

All of the Company’s other financial instruments (excluding derivatives) are presented on the balance sheet at carrying value. As of March 31, 2013, the carrying value of cash and cash equivalents (excluding money market funds), other current assets and current liabilities reported in the Consolidated Balance Sheet approximate fair value because of their short-term nature, and all such financial instruments are considered Level 1 instruments.

The Company’s debt consists of $200 million in aggregate principal amount of 9.500% Senior Notes due 2018 (the “9.500% Senior Notes”) and borrowings under the Credit Facility. The fair value of the Company’s 9.500% Senior Notes is based upon an unadjusted quoted market price and is considered a Level 1 instrument. The Company’s borrowings under the Credit Facility approximate fair value as the interest rates are variable and reflective of current market rates, and are therefore considered a Level 1 instrument. As of March 31, 2013, the carrying amount and estimated fair value of total debt was $465.0 million and $485.9 million, respectively.

(6) Asset Retirement Obligations

The following table provides a rollforward of the Company’s asset retirement obligations (“ARO”). Liabilities incurred during the period include additions to obligations. 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 ARO is as follows:


	Three Months Ended March 31, 2013
	(In thousands)
ARO as of December 31, 2012	$	8,400
Liabilities incurred during period		46
Liabilities settled during period		(426	)
Accretion expense		146

ARO as of March 31, 2013	$	8,166

As of March 31, 2013, the $2.4 million current portion of the total ARO is included in Accrued liabilities, and the $5.8 million long-term portion of ARO is included in Other long-term liabilities on the Consolidated Balance Sheet.

(7) Long-Term Debt

Senior Secured Revolving Credit Facility. At March 31, 2013, the Company’s borrowing base and commitments under the Credit Facility were $625.0 million. Availability under the Credit Facility is restricted to a borrowing base and committed amount, which are subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements as well as asset divestitures. The amount of the borrowing base and committed amount is affected by a number of factors, including the Company’s level of reserves, as well as the pricing outlook at the time of the redetermination. Therefore, a significant reduction in capital spending could result in a reduced level of reserves that could lower the borrowing base and committed amount.

As of March 31, 2013, the Company had $265.0 million outstanding with $360.0 million of available borrowing capacity under its Credit Facility. Amounts outstanding under the Credit Facility bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50%. The weighted average borrowing rate for the three months ended March 31, 2013 under the Credit Facility was 1.96%. Borrowings under the Credit Facility 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 proved reserve value, a guaranty by all of the Company’s domestic subsidiaries and a pledge of 100% of the membership and limited partnership interests of the Company’s domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is also subject to certain financial covenants including the requirement to maintain a minimum current ratio of consolidated current assets, including the unused amount of available borrowing capacity, to consolidated current liabilities, excluding certain non-cash obligations, of not less than 1.0 to 1.0 as of the end of each fiscal quarter. The terms of the credit agreement also require the maintenance of a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. As of March 31, 2013, the Company’s current ratio was 2.8 and leverage ratio was 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties.

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

Total Indebtedness. As of March 31, 2013, the Company had total outstanding borrowings of $465.0 million. For the three months ended March 31, 2013, the Company’s weighted average borrowing rate was 5.42%.

Subsequent Events. See Note 13 – Subsequent Events for a description of our Sixth Amendment to the Credit Agreement, repayment of borrowings outstanding, our public offering of 8,050,000 shares of common stock and the Company’s issuance of $700.0 million in aggregate principal amount of 5.625% Senior Notes (the “5.625% Senior Notes”) due 2021.

(8) Income Taxes

The Company’s effective tax rate for the three months ended March 31, 2013 and 2012 was 33.4% and 36.2%, respectively. The provision for income taxes for the three months ended March 31, 2013 differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes and the non-deductibility of certain incentive compensation. In addition, during the first quarter of 2013 there was a one-time favorable discrete adjustment of (2.9%) to reflect a change in the amount of deductible executive compensation. Excluding the discrete item, the effective tax rate for the first quarter of 2013 was 36.3%. As of March 31, 2013 and December 31, 2012, the Company had no unrecognized tax benefits. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of March 31, 2013, the Company had a net deferred tax liability of $35.9 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of oil and natural gas properties.

(9) Commitments and Contingencies

Firm Oil and Natural Gas Transportation and Processing Commitments. The Company has commitments for the transportation and processing of its production in the Eagle Ford area and has an aggregate minimum commitment to deliver 7.2 MMBbls of oil by the end of 2017 and 400 million MMBtus of natural gas by the end of 2023. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume under these commitments. Currently, the Company has insufficient production to meet all of these contractual commitments and as of March 31, 2013, the Company has accrued deficiency fees of $1.4 million. Future obligations under firm oil and natural gas transportation and processing agreements as of March 31, 2013 are as follows:


	March 31, 2013
	(In thousands)
2013	$	25,920
2014		34,403
2015		34,230
2016		33,809
2017		33,388
Thereafter through 2023		133,928

	$	295,678

Drilling Rig and Completion Services Commitments. Drilling rig and completion services commitments represent obligations with certain contractors to execute the Company’s Eagle Ford area drilling program, and payments under these commitments are accounted for as capital additions to oil and gas properties. As of March 31, 2013, the Company had no outstanding drilling rig commitments with terms greater than one year and minimum contractual commitments due in the next twelve months are $6.5 million. As of March 31, 2013, the Company’s minimum contractual commitments for completion services agreements for the stimulation, cementing and delivery of drilling fluids are $12.0 million.

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

(10) Earnings Per Share

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

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


	Three Months Ended March 31,
	2013		2012
	(In thousands)
Basic weighted average number of shares outstanding		52,733		52,399
Dilution effect of stock option and restricted shares at the end of the period		348		411

Diluted weighted average number of shares outstanding		53,081		52,810


Anti-dilutive stock awards and shares		2		1

(11) Stock-Based Compensation and Employee Benefits

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


	Three Months Ended March 31
	2013			2012
	(In thousands)
Total stock-based compensation	$	2,738		$	5,585
Capitalized in oil and gas properties		(74	)		(162	)

Net stock-based compensation expense	$	2,664		$	5,423

All stock-based compensation expense associated with restricted stock granted to employees and directors is recognized on a straight-line basis over the applicable remaining vesting period. For the three months ended March 31, 2013, the Company recorded compensation expense of approximately $1.3 million related to these equity awards. As of March 31, 2013, unrecognized stock-based compensation expense related to unvested restricted stock was approximately $13.2 million.

Stock-based compensation expense associated with the PSUs granted to management is recognized over a three-year performance period. For the three months ended March 31, 2013, the Company recognized compensation expense of $1.4 million associated with the PSUs. At the current fair value as of March 31, 2013 and assuming the Board elects the maximum available payout of 200% for all PSU metrics, unrecognized stock-based compensation expense related to the PSUs was approximately $12.6 million. The Company’s total stock-based compensation expense will be measured and adjusted quarterly until settlement occurs, based on the Company’s performance, expected payout and quarter-end closing common stock prices. For a more detailed description of the Company’s PSU plans, including related performance conditions and structure, see the definitive proxy statement filed with respect to the Company’s 2013 annual meeting under the heading “Compensation Discussion and Analysis” and the Company’s 2012 Annual Report.

Postretirement Health Care. Effective January 1, 2013, the Company enacted a postretirement medical benefit plan covering eligible employees and their eligible dependents. Upon enactment, the Company recognized a $0.3 million liability related to the prior service of employees which is included as a component of Other comprehensive income, net of the related tax benefit. The Company recognizes periodic postretirement benefits cost as a component of General and administrative costs. For the three months ended March 31, 2013, this expense was immaterial.

(12) Guarantor Subsidiaries

The Company’s 9.500% Senior Notes are guaranteed by its wholly owned subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several and the Company’s non-guarantor subsidiaries are immaterial. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiaries by dividend or loan. Finally, none of the Company’s subsidiaries has restricted assets that exceed 25% of net assets as of the most recent fiscal year which may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

(13) Subsequent Events

On April 12, 2013, the Company entered into the Sixth Amendment to Amended and Restated Senior Revolving Credit Agreement (the “Amendment”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto. The Amendment, among other things, (i) increases the borrowing base to $800 million; (ii) increases the maximum credit amount under the Credit Facility to $1.5 billion; (iii) extends the maturity date to April 12, 2018; and (iv) provides for restrictions on the Company’s ability to pay dividends to its equity holders to be eased upon the Company acquiring investment grade unsecured debt ratings from Moody’s and Standard and Poor’s.

On April 23, 2013, the Company completed its public offering of 7,000,000 shares of common stock at a price to the public of $42.50 per share ($40.80 per share, net of underwriting discount and structuring fee) for net proceeds of approximately $286.3 million. The Company also received net proceeds of approximately $43.0 million in connection with the underwriters’ full exercise of their over-allotment option to purchase an additional 1,050,000 shares of common stock, which closed on April 29, 2013. The Company has used the net proceeds from the offering to repay outstanding indebtedness under its Credit Facility. The Company intends to use the remaining net proceeds from the offering to fund a portion of the consideration for the Acquisition. As of May 1, 2013, the Company had no borrowings outstanding with $800.0 million available for borrowing under the Credit Facility.

On May 2, 2013, the Company completed its public offering of $700.0 million in aggregate principal amount of its 5.625% Senior Notes due 2021. The Company intends to use all of the net proceeds from the offering to fund a portion of the consideration for the Company’s previously announced Acquisition. Interest is payable on the 5.625% Senior Notes semi-annually on May 1 and November 1. The 5.625% Notes were issued under an indenture with Wells Fargo Bank, National Association, as trustee. The indenture contains covenants and events of default substantially similar to those in the 9.500% Notes Indenture. If the Acquisition does not close on or prior to July 15, 2013 or if the applicable purchase and sale agreement is terminated at any time prior to the consummation of the Acquisition, then the Company will be required to redeem all of the 5.625% Senior Notes in cash at a redemption price equal to 100% of their aggregate principal amount, plus accrued and unpaid interest to the date of the redemption.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding the Company within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “forecast,” “predict,”

“potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology. Unless the context clearly indicates otherwise, references in this report to “Rosetta,” “the Company,” “we,” “our,” “us” or like terms refer to Rosetta Resources Inc. and its subsidiaries.

The forward-looking statements contained in this report reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Annual Report”). We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

•

our ability to consummate our acquisition (“Acquisition”) from Comstock Oil & Gas, LP (“Comstock”) of producing and undeveloped oil and natural gas interests in the Permian Basin in Gaines and Reeves Counties, Texas (the “Permian Basin Assets”) and to realize the expected benefits therefrom;

•

the impact of title and environmental due diligence on the value of the Permian Basin Assets;

•

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

•

unexpected difficulties in integrating our operations as a result of any significant acquisitions, including the Acquisition;

•

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

•

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

•

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

•

conditions in the energy and financial markets;

•

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

•

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

•

failure of our joint interest partners to fund any or all of their portion of any capital program;

•

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, equipment, goods and services;

•

changes or advances in technology;

•

potential reserve revisions;

•

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

•

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

•

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

•

drilling and exploration risks, including with respect to the Permian Basin Assets to be acquired which do not have substantial existing production or proved reserves;

•

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

•

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

•

present and possible future claims, litigation and enforcement actions;

•

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

•

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

•

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

•

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

•

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

Overview

The following discussion addresses material changes in our results of operations for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 and material changes in our financial condition since December 31, 2012. This discussion should be read in conjunction with our 2012 Annual Report, which includes disclosures regarding our critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Results for the three months ended March 31, 2013 included the following:

•

production of 4.2 MMBoe compared to 3.1 MMBoe for the three months ended March 31, 2012;

•

24 gross (23 net) wells drilled with a net success rate of 100% compared to 15 gross (15 net) wells drilled with a net success rate of 100% for the three months ended March 31, 2012;

•

net income of $53.5 million, or $1.01 per diluted share, compared to $22.3 million, or $0.42 per diluted share, for the three months ended March 31, 2012.

Our principal business strategy is focused on the acquisition, development and production of oil, NGLs and natural gas from unconventional resource plays. Our current assets are primarily located in the Eagle Ford area in South Texas, one of the most active shale plays in the U.S. During the first quarter of 2013, we entered into a purchase and sale agreement with Comstock to acquire producing and undeveloped assets covering 87,373 gross (53,306 net) acres in the oil-rich areas of the Permian Basin for $768 million, subject to customary closing adjustments, including adjustments based upon title and environmental due diligence. The Acquisition will be effective as of January 1, 2013 and is expected to close in May 2013.

In the last three years, we have become a significant producer in the liquids-rich window of the Eagle Ford region and have established an inventory of lower-risk, higher-return drilling opportunities that offer more predictable and long-term production, reserve growth and a more valuable commodity mix. With our expected entry into the Permian Basin, we have increased our portfolio of long-lived, oil-rich resource projects that will further drive the long-term growth and sustainability of the Company. We will continue to consider investments in the Eagle Ford shale region, Permian Basin and other unconventional resource basins that offer a viable inventory of projects including new higher-risk exploration projects and producing property acquisitions.

Our current operations in the Eagle Ford shale are primarily focused in four areas. Our original 2009 discovery is located in the 26,500-acre Gates Ranch leasehold in Webb County. We are also active in the Karnes Trough area, the Briscoe Ranch leasehold and in Central Dimmit County, where our positions were delineated in 2010, 2011 and 2012. Overall, we hold 67,000 net acres in the region with approximately 53,000 acres located in the crude oil and liquids producing portions of the play. In late 2012, we also began an exploration test in the Pearsall shale on our Tom Hanks lease in northern LaSalle County. The well has been drilled and completed and is currently awaiting a pipeline tie-in.

The development of our assets in the Eagle Ford has led to substantial growth for the Company, while shifting our portfolio toward greater percentages of higher-valued crude oil and NGL production. During 2012, we recorded a 35% percent increase in daily total equivalent production, with total liquids production growth of 76% and total proved reserves growth of 25% from 2011. At year-end 2012, our total estimated proved reserves were 201 MMBoe of which 58% were liquids.

For the quarter ended March 31, 2013, approximately 62% of our production was from crude oil and liquids as compared to 52% of our production from crude oil and liquids for the same period in 2012. The development of our Eagle Ford assets combined with the sale of non-strategic assets completed last year continues to lower our overall cost structure as a company, with lease operating expenses for the first quarter of 2013 decreasing to $2.64 per Boe from $2.76 per Boe for the same period in 2012.

Rosetta successfully drilled 24 and completed 17 wells during the quarter ended March 31, 2013. As of that date, we had completed a total of 142 wells in the Eagle Ford shale. In the first quarter of 2013, daily production increased 39% from the same period in 2012, and we recorded 6% sequential growth in our Eagle Ford volumes. To handle our increased production, we have secured multiple options for transportation and processing capacity with firm commitments in place to meet total planned production levels through 2014, and we are in the process of adding more firm capacity.

With the pending purchase of the Permian Basin Assets, we have revised our capital guidance range upward from $640 – $700 million to $840 – $900 million. The 2013 capital program is based on a five to six-rig program in South Texas and a Delaware Basin program with three rigs increasing to six rigs during the year. We expect to spend approximately $600 million for development activities primarily located in the liquids-rich window of the Eagle Ford shale in South Texas, including about $55 million allocated to facilities projects. We expect to direct approximately $175 million toward operated and non-operated development activity in the oil-rich Delaware Basin in West Texas, including approximately $7 million for facilities projects. Another $25 million of capitalized interest related to the pending Acquisition has also been included in the revised budget. The remainder of our 2013 capital plan will be targeted to new ventures activity and other corporate capital requirements.

While our unconventional resource strategy has proved to be successful, we recognize that there are risks inherent to our industry that could impact our ability to meet future goals. Although we cannot completely control all external factors that could affect our operating environment, our business model takes into account the threats that could impede achievement of our stated growth objectives and the building of our asset base. We have diversified our production base to include a greater mix of crude oil and NGLs, which continue to be priced at more favorable levels than natural gas. Because our production is highly concentrated in the Eagle Ford area, we have taken various steps to provide access to necessary services and infrastructure. We believe that our 2013 capital program can be executed from internally generated cash flows, cash on hand, and drawing on unused capacity under our existing Credit Facility. We continuously monitor our liquidity to respond to changing market conditions, commodity prices and service costs. If our internal funds are insufficient to meet projected funding requirements, we would consider curtailing capital spending or accessing the capital markets.

Availability under our Credit Facility is restricted to a borrowing base, which is subject to review and adjustment on a semiannual basis and other interim adjustments, including adjustments based on hedging arrangements and asset divestitures. The amount of the borrowing base is dependent on a number of factors, including our level of reserves, as well as the pricing outlook at the time of the redetermination. Subsequent to March 31, 2013, we amended our Credit Facility to provide a maximum credit amount of $1.5 billion (subject to a borrowing base), revised from the previous amount of $750 million. The semi-annual borrowing base redetermination was recently completed for the Credit Facility and effective April 12, 2013 our borrowing base increased from $625 million to $800 million. Additionally, the maturity date of the Credit Agreement has been extended to April 12, 2018. See Note 13 – Subsequent Events. Net proceeds received from the equity offering were used to repay outstanding indebtedness of $305 million under the Credit Facility and as of May 1, 2013, we had no borrowings outstanding with $800 million available for borrowing under the Credit Facility.

Results of Operations

Revenues

Our consolidated financial statements for the three months ended March 31, 2013 reflect total revenue of $178.1 million based on total volumes of 4.2 MMBoe and is net of derivative losses of $12.0 million.

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


	Three Months Ended March 31,
	2013			2012			% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Revenues:
Oil sales	$	110,052		$	62,970			75	%
NGL sales		46,461			43,760			6	%
Natural gas sales		33,576			23,689			42	%
Derivative instruments		(11,969	)		(15,961	)		25	%

Total revenues	$	178,120		$	114,458			56	%


Production:
Oil (MBbls)		1,117.9			677.3			65	%
NGLs (MBbls)		1,488.9			909.4			64	%
Natural gas (MMcf)		9,738.4			8,950.0			9	%

Total equivalents (MBoe)		4,229.9			3,078.4			37	%


Average sales price:
Oil, excluding derivatives (per Bbl)	$	98.45		$	92.97			6	%
Oil, including realized derivatives (per Bbl)		96.55			92.81			4	%

NGL, excluding derivatives (per Bbl)		31.20			48.12			(35	%)
NGL, including realized derivatives (per Bbl)		32.92			45.49			(28	%)

Natural gas, excluding derivatives (per Mcf)		3.45			2.65			30	%
Natural gas, including realized derivatives (per Mcf)		3.61			3.15			15	%

Revenue, excluding realized derivatives (per Boe)		44.94			42.37			6	%
Revenue, including realized derivatives (per Boe)		45.41			43.01			6	%

Oil sales. For the three months ended March 31, 2013, oil revenue, excluding derivative instruments, increased by $47.1 million from the same period in 2012 due to higher oil production and higher realized prices. The increase in oil production was primarily attributable to our Gates Ranch and Klotzman wells in the Eagle Ford area, whose combined total oil production was 11.2 MBbls per day and 6.5 MBbls per day for the three months ended March 31, 2013 and 2012, respectively. Realized oil derivative losses of $2.1 million and $0.1 million for the three months ended March 31, 2013 and 2012, respectively, are reported as a component of Derivative instruments within Revenues.

NGL sales. For the three months ended March 31, 2013, NGL revenue, excluding derivative instruments, increased by $2.7 million from the same period in 2012. The increase was attributable to increased production offset by lower average realized prices. The increase in NGL production was primarily attributable to our Gates Ranch wells in the Eagle Ford area, whose total NGL production was 14.5 MBbls per day and 9.0 MBbls per day for the three months ended March 31, 2013 and 2012, respectively. Realized NGL derivative gains of $2.5 million for the three months ended March 31, 2013 and realized derivative losses of $2.4 million for the three months ended March, 31, 2012 are reported as a component of Derivative instruments within Revenues.

Natural gas sales. For the three months ended March 31, 2013, natural gas revenue, excluding derivative instruments, increased by $9.9 million from the same period in 2012. The increase was primarily due to higher average realized prices and increased production. The increase in natural gas production of 9% was primarily attributable to our Gates Ranch wells in the Eagle Ford area, whose total natural gas production was 95.5 MMcf per day and 77.2 MMcf per day for the three months ended March 31, 2013 and 2012, respectively. The increase in natural gas production was partially reduced by the 2012 divestiture of our Lobo properties. Realized gas derivative gains of $1.6 million and $4.5 million for the three months ended March 31, 2013 and 2012, respectively, are reported as a component of Derivative instruments within Revenues.

Derivative instruments. For the three months ended March 31, 2013, Derivative instruments included an unrealized derivative loss of $13.5 million due to changes in fair value on commodity derivative contracts, the reclassification of an unrealized derivative loss of $0.4 million from Accumulated other comprehensive income, and a realized derivative gain of $2.0 million from derivative settlements. These realized derivative gains represent cash settlements associated with our commodity derivative contracts. For the three months ended March 31, 2012, Derivative instruments included an unrealized derivative loss of $18.0 million due to changes in fair value on commodity derivative contracts, an unrealized derivative gain of $0.1 million due to the reclassification of commodity hedging gains from Accumulated other comprehensive income, and a realized derivative gain of $1.9 million from derivative settlements.

Operating Expenses

The following table presents information regarding our operating expenses:


	Three Months Ended March 31,
	2013		2012			% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Direct lease operating expense	$	8,354	$	5,836			43	%
Workover expense		354		(221	)		260	%
Insurance expense		203		369			(45	%)

Production costs		8,911		5,984			49	%
Ad valorem taxes		2,263		2,517			(10	%)

Lease operating expense	$	11,174	$	8,501			31	%
Treating and transportation		15,087		11,998			26	%
Production taxes		5,392		3,228			67	%
Depreciation, depletion and amortization (DD&A)		44,630		32,899			36	%
General and administrative costs		15,532		17,291			(10	%)

Costs and expenses (per Boe of production)
Lease operating expense	$	2.64	$	2.76			(4	%)
Treating and transportation		3.57		3.90			(8	%)
Production taxes		1.27		1.05			21	%
Depreciation, depletion and amortization (DD&A)		10.55		10.69			(1	%)
General and administrative costs		3.67		5.62			(35	%)
General and administrative costs, excluding stock-based compensation		3.04		3.86			(21	%)
Production costs		2.11		1.94			9	%

Lease operating expense. Lease operating expense increased $2.7 million for the three months ended March 31, 2013 as compared to the same period in 2012. The increase was a result of increased Eagle Ford operations, which contributed to an increase of $6.3 million, partially offset by a decline in costs of $3.6 million due to divestitures of dry gas properties.

Treating and transportation. Treating and transportation expense increased $3.1 million for the three months ended March 31, 2013 compared to the same period in 2012. The increase was a result of increased daily production of 54% in the Eagle Ford shale as well as higher unit costs required to transport incremental production from the area. Additionally, we have accrued deficiency fees of $1.4 million related to shortfalls in delivering the minimum volumes required under our transportation and processing agreements during the three months ended March 31, 2013.

Production taxes. Production taxes are highly correlated to commodity revenues, production volumes and commodity prices, which have impacted results for this expense item. Production taxes as a percentage of oil, NGL and natural gas sales were 2.8% for the three months ended March 31, 2013 compared to 2.5% for the same period in 2012. The increase in rates was primarily due to a higher percentage of our oil revenues being subject to taxation in the State of Texas.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $11.7 million for the three months ended March 31, 2013 compared to the same period in 2012. The increase for the three months ended March 31, 2013 was due to a 37% increase in production, partially offset by a lower DD&A rate due to lower development costs in the Eagle Ford.

General and administrative costs. General and administrative costs decreased $1.8 million for the three months ended March 31, 2013 as compared to the same period in 2012. The decrease for the three months ended March 31, 2013 was primarily due to a $2.8 million decrease in stock-based compensation expense, driven by a lower number of PSUs outstanding in 2013 and a lower stock price as compared to the prior comparable period. The decrease in stock-based compensation expense was partially offset by a $1.0 million increase in other general and administrative expenses primarily due to certain transaction costs associated with the Acquisition, in addition to a higher number of employees and higher office rent compared to the same period in 2012.

Total Other Expense

Total other expense, which includes Interest expense, net of interest capitalized; Interest income; and Other income/expense, net, increased $0.5 million for the three months ended March 31, 2013 compared to the same period in 2012. The increase was primarily due to an increase in debt outstanding compared to the prior comparable period and a decrease in capitalized interest primarily due to a lower weighted average interest rate. The weighted average interest rate for the three months ended March 31, 2013 was 5.42% compared to 8.25% for the same period in 2012 and was due to a higher proportional mix of debt outstanding under the Credit Facility.

Provision for Income Taxes

The effective tax rate for the three months ended March 31, 2013 and 2012 was 33.4% and 36.2%, respectively. The provision for income taxes for the three months ended March 31, 2013 differs from the tax computed at the federal statutory income tax rate primarily due to the effects of state taxes and the non-deductibility of certain incentive compensation. In addition, during the first quarter of 2013 there was a one-time favorable discrete adjustment of (2.9%) to reflect a change in the amount of deductible executive compensation. Excluding the discrete item, the effective tax rate for the first quarter of 2013 was 36.3%, and the rate applicable to future earnings is expected to be consistent with this rate. As of March 31, 2013 and December 31, 2012, we had no unrecognized tax benefits and we do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations within the next twelve months.

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of March 31, 2013, we had a net deferred tax liability of $35.9 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of our oil and natural gas properties.

Liquidity and Capital Resources

Our sources of liquidity and capital are our operating cash flow and our Credit Facility, which can be accessed as needed to supplement operating cash flow.

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

Subsequent Events. See Item 1. “Financial Statements, Note 13 – Subsequent Events” for a description of our Sixth Amendment to our Credit Agreement, repayment of borrowings outstanding thereunder, our public offering of 8,050,000 shares of common stock and our issuance of $700.0 million in aggregate principal amount of 5.625% Senior Notes.

Cash Flows

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


	Three Months Ended March 31,
	2013			2012
	(In thousands)

Cash provided by (used in):
Operating activities	$	141,639		$	73,711
Investing activities		(216,900	)		(62,357	)
Financing activities		49,152			(5,313	)

Net (decrease) increase in cash and cash equivalents	$	(26,109	)	$	6,041

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2013 compared to the same period in 2012 reflects higher operating income in 2013 as a result of increased liquids production and an expansion of our production base to include a greater mix of crude oil and NGLs, which continue to be priced at more favorable levels than natural gas.

Investing Activities. Net cash used in investing activities for the three months ended March 31, 2013 compared to the same period in 2012 reflects higher capital spending related to our Eagle Ford drilling program and a $38.4 million deposit in connection with the Acquisition.

Financing Activities. Net cash provided by financing activities for the three months ended March 31, 2013 compared to the same period in 2012 reflects net borrowings of $55.0 million under the Credit Facility in 2013, partially offset by treasury stock repurchases of $6.3 million.

Capital Expenditures and Requirements

Our historical capital expenditures summary table is included in Items 1 and 2. Business and Properties in our 2012 Annual Report and is incorporated herein by reference.

Our capital expenditures for the three months ended March 31, 2013 increased by $28.4 million to $161.1 million from $132.7 million for the three months ended March 31, 2012. During the three months ended March 31, 2013, we drilled 24 and completed 17 gross wells, the majority of which were located in the Eagle Ford area. At current commodity prices, our positive operating cash flow and liquidity from the Credit Facility should be sufficient to fund planned capital expenditures for the remainder of 2013, which are projected to be approximately $840 to $900 million compared to our previous budget range of $640 to $700 million.

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

Fair Value of Financial Instruments

The energy markets have historically been very volatile and oil, NGL and natural gas prices will be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management hedges oil, NGL and natural gas prices from time to time, primarily through the use of certain derivative instruments, including fixed price swaps, basis swaps, NYMEX roll swaps, costless collars and put options. Although not risk-free, we believe these activities will reduce our exposure to commodity price fluctuations and thereby enable us to achieve a more predictable cash flow to fund our capital program. Consistent with this policy, we have entered into a series of oil, NGL and natural gas fixed price swaps, basis swaps, NYMEX roll swaps and costless collars for each year through 2015. Our fixed price swap, basis swap, NYMEX roll swap and costless collar agreements require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of oil, NGLs and natural gas, as applicable, without the exchange of underlying volumes. The notional amounts of these financial instruments were based on a portion of our expected production from existing wells upon inception of the derivative instruments. See Note 4 – Commodity Derivative Contracts and Note 5 – Fair Value Measurements included in Part I. Item 1. Financial Statements of this Form 10-Q for a listing of open contracts as of March 31, 2013, a description of the applicable accounting and the estimated fair market values as of March 31, 2013. The effects of material changes in market risk exposure associated with these derivative transactions are discussed below under “Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

Governmental Regulation

There have been no material changes in governmental regulations from those previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of generally accepted accounting principles that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2012 Annual Report.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 2 – Summary of Significant Accounting Policies included in Part I. Item 1. Financial Statements of this Form 10-Q.

Commitments and Contingencies

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

As noted in Note 9 – Commitments and Contingencies included in Part I. Item 1. Financial Statements of this Form 10-Q, we have certain commitments for the transportation and processing of our production in the Eagle Ford area. Currently, we have insufficient production to meet all of our contractual commitments. However, we intend to completely fulfill the delivery commitments by 2015 with production from the development of our proved reserves, as well as the development of resources not yet characterized as proved reserves, in the Eagle Ford area. As we develop our Eagle Ford assets, we intend to enter into additional transportation and processing commitments in the future that may expose us to additional volume deficiency payments. As of March 31, 2013, we had accrued deficiency fees of $1.4 million and expect to continue to accrue additional deficiency fees under our current commitments.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk primarily related to adverse changes in oil, NGL and natural gas prices. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2012 Annual Report and Note 4 – Commodity Derivative Contracts included in Part I. Item 1. Financial Statements of this Form 10-Q.

As of March 31, 2013, we had open crude oil derivative contracts in a net liability position with a fair value of $0.7 million. A ten percent increase in crude oil prices would reduce the fair value by approximately $34.9 million, while a ten percent decrease in crude oil prices would increase the fair value by approximately $32.9 million. The effects of these derivative transactions on our revenues are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.”

As of March 31, 2013, we had open NGL derivative contracts in a net asset position with a fair value of $12.0 million. A ten percent increase in NGL prices would reduce the fair value by approximately $12.7 million, while a ten percent decrease in NGL prices would increase the fair value by approximately $14.8 million. The effects of these derivative transactions on our revenues are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.”

As of March 31, 2013, we had open natural gas derivative contracts in a net liability position with a fair value of $4.2 million. A ten percent increase in natural gas prices would reduce the fair value by approximately $14.2 million, while a ten percent decrease in natural gas prices would increase the fair value by approximately $14.1 million. The effects of these derivative transactions on our revenues are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.”

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

As of March 31, 2013, the Company’s derivative instruments are with counterparties who are lenders under the Company’s Credit Facility. This practice allows us to satisfy any need for margin obligations resulting from an adverse change in the fair market value of the derivative contracts with the collateral securing our Credit Facility, thus eliminating the need for independent collateral postings. As of March 31, 2013, we had no deposits for collateral regarding commodity derivative instruments. Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and future market prices on hedged volumes of the commodities as of March 31, 2013. Our third-party provider evaluated non-performance risk using the current credit default swap values for both the counterparties and us. We recorded an immaterial downward adjustment to the fair value of our derivative instruments as of March 31, 2013. We currently do not know of any circumstances that would limit access to our Credit Facility or require a change in our debt or hedging structure.

We entered into oil, NGL and natural gas price derivative contracts with respect to a portion of our expected production through 2015. These derivative contracts may limit our potential revenue if oil, NGL and natural gas prices were to exceed the price established by the contract. As of March 31, 2013, 84% of our crude oil derivative transactions represented hedged prices of crude oil at West Texas Intermediate on the NYMEX with the remaining 16% at Light Louisiana Sweet; 100% of our total NGL derivative transactions represented hedged prices of NGLs at Mont Belvieu; and 100% of total natural gas derivative transactions represented hedged prices of natural gas at Houston Ship Channel.

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

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of March 31, 2013. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2013, 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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Except as noted below, there have been no material changes in our risk factors from those previously disclosed in Item 1A. of our 2012 Annual Report.

Financing the Acquisition will substantially increase our leverage.

We have arranged to finance a portion of the consideration of the Acquisition through the issuance of the 5.625% Senior Notes in the principal amount of $700 million. As a result of the issuance of the 5.625% Senior Notes, our leverage and annual interest costs will increase substantially. In addition, the capital expenditures to be incurred in relation to the Permian Basin Assets, including those expenditures required to maintain leasehold positions, is expected to be greater than the anticipated cash flows generated by those assets for several years. This is currently expected to be funded from cash flows from our Eagle Ford assets, as well as borrowings under our Credit Facility. These increases in our indebtedness and any future reductions in the available capacity under the Credit Facility may reduce our flexibility to respond to changing business and economic conditions or to fund our capital expenditures or working capital needs.

We may not be able to consummate the Acquisition.

If the Acquisition is not consummated by July 15, 2013, or the purchase and sale agreement is terminated at any time prior to the consummation of the Acquisition, we will be required to redeem the 5.625% Senior Notes in cash at a redemption price equal to 100% of their aggregate principal amount, plus accrued and unpaid interest to the date of redemption. The purchase and sale agreement contains customary conditions for closing, many of which are beyond our control, and we may not be able to complete the Acquisition prior to July 15, 2013. If the Acquisition is not consummated under certain circumstances, we may be required to forfeit a deposit under the Comstock purchase and sale agreement. Furthermore, our stock price could be negatively impacted if we fail to complete the Acquisition.

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, 2013:


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		30,231	$	47.13		—		—
February 1 – February 28		88,233		50.79		—		—
March 1 – March 31		7,220		48.41		—		—

Total		125,684	$	49.77		—		—

(1)	All of the shares were surrendered by our employees and certain of our directors to pay tax withholding upon the vesting of restricted stock awards. We do not have a publicly announced program to repurchase shares of common stock.

Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits


Exhibit Number		Description

2.2*		Purchase and Sale Agreement with Comstock Oil & Gas, LP dated March 14, 2013

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Schema Document

101.CAL*		XBRL Calculation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document

101.LAB*		XBRL Label Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

*	Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


ROSETTA RESOURCES INC.

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

(Duly Authorized Officer and Principal Financial Officer)

Date: May 6, 2013