Edgar Filing: Rosetta Resources Inc.

Form 10-Q for quarterly period ended March 31, 2006

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, 2006

¨	Transition Report Pursuant To Section 15(d) of The Securities Exchange Act of 1934

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)


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

717 Texas, Suite 2800, Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

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

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non-Accelerated filer x

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

The number of shares of the registrant’s Common Stock, $.001 par value per share, outstanding as of May 5, 2006 was 50,591,819.

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	25

	Item 4. Controls and Procedures	25

Part II –	Other Information

	Item 1. Legal Proceedings	25

	Item 1A. Risk Factors	25

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	26

	Item 3. Defaults upon Senior Securities	26

	Item 4. Submission of Matters to a Vote of Security Holders	26

	Item 5. Other Information	26

	Item 6. Exhibits	26

Signatures		27

Exhibit Index		28

Rule 13a-14(a) Certification executed by B.A. Berilgen

Rule 13a-14(a) Certification executed by Michael J. Rosinski

Section 1350 Certification

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Part I. Financial Information

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except per share amounts)


	March 31, 2006			December 31, 2005
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	103,751		$	99,724
Accounts receivable		31,839			40,051
Derivative instruments		4,892			1,110
Deferred income taxes		—			10,962
Current income tax receivable		—			6,000
Other current assets		13,939			9,411

Total current assets		154,421			167,258

Oil and natural gas properties, full cost method, of which $40 million at March 31, 2006 and $37 million at December 31, 2005 were excluded from amortization		1,011,219			973,185
Other		3,470			2,912

		1,014,689			976,097
Accumulated depreciation, depletion, and amortization		(64,049	)		(40,161	)

Total property and equipment, net		950,640			935,936
Long-term accounts receivable		1,358			1,726
Deferred loan fees		4,260			4,555
Deferred income taxes		—			8,594
Other assets		1,025			1,200

Total other assets		6,643			16,075

Total assets	$	1,111,704		$	1,119,269

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	13,981		$	13,442
Royalties payable		12,901			15,511
Derivative instruments		529			29,957
Interest payable		189			133
Prepayment on gas sales		11,057			14,528
Deferred income taxes		1,658			—
Other current liabilities		25,298			28,264

Total current liabilities		65,613			101,835
Long-term liabilities:
Derivative instruments		35,999			52,977
Long-term debt		240,000			240,000
Asset retirement obligation		9,227			9,034
Deferred income taxes		3,776			—

Total liabilities		354,615			403,846
Commitments and contingencies (Note 9)
Stockholders’ Equity:
Common stock, $0.001 par value, 150,000,000 shares authorized, 50,288,950 issued		50			50
Additional paid-in capital		750,839			748,569
Treasury stock, at cost; 66,831 and no shares at March 31, 2006 and December 31, 2005, respectively.		(1,246	)		—
Accumulated other comprehensive loss		(19,615	)		(50,731	)
Retained Earnings		27,061			17,535

Total stockholders’ equity		757,089			715,423

Total liabilities and stockholders’ equity	$	1,111,704		$	1,119,269

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

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Rosetta Resources Inc.

Consolidated/Combined Statements of Operations

(In thousands, except share and per share amounts)

(Unaudited)


	Successor- Consolidated			Predecessor- Combined
	Three Months Ended March 31,
	2006			2005
Revenues:
Natural gas sales	$	56,730		$	6,742
Oil sales		7,809			3,998
Oil and natural gas sales to affiliates		—			39,776
Other revenue		5			39

Total revenues		64,544			50,555
Operating Costs and Expenses:
Lease operating expense		9,558			7,537
Depreciation, depletion, and amortization		24,067			15,124
Exploration expense		—			1,429
Dry hole costs		—			76
Treating and transportation		895			968
Affiliated marketing fees		—			439
Marketing fees		624			—
Production taxes		1,697			1,188
General and administrative costs		9,251			3,345

Total operating costs and expenses		46,092			30,106

Operating income		18,452			20,449

Other (income) expense
Interest expense with affiliates, net of interest capitalized		—			3,617
Interest expense, net of interest capitalized		4,132			—
Interest income		(1,137	)		(253	)
Other expense (income), net		25			(96	)

Total other expense		3,020			3,268

Income before provision for income taxes		15,432			17,181
Provision for income taxes		5,906			6,519

Net income	$	9,526		$	10,662

Earnings per share:

Basic	$	0.19		$	0.21

Diluted	$	0.19		$	0.21

Weighted average shares outstanding:
Basic		50,120,907			50,000,000
Diluted		50,355,256			50,160,000

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

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Rosetta Resources Inc.

Consolidated/Combined Statements of Cash Flows

(In thousands)

(Unaudited)


	Successor- Consolidated			Predecessor- Combined
	Three Months Ended March 31,
	2006			2005
Cash flows from operating activities
Net income	$	9,526		$	10,662
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		24,067			15,124
Affiliate interest expense		—			3,617
Deferred income taxes		5,906			2,242
Amortization of deferred loan fees recorded as interest expense		295			—
Income from unconsolidated investments		25			(396	)
Stock compensation expense		1,835			—
Other non-cash charges		—			202
Change in operating assets and liabilities:
Accounts receivable		8,212			2,406
Accounts receivable from affiliates		—			3,217
Current income taxes receivable		6,000			4,277
Other Assets		(4,528	)		379
Long-term accounts receivable		368			—
Royalties payable		(6,081	)		(1,603	)
Accounts payable		(1,753	)		(79	)
Interest payable		56			—
Other current liabilities		(2,913	)		835

Net cash provided by operating activities		41,015			40,883

Cash flows from investing activities
Purchases of property and equipment		(36,325	)		(18,233	)
Disposals of property and equipment		—			636
Deposits		25			—
Other		111			365

Net cash used in investing activities		(36,189	)		(17,232	)

Cash flows from financing activities
Equity offering transaction fees		267			—
Notes payable to affiliates		—			(23,136	)
Proceeds from issuances of common stock		192			—
Purchases of treasury stock		(1,246	)		—
Other		(12	)		—

Net cash used in financing activities		(799	)		(23,136	)

Net increase in cash		4,027			515
Cash and cash equivalents, beginning of period		99,724			—

Cash and cash equivalents, end of period	$	103,751		$	515

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	2,249			—

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

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Rosetta Resources Inc.

Notes to Consolidated/Combined Financial Statements (unaudited)

(1) Organization and Operations of the Company

Nature of Operations. Rosetta Resources Inc. (“the Company”), formed in June 2005, is comprised of the domestic oil and natural gas business formerly owned by Calpine Corporation and affiliates (predecessor, “Calpine”). The Company (“Successor”) is engaged in oil and natural gas exploration, development, production, and acquisition activities in the United States. The Company’s operations are primarily concentrated in the Sacramento Basin of California, Lobo and Perdido Trends in South Texas, the State Waters of Texas, the shallow waters of the Gulf of Mexico and the Rocky Mountains.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of the financial statements have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America.

These financial statements and notes should be read in conjunction with our audited consolidated/combined financial statements and the notes thereto included in our annual report for the year ended December 31, 2005.

Certain reclassifications of prior year balances have been made to conform such amounts to corresponding 2006 classifications. These reclassifications have no impact on net income.

(2) Acquisition of Calpine Oil and Natural Gas Business

On July 7, 2005, the Company acquired the oil and natural gas business of Calpine, excluding certain non-consent properties, for approximately $910 million. This acquisition was funded with the issuance of common stock totaling $725 million and $325 million of debt from our credit facilities. The transaction was accounted for under the purchase method in accordance with SFAS 141. The results of operations were included in the Company’s financial statements effective July 1, 2005 as the operating results in the intervening period are not significant. The preliminary purchase price was calculated as follows:


Cash from equity offering	$	725,000
Proceeds from revolver		225,000
Proceeds from term loan		100,000
Other purchase price costs		(53,389	)
Transaction adjustments (purchase price adjustments)		(11,556	)
Transaction adjustments (non-consent properties)		(74,991	)

Initial purchase price	$	910,064

Other purchase price costs relate primarily to professional fees of $3.9 million and other direct transaction costs of $49.5 million.

The transaction adjustments (purchase price adjustments) is an amount agreed upon by Calpine Corporation and the Company to cover potential costs and/or revenues that will be adjusted to actual upon the final closing of the transaction.

Transaction adjustments (non-consent properties) relate to properties which required third party consents or waivers of preferential purchase rights necessary in order to effect transfer of title. At July 7, 2005, we withheld $75 million of the purchase price with respect to these non-consent properties. These funds are held by us and, despite Calpine’s bankruptcy filing, management believes that it remains likely that conveyance of substantially all of these non-consent properties will occur ($7.4 million being subject to an exercised preference purchase right). Upon conveyance, such additional purchase price will be paid to Calpine and will be incremental to the initial purchase price of $910 million. We have excluded the effects of the operating results for the non-consent properties from our actual results for the three month period ended March 31, 2006. If the assignment of these properties does not occur, the portion of the purchase price we withheld pending obtaining consent for these properties will be available to us for general corporate purposes or to acquire other properties.

The following is the allocation of the purchase price to specific assets acquired and liabilities assumed based on estimates of the fair values and costs (In thousands). There was no goodwill associated with the transaction.


Current assets	$	1,794
Non-current assets		5,087
Properties, plant and equipment		925,141
Current liabilities		(14,390	)
Long-term liabilities		(7,568	)

	$	910,064

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The purchase price allocation is preliminary in nature and is subject to changes as additional information becomes available and title is obtained for the non-consent properties. Management does not expect the final purchase price allocation to differ materially, with the exception of the conveyance of the non-consent properties discussed above.

The unaudited pro forma information below of operations for the three months ended March 31, 2005 assumes the acquisition of Calpine’s domestic oil and natural gas business and the related financings occurred on January 1, 2004. We believe the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to such transactions. The unaudited pro forma financial statements do not purport to represent what our results of operations would have been if such transactions had occurred on such date.


	Three Months Ended March 31, 2005
	(In thousands, except per share amounts)
	(Unaudited)
Revenues	$	50,555
Net income		7,958
Basic earnings per common share		0.16
Diluted earnings per common share		0.16

(3) Summary of Significant Accounting Policies

The Company has provided discussion of significant accounting policies, estimates and judgments in its annual report for the year ended December 31, 2005.

Principles of Consolidation/Combination and Basis of Presentation. The Company purchased the domestic oil and natural gas business of Calpine which was separately accounted for and managed through direct and indirect subsidiaries of Calpine. As a result, the results of operations for the three month period ended March 31, 2005 of this domestic oil and gas business comprise the predecessor combined financial statements.

The predecessor combined financial statements have been prepared from the historical accounting records of the domestic oil and natural gas business of Calpine and are presented on a carve-out basis to include the historical operations of the domestic oil and gas business. The combined financial information included herein includes certain allocations based on the historical activity levels to reflect the combined financial statements in accordance with accounting principles generally accepted in the United States of America and may not necessarily reflect the financial position, results of operations and cash flows of the Company in the future or as if the Company had existed as a separate, stand-alone business during the period presented. The allocations consist of general and administrative expenses (employee payroll and related benefit costs, building lease expense, among other items) incurred on behalf of Calpine. The allocations have been made on a reasonable basis and have been consistently applied for the period presented.

The accompanying consolidated financial statements as of March 31, 2006 and December 31, 2005 and for the three month period ended March 31, 2006 contain the accounts of Rosetta Resources Inc. and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.

Property, Plant, and Equipment, Net. In connection with the Company’s separation from Calpine, the Company adopted the full cost method of accounting for oil and natural gas properties beginning July 1, 2005. Under the full cost method, all costs incurred in acquiring, exploring, and developing properties within a relatively large geopolitical cost

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center are capitalized when incurred and are amortized as mineral reserves in the cost center produced, subject to a limitation that the capitalized costs not to exceed the value of those reserves. In some cases, however, certain significant costs, such as those associated with offshore U.S. operations, are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with acquisition, exploration and development activities and certain costs related to general corporate overhead or similar activities. The Company capitalized $0.8 million of internal costs for the three months ended March 31, 2006. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable cost center. The Company assesses the impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes should not exceed the following: (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues should be based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test must take into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price should be consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. Application of the ceiling test is required for quarterly reporting purposes, and any write-downs cannot be reinstated even if the cost ceiling subsequently increases by year-end. No ceiling test write-down was recorded for the three months ended March 31, 2006 (successor).

Calpine followed the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs were capitalized. Exploratory drilling costs were capitalized until the results were determined. If proved reserves were not discovered, the exploratory drilling costs were expensed. Other exploratory costs were expensed as incurred. Interest costs related to financing major oil and natural gas projects in progress were capitalized until the projects were evaluated or until the projects were substantially complete and ready for their intended use if the projects were evaluated as successful. Calpine also capitalized internal costs directly identified with acquisition, exploration and development activities and did not include any costs related to production, general corporate overhead or similar activities. The provision for depreciation, depletion, and amortization was based on the capitalized costs as determined above, plus future abandonment costs net of salvage value, using the unit of production method with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

Calpine assessed the impairment for oil and natural gas properties on a field by field basis periodically (at least annually) to determine if impairment of such properties was necessary. Management utilized its year-end reserve report prepared by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc., and related market factors to estimate the future cash flows for all proved developed (producing and non-producing) and proved undeveloped reserves. Property impairments occurred if a field discovered lower than anticipated reserves, reservoirs produced at a rate below original estimates or if commodity prices fell below a level that significantly affected anticipated future cash flows on the property. Proved oil and natural gas property values were reviewed when circumstances suggested the need for such a review and, if required, the proved properties were written down to their estimated fair market value based on proved reserves and other market factors. Unproved properties were reviewed quarterly to determine if there was impairment of the carrying value, with any such impairment charged to expense in the period. No impairment charge was recorded for the three months ended March 31, 2005 (predecessor).

Stock-Based Compensation.

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payments” (“SFAS-123R”). This statement applies to all awards granted, modified, repurchased or cancelled after January 1, 2006 and to the unvested portion of all awards granted prior to that date. The Company adopted this statement using the modified version of the

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prospective application (modified prospective application). Under the modified prospective application, compensation cost for the portion of awards for which the employee’s requisite service has not been rendered that are outstanding as of January 1, 2006 must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of awards shall be based on the original fair market value of those awards on the date of grant as calculated for recognition under SFAS 123. The compensation cost for these earlier awards shall be attributed to periods beginning on or after January 1, 2006 using the attribution method that was used under SFAS 123. The impact of adoption of SFAS-123R decreased income from operations and income before income taxes by approximately $0.5 million and decreased net income by $0.3 million for the three months ended March 31, 2006 and there was no impact on the Consolidated Statement of Cash Flows. The effect on net income per share for basic and diluted is $0.01. See Note 10 of the notes to the Consolidated/Combined Financial Statements for additional disclosure.

Recent Accounting Developments

Accounting Changes and Error Corrections. In May 2005 the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”)”, which changes the requirements for the accounting for and the reporting of a change in accounting principle. This Statement applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of this Statement did not impact the Company’s consolidated financial position or results of operations.

Accounting for Certain Hybrid Financial Instruments. In February 2006 , the FASB issued SFAS No. 155, Accounting for Certain Hybrid Instruments-an amendment of FASB Statements 133 and 140, which is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The statement improves financial reporting by eliminating the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. The Statement also improves financial reporting by allowing a preparer to elect fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event, on an instrument–by–instrument basis, in cases in which a derivative would otherwise have to be bifurcated, if the holder elects to account for the whole instrument on a fair value basis. The Company is currently evaluating the impact, if any, of this statement on the consolidated financial position or results of operations.

(4) Property, Plant and Equipment

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


	March 31, 2006			December 31, 2005
	(In thousands)
Proved properties	$	988,387		$	951,968
Unproved properties		22,832			21,217
Other		3,470			2,912

Total		1,014,689			976,097
Less: accumulated depreciation, depletion, and amortization		(64,049	)		(40,161	)

Net capitalized costs	$	950,640		$	935,936

Included in the Company’s oil and gas properties are asset retirement obligations of $9.1 million.

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At March 31, 2006 and December 31, 2005, the Company excluded the following capitalized costs from depletion, depreciation and amortization:


	March 31, 2006		December 31, 2005
	(In thousands)
Onshore:
Development cost	$	9,826	$	4,589
Exploration cost		3,556		6,144
Acquisition cost of undeveloped acreage		21,956		19,684
Capitalized interest		876		555

Total		36,214		30,972

Offshore:
Exploration cost		206		5,095
Acquisition cost of undeveloped acreage		—		950
Capitalized interest		—		27

Total		206		6,072

Total costs excluded from depreciation, depletion, and amortization	$	36,420	$	37,044

(5) Commodity Hedging Contracts and Other Derivatives

As of March 31, 2006, the Company had the following financial fixed price swaps outstanding with average underlying prices that represent hedged prices of commodities at various market locations:


Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu	Total of Notional Volume MMBtu	Average Underlying Prices MMBtu		Total of Proved Natural Gas Production Hedged (1)		Fair Market Value Gain/(Loss) (In thousands)
2006	Swap	Cash flow	45,000	12,375,000	$	7.92	46	%	$	5,592
2007	Swap	Cash flow	36,300	13,249,500		7.62	33	%		(17,609	)
2008	Swap	Cash flow	30,876	11,300,616		7.30	27	%		(14,807	)
2009	Swap	Cash flow	26,141	9,541,465		6.99	26	%		(9,704	)

				46,466,581					$	(36,528	)

(1)

Estimated based on net gas reserves presented in the December 31, 2005 Netherland, Sewell & Associates, Inc. reserve report.

As of March 31, 2006, the Company had the following costless collar transactions outstanding with associated notional volumes and contracted ceiling and floor prices that represent hedge prices at various market locations:

Settlement

Period

Derivative
Instrument

Hedge
Strategy

Notional
Daily
Volume
MMBtu

Total of
Notional
Volume
MMBtu

Average
Floor Price
MMBtu

Average
Ceiling Price
MMBtu

Fair Market
Value

Gain/(Loss)
(In thousands)

2006

Costless Collar

Cash flow

10,000

2,700,000

8.825

14.000

4,892

The total of proved natural gas production hedged in 2006 for the costless collars is approximately 10% based on the December 31, 2005 reserve report prepared by Netherland, Sewell & Associates, Inc.

The Company’s current cash flow hedge positions are with counterparties who are lenders in our credit facilities. This allows us to securitize any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with our credit obligations and eliminate the need for independent collateral postings. As of March 31, 2006, we had no deposits for collateral.

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The following table sets forth the results of third party hedging transactions for the respective period for the statement of operations:


	Successor
	Three Months Ended March 31, 2006
Natural Gas
Quantity settled (MMBtu)		4,950,000
Increase in natural gas sales revenue	$	1,562,914

The Company expects to reclassify gains of $2.7 million to earnings from the balance in Accumulated Other Comprehensive Loss during the next twelve months.

At March 31, 2006, the Company had derivative liabilities of $36.5 million of which $0.5 million is included in Derivative instruments under current liabilities on the Consolidated Balance Sheet. The Company also had a derivative instrument current asset of $4.9 million on the Consolidated Balance Sheet at March 31, 2006. The derivative instrument assets and liabilities related to commodities represent the difference between hedged prices and market prices on hedged volumes of the commodities as of March 31, 2006. Hedging activities related to cash settlements on commodities increased revenues by $ 1.6 million for the three months ended March 31, 2006 (successor).

Gains and losses related to ineffectiveness and derivative instruments not designated as hedging instruments are included in Other income (expense). There was no ineffectiveness related to cash-flow hedges recorded for the three months ended March 31, 2006 (successor). There were no gains related to derivative instruments not designated as hedged instruments for the three months ended March 31, 2005 (predecessor) as no derivative instruments existed.

The Company did not enter into any new derivative instruments during the first quarter of 2006.

(6) Comprehensive Income

For the three months ended March 31, 2006, comprehensive income consisted of the amounts listed below. For 2005, the predecessor did not have transactions affecting comprehensive income.


	March 31, 2006
	(In thousands)
Net income	$	9,526
Change in fair value of derivative hedging instruments		51,750
Hedge settlement reclassified to income		(1,563	)
Tax provision related to hedges		(19,071	)

Comprehensive Income	$	40,642

(7) Senior Credit Facility

Our credit facilities consist of a four-year senior secured revolving line of credit of up to $400 million with a borrowing base of $325 million and a five-year $75 million senior second lien term loan. All amounts drawn under the revolver are due and payable on July 7, 2009. The principal balance associated with the senior secured lien term loan is due and payable on July 7, 2010.

On March 31, 2006, we had outstanding borrowings and letters of credit under our credit facility of $240.0 million and $1.0 million, respectively. Net borrowing availability was $159.0 million at March 31, 2006. We were in compliance with all covenants at March 31, 2006.

(8) Asset Retirement Obligation

Activity related to the Company’s asset retirement obligation (ARO) as of March 31, 2006 is as follows:


	Three months ended March 31, 2006
	(In thousands)
ARO as of beginning of period	$	9,467
Liabilities incurred during period		21
Liabilities settled during period		(14	)
Accretion expense		180
Other Adjustments		(4	)

ARO as of end of period	$	9,650

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Of the total ARO, approximately $0.4 million is classified as a current liability at March 31, 2006.

(9) Commitment and Contingencies

The Company is party to various litigation matters arising out of the normal course of business. Although the ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operation or cash flows. As of March 31, 2006 and December 31, 2005, a reserve for legal fees was recorded in other current liabilities on the Consolidated Balance Sheets in the amount of $0.3 million and $0.4 million, respectively.

Calpine Bankruptcy

Calpine and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the Southern district of New York on December 20, 2005. The Company is not presently a party to any pending litigation in connection with this bankruptcy, although counsel has filed a notice of appearance on our behalf so we may effectively monitor the proceedings. Calpine Energy Services, L.P. has continued to make the required deposits into Rosetta’s margin account and to timely pay for production it purchases from the Company’s subsidiaries under various natural gas supply agreements. Calpine and certain of its subsidiaries have generally continued to provide services desired by the Company under the Transition Services Agreement and Calpine Producer Services, L.P. generally is performing its obligations under the Marketing and Services Agreement with us.

There remains the possibility, however, that there will be issues between the Company and Calpine that could amount to material contingencies in relation to the Purchase and Sale Agreement, dated July 7, 2005, by and among Calpine, the Company, and various other parties signatories thereto (the “Purchase Agreement”) including unasserted claims and assessments with respect to (i) the still pending final closing under the Purchase Agreement and the amounts that will be payable in connection therewith, (ii) whether or not Calpine and its affiliated debtors will, in fact, perform their remaining obligations in connection with the final closing and (iii) the ultimate disposition of certain properties (and related royalty revenues) for which third party consents to transfer had not been obtained at the time of the original closing under the Purchase Agreement. While the Company remains hopeful that it will be able to work cooperatively with Calpine as to accomplish the delivery by Calpine of legal record title including all ancillary ministerial and administrative corrections for all non-consent properties, as well as the curative corrections for all properties which the Company paid for, all of the same being covered by the further assurances provision of the parties’ definitive agreements, the timing and exact details of how, when, and if this will be able to be accomplished continue to remain uncertain at this early stage of Calpine’s bankruptcy. The Company’s management continues to believe that it is unlikely that any challenges by the Calpine debtors or their creditors to the fairness of the acquisition would be successful. At the present time, there is no pending or overtly threatened litigation in this regard. However, in the future there may be possible unasserted claims and assessments, seeking to challenge some aspects of the acquisition.

Environmental

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the cost can be reasonably estimated. The Company performed an environmental remediation study for three sites in California and correspondingly, recorded a liability, which at March 31, 2006 and December 31, 2005 was $0.7 million. We do not expect that the outcome of our environmental matters discussed above will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Participation in a Regional Carbon Sequestration Partnership

In accordance with its obligations to Calpine under the parties’ transition services agreement, the Company has made preliminary preparations in connection with its cooperating with Calpine to participate in a joint study in connection with the U.S. Department of Energy’s (“DOE”) Regional Carbon Sequestration Partnership program (“WESTCARB”) with the California Energy Commission and the University of California, Lawrence Berkeley Laboratory. The Company has been selected by the DOE for this project. Under WESTCARB, the Company would be required to drill a carbon injection well, recondition an idle well for use as an observation well and provide WESTCARB with certain proprietary well data and technical assistance related to the evaluation and injection of carbon dioxide into a suitable natural gas reservoir in the Sacramento Basin. The Company’s maximum contribution to WESTCARB is $1.0 million and will be limited to 20% of the total contributions to the project. The Company will not have any obligation under the WESTCARB project until it has

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entered into an acceptable contract and the project has obtained proper and necessary local, state and federal regulatory approvals, land use authorizations, and third party property rights. No accrual was recorded at March 31, 2006 as the study is still in the preliminary stage.

(10) Stock-Based Compensation

Successor

2005 Long-Term Incentive Plan

In July 2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan whereby stock is granted to employees, officers and directors of the Company. The Plan allows for the grant of stock options, stock awards, restricted stock, restricted stock units, stock appreciation rights, performance awards and other incentive awards. Employees, non-employee directors and other service providers of Rosetta and our affiliates who, in the opinion of the Committee, are in a position to make a significant contribution to the success of Rosetta and our affiliates are eligible to participate in the Plan. The Plan provides for administration by the Compensation Committee or another committee of our Board of Directors (the “Committee”), which determines the type and size of award and sets the terms, conditions, restrictions and limitations applicable to the award within the confines of the Plan’s terms. The maximum number of shares available for grant under the plan is 3,000,000 shares of common stock plus any shares of common stock that become available under the Plan for any reason other than exercise, such as shares traded for the related tax liabilities of employees. The maximum number of shares of common stock available for grant of awards under the Plan to any one participant is (i) 300,000 shares during any fiscal year in which the participant begins work for Rosetta and (ii) 200,000 shares during each fiscal year thereafter.

Adoption of SFAS-123R

On January 1, 2003, Calpine prospectively adopted the fair market value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation”, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure” (SFAS No. 123”). Expense amounts included in the combined historical financial statements for the three-months ended March 31, 2005 are based on stock based compensation granted to employees by Calpine. Stock options were granted at an option price equal to the quoted market price at the date of the grant or award.

In determining the Company’s accounting policies, the Company chose to apply the intrinsic value method pursuant to Accounting Standards Board (“APB”) No. 25, “Stock Issued to Employees” (“APB No. 25”), effective July 1, 2005. Under APB No. 25, no compensation is recognized when the exercise price for options granted equals the fair value of the Company’s common stock on the date of the grant. Accordingly, the provisions of SFAS No. 123 permit the continued use of the method prescribed by APB No. 25 but require additional disclosures, including pro forma calculations of net income (loss) per share as if the fair value method of accounting prescribed by SFAS No. 123 had been applied.

Effective January 1, 2006, the Company began accounting for stock-based compensation under SFAS-123R, whereby the Company records compensation expense based on the fair value of awards described below. Compensation expense for the three months ended March 31, 2006 (successor) and 2005 (predecessor) was $1.8 million and $0.1 million with a tax benefit of $0.7 million and $0.01 million , respectively. The remaining compensation expense associated with total unvested awards as of March 31, 2006 was $10.6 million and will be recognized over a weighted average period of 1.5 years.

Stock Options

The Company has granted stock options under its 2005 Long-Term Incentive Plan. Options generally expire ten years from the date of grant. The exercise price of the options can not be less than the fair market value per share of the Company’s common stock on the grant date.

The weighted average fair value at date of grant for options granted during the three month periods ended March 31, 2006 and 2005 was $10.82 and $1.27 per share, respectively. The fair value of options granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:


	Successor	Predecessor
	Three Months Ended March 31, 2006	Three Months Ended March 31, 2005
Expected option term (years)	6.5	2.5
Expected volatility	56.65%	58.00%
Expected dividend rate	0.00%	0.00%
Risk free interest rate	4.03% - 4.60%	3.62%

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The Company has assumed an annual forfeiture rate of 5 % for the awards granted in 2006 based on the Company’s history for this type of award to various employee groups. Compensation expense is recognized ratably over the requisite service period and immediately for retirement-eligible employees.

The following table summarizes information concerning outstanding and exercisable options held by the Company’s employees at March 31, 2006:


	Shares		Weighted Average Exercise Price Share		Weighted Average Remaining Contractual Term (In years)	Aggregate Intrinsic Value (In thousands)
Outstanding at the December 31, 2005	706,550		$	16.28
Granted	156,950			18.22
Exercised	(11,950	)		16.03
Cancelled	(21,750	)		16.22

Outstanding at March 31, 2006	829,800		$	16.66	9.41	$	1,151

Options Exercisable at March 31, 2006	187,062		$	16.27	9.30	$	324

Compensation expense recorded for stock option awards for the first quarter of 2006 (successor) and 2005 (predecessor) is $0.5 million and $0.1million, respectively. Unrecognized expense as of March 31, 2006 for all outstanding stock options is $6.1 million.

The total intrinsic value of options exercised during the three month periods ended March 31, 2006 was $0.1 million. For the three months ended March 31, 2005, the predecessor did not have any options exercised. The fair value of awards vested for the three month period ended March 31, 2006 was $5.1 million.

Restricted Stock

The Company has granted stock under its 2005 Long-Term incentive Plan with a maximum contractual life of three years. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The Company also assumes an annual forfeiture rate of 5 % for these awards based on the Company’s history for this type of award to various employee groups.

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The following table summarizes information concerning restricted stock held by the Company’s employees at March 31, 2006:


	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2005	581,900		$	16.27
Granted	63,000			18.21
Vested	(273,500	)		16.07
Forfeited	(15,000	)		16.21

Non-vested shares outstanding at March 31, 2006	356,400		$	16.77

The non-vested restricted stock outstanding at March 31, 2006 vests at a rate of 25% on the first anniversary, 25% on the second anniversary and 50% on the third anniversary. The restrictions on 270,000 shares lapsed on the day after the Company’s effective date of its recently completed initial public offering in February 2006 and therefore vested in the first quarter of 2006.

Compensation expense recorded for restricted stock awards for the first quarter of 2006 is $1.3 million. Unrecognized expense as of March 31, 2006 for all outstanding restricted stock awards is $4.5 million.

Predecessor

Retirement Savings Plan

Calpine had a defined contribution savings plan, under Section 401(a) and 501(a) of the Internal Revenue Code, in which Calpine’s employees were eligible to participate. The plan provided for tax deferred salary deductions and after-tax employee contributions. Employees were immediately eligible upon hire. Contributions included employee salary deferral contributions and employer profit-sharing contributions made entirely in cash of 4% of employees’ salaries, with employer contributions capped at $8,400 per year for 2005. There were no employer profit-sharing contributions for the three months ended March 31, 2005.

2000 Employee Stock Purchase Plan

Calpine adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000. Calpine’s eligible employees could, in the aggregate, purchase up to 28,000,000 shares of common stock at semi-annual intervals through periodic payroll deductions. Purchases were limited to either a maximum value of $25,000 per calendar year based on the IRS Code Section 423 limitation or limited to 2,400 shares per purchase interval. Shares were purchased on May 31 and November 30 of each year until termination of the plan on May 31, 2010. The purchase price was 85% of the lower of (i) the fair market value of the common stock on the participant’s entry date into the offering period, or (ii) the fair market value on the semi-annual purchase date. The purchase price discount was significant enough to cause the ESPP to be considered compensatory under SFAS No. 123. As a result, the ESPP was accounted for as stock-based compensation in accordance with SFAS No. 123 for the three-month period ended March 31, 2005. As the shares are purchased in May and November, there was no activity during the first quarter of 2005.

1996 Stock Incentive Plan

Calpine adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996 in which certain of the Company’s employees were eligible to participate. The SIP succeeded Calpine’s previously adopted stock option program. Under the SIP, the option exercise price generally equaled the stock’s fair market value on date of grant. The SIP options generally vested ratably over four years and expired after 10 years. As of March 31, 2005, 793,861 shares were outstanding under the 1996 stock incentive plan.

(11) Earnings Per Share

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

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


	Successor	Predecessor
	Three Months Ended March 31, 2006	Three Months Ended March 31, 2005
	(In thousands)
Basic weighted average number of shares outstanding	50,121	50,000
Dilution effect of stock option and awards at the end of the period	234	160

Diluted weighted average number of shares outstanding	50,355	50,160

Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect	103	—

(12) Operating Segments

The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information.” See below for information by geographic location.

Geographic Area Information

During the three months ended March 31, 2006 and 2005, the Company owned oil and natural gas interests in eight main geographic areas in the United States. Geographic revenue and property, plant and equipment information below (In thousands) is based on physical location of the assets at the end of each period.


	Successor				Predecessor
	Three Months Ended March 31, 2006				Three Months Ended March 31, 2005
	Total Oil & Gas Revenue (1)		Total Assets (2)		Total Oil & Gas Revenue (1)		Total Assets, Net
California	$	20,391	$	397,558	$	22,182	$	152,490
Lobo		15,408		371,822		12,597		350,055
Perdido		9,822		28,551		5,872		22,818
State Waters		3,148		19,632		14		5,150
Other Onshore		3,860		82,318		3,417		30,412
Gulf of Mexico		9,526		81,126		5,989		36,909
Rockies		342		23,919		75		6,239
Mid-Continent		479		6,365		370		3,172
Other		5		3,398		39		1,513

	$	62,981	$	1,014,689	$	50,555	$	608,758

(1)	Excludes the effects of hedging.

(2)	Total assets at March 31, 2006 are reported gross. Under the full cost method of accounting for oil and gas properties, depreciation, depletion and amortization is not allocated to properties.

(13) Subsequent Events

In April 2006, the Company acquired certain oil and gas producing non-operated properties located in Duval, Zapata and Jim Hogg Counties in Texas and Escambia County in Alabama from Contango Oil and Gas for $11.6 million in cash.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements, other than statements of historical fact, included in this prospectus, are forward-looking statements. In some cases, you can identify a forward-looking statement by terminology such as “may”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or other comparable terminology.

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions 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. Management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties, see Item 1A. Risk Factors in our annual report on Form 10-K for the year ended December 31, 2005. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events 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 the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to various factors, including:

•

the timing and extent of changes in commodity prices, particularly natural gas;

•

various drilling and exploration risks that may delay or prevent commercial operation of new wells;

•

economic slowdowns that can adversely affect consumption of oil and natural gas by businesses and consumers;

•

Calpine’s bankruptcy;

•

uncertainties that actual costs may be higher than estimated;

•

factors that impact the exploration of oil or natural gas resources, such as the geology of a resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas;

•

uncertainties associated with estimates of oil and natural gas reserves;

•

our ability to access the capital markets on attractive terms or at all;

•

refusal by or inability of our current or potential counterparties or vendors to enter into transactions with us or fulfill their obligations to us;

•

our inability to obtain credit or capital in desired amounts or on favorable terms;

•

present and possible future claims, litigation and enforcement actions;

•

effects of the application of regulations, including changes in regulations or the interpretation thereof;

•

availability of processing and transportation;

•

potential for disputes with mineral lease and royalty owners regarding calculation and payment of royalties, including basis of pricing, adjustment for quality, measurement and allowable costs and expenses;

•

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

•

competition in the oil and natural gas industry; and

•

adverse weather conditions and other natural disasters which may occur in areas of the United States in which we have operations, including the Federal waters of the Gulf of Mexico.

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

Overview

Rosetta Resources Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of natural gas and oil properties in the United States. We were formed as a Delaware corporation in June 2005. In July 2005, we acquired the domestic oil and natural gas business of Calpine Corporation and affiliates. Our operations are concentrated in the Sacramento Basin of California, Lobo and Perdido Trends in South Texas, and the shallow waters of the Gulf of Mexico.

In this section, we refer to Rosetta as “successor” and to the domestic oil and natural gas properties acquired from Calpine, “predecessor”.

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. Given the inherent volatility of oil and natural gas prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production. Our future earnings will also be impacted by the changes in fair market value of hedges we executed to mitigate the volatility in the changes of oil and natural gas prices in future periods when such positions are settled as these instruments meet the criteria to be accounted for as cash flow hedges. Until settlement, the changes in fair market value of our hedges will be included as a component of stockholder’s equity to the extent effective. In periods of rising prices, these transactions will mitigate future earnings and in periods of declining prices will increase future earnings in the respective period the positions are settled.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce our reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. The permitting and approval process has been more difficult in recent years than in the past due to increased activism from environmental and other groups and has extended the time it takes us to receive permits. We can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Calpine Bankruptcy

On December 20, 2005, Calpine and certain of its subsidiaries, including Calpine Fuels, filed for federal bankruptcy protection in the Southern District of New York. The filing raises certain concerns regarding aspects of our relationship with Calpine which we will closely monitor as the Calpine bankruptcy proceeds. Following are our principal areas of concern:

•

The bankruptcy court may challenge the fairness of our acquisition. For a number of reasons, including the process which Calpine followed in allowing market forces to set the purchase price for the acquisition, we believe that it is unlikely that any challenge to the fairness of our acquisition would be successful.

•

The bankruptcy proceeding may prevent, frustrate or delay our ability to receive record legal title to certain properties originally determined to be non-consent properties which we are entitled to obtain under our purchase and sale agreement with Calpine and certain subsidiaries.

•

Additionally, the bankruptcy proceeding may prevent, frustrate or delay our ability to receive corrective documentation from Calpine for certain properties which we bought from Calpine and paid for, where the documentation delivered by Calpine was incomplete, including documentation related to certain ministerial governmental approvals.

•

Calpine may stop purchasing gas from us under our gas purchase contract with Calpine. Since the date of the bankruptcy filing, Calpine has continued buying natural gas from us and paying for it timely. The bankruptcy

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court for Calpine, as debtor-in-possession, has given approval to continue payments to us for our delivery of natural gas under our gas purchase and sale agreement. Under the terms of this contract, we are entitled to sell this gas to third parties at comparable prices and terms if this occurs and expect to be able to minimize our exposure to four days of sales under the contract, or approximately $1.5 million in lost sales at production rates and prices as of March 31, 2006.

•

Calpine may stop providing us certain services, including natural gas marketing services and pipeline services, which Calpine, through separate subsidiaries, currently provides to us. Management does not believe that cessation of these services would have a material impact on our operations.

We have engaged bankruptcy counsel to monitor the Calpine Bankruptcy proceeding and advocate our interests as necessary and have initiated plans to mitigate the operational risks presented by Calpine’s bankruptcy. As of the date of this report, we have not been named as a party to any proceeding or have received any notice to appear with respect to this bankruptcy proceeding.

Transfers Pending at Calpine’s Bankruptcy

At July 7, 2005, we retained approximately $75 million of the purchase price in respect to properties identified as requiring third party consents that were not received before closing. Subsequent analysis determined that a portion of these properties, with an approximate allocation value of $29 million under the purchase and sale agreement with Calpine (“PSA”) did not require consent. For that portion of the properties for which third party consents were in fact required having an approximate value of $39 million under the PSA and those properties that did not require consent, we believe that Calpine was obligated to have transferred to us the record title, free of any mortgages, for all properties for which any required consents were received or were otherwise cured at the close of each month for the first six months after closing by no later than 5 days after the end of each month of cure.

The approximate allocated value under the PSA for the portion of these properties subject to a preferential right is $7.1 million. We will retain $7.4 million for the properties subject to this preferential right, which total amount includes approximately $0.3 million for a property which was transferred to us but will be transferred to the appropriate third party under an exercised preferential purchase right.

We believe all conditions for our receipt of record title, free of any mortgages for all of these properties (excluding that portion of these properties subject to this preferential right) were satisfied on or before December 15, 2005. We believe we are the equitable owner of all of these properties (excluding that portion of these properties subject to this preferential right) and that these properties are not part of Calpine’s bankruptcy estate. Upon our receipt from Calpine of record title, free of any mortgages, we are prepared to pay Calpine approximately $68 million, subject to appropriate adjustment for the associated net revenues for the cured non-consent properties through December 15, 2005. Rosetta’s statement of operations for the three months ended March 31, 2006 does not include any net revenues or production from these properties.

If Calpine does not provide us with record title, free of any mortgages for all of these properties (excluding that portion of these properties subject to this preferential right), we will have a total of approximately $68 million available to us for general corporate purposes, including for the purpose of acquiring additional properties. We will also have approximately $7.4 million for that portion of these properties subject to a preferential right, available to us for general corporate purposes, including for the purpose of acquiring additional properties.

In addition, as to certain of the properties we purchased from Calpine and paid Calpine for on July 7, 2005, we will seek additional documentation from Calpine to eliminate any issue as to the clarity of our ownership. The specific nature of our request will depend on the particular facts and circumstances surrounding each property involved. Certain of these properties are subject to ministerial governmental action approving us as qualified assignee and operator, even though in most cases Calpine specifically conveyed the property to us free and clear of mortgages and liens previously recorded by Calpine’s creditors. As to certain other properties, the documentation delivered by Calpine at closing was incomplete. We remain hopeful that we will be able to work cooperatively with Calpine to secure these ministerial governmental approvals and to accomplish the curative corrections for all of these properties. In addition, as to all these properties, Calpine contractually agreed to provide us with such further assurances as we may reasonably request. Nevertheless, as a result of the recency of Calpine’s bankruptcy filing, it remains uncertain as to how, when and if Calpine will respond cooperatively. If Calpine does not fulfill its contractual obligations and does not complete the documentation necessary to resolve these conveyancing issues, we will pursue all available remedies, including but not limited to a declaratory judgment to enforce our rights and actions to quiet title. After pursuing these matters, if we experience a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to us, an outcome our management considers to be remote, then we could experience losses which could have a material adverse effect on our assets, financial condition, statement of operations and cash flows.

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Critical Accounting Policies and Estimates

In our annual report on Form 10-K for the year ended December 31, 2005, we identified our most critical accounting policies upon which our financial condition depends as those relating to oil and natural gas reserves, full cost method of accounting, derivative transactions and hedging activities, asset retirement obligations, income taxes and stock-based compensation.

Effective January 1, 2006, we adopted the accounting policies described in SFAS No. 123 (revised 2004) “Share-Based Payments” (“SFAS-123R”). This statement applies to all awards granted, modified, repurchased or cancelled after January 1, 2006 and to the unvested portion of all awards granted prior to that date. The Company adopted this statement using the modified version of the prospective application (modified prospective application). Under this method, no prior year amounts have been restated. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by the Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees”.

With the adoption of SFAS-123R, one of the differences in our method of accounting is that unvested stock options are now expensed as a component of stock-based compensation recorded in General and Administrative Costs in the Consolidated Statement of Operations. This expense is based on the fair value of the award at the original grant date and is recognized over the remaining vesting period. Prior to the adoption of SFAS-123R, this amount was included as a pro forma disclosure in the Notes to the Consolidated Financial Statements. Compensation expense for the three month period ended March 31, 2006 was $1.8 million.

In addition, the application of the forfeiture rate in calculating the fair value has changed with the adoption of SFAS-123R. We are now required to estimate forfeitures on all equity-based compensation and adjust period expenses instead of recording the actual forfeitures as they occur. Furthermore, we are required to immediately expense certain awards to retirement eligible employees depending on the structure of each individual plan. The retirement eligibility provision only applies to new grants that were awarded after January 1, 2006.

Results of Operations

In July 2005, we acquired the domestic oil and natural gas business of Calpine Corporation and affiliates. Due to the acquisition, the results of operations for the three months ended March 31, 2006 and 2005 are presented as successor and predecessor, successor comprising the three months ended March 31, 2006 and predecessor comprising the three months ended March 31, 2005. These two periods have not been compared because differences in accounting principles, primarily the full cost method of accounting for oil and natural gas properties adopted by us and the successful efforts method of accounting for oil and natural gas properties followed by Calpine. In addition, Calpine adopted on January 1, 2003, SFAS No. 123, “Accounting for Stock-Based Compensation” to measure the cost of employee services received in exchange for an award of equity instruments, whereas we adopted the intrinsic value method of accounting for stock options and stock awards effective July 1, 2005, and as required, have adopted the guidance for stock based compensation under SFAS 123(R) effective January 1, 2006. We believe comparative results of operations for the two periods would be misleading and, therefore, have chosen to present the periods separately.

Successor

Revenues. Our revenues are derived from the sale of our oil and gas production, which includes the effects qualifying hedge contracts. Total revenue of $64.5 million for the three months ended March 31, 2006 consists primarily of natural gas sales comprising 87.9% of total revenue on total volumes of 7.7 Bcfe. Natural gas sales revenue was $56.7 million, including the effects of hedging, based on total gas production volumes of 6.9 Bcf. The average natural gas prices were $8.22 per Mcf for the three month period ended March 31, 2006. The effect of hedging on natural gas sales revenue was an increase of $1.6 million for an increase in total price from $7.99 to $8.22 per Mcf.

Oil revenue was $7.8 million based on production volumes of 127.2 Mbbls. Production volumes were 75.4 Mbbls for the Gulf of Mexico, 20.6 Mbbls for other onshore and 14.2 Mbbls for Lobo, resulting in approximately 87% of the total production. The offshore production volumes are higher than expected due to minimal downtime on most of the offshore wells in High Island and East Cameron. The average oil price was $61.39 per Bbl.

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Production


	Three Months Ended March 31, 2006
	(In thousands, expect per unit amounts)
Oil and natural gas sales	$	64,544

Production:
Gas (Bcf)		6.9
Oil (Mbbl)		127.2
Total Equivalents (Bcfe)		7.7

$ per unit:
Avg. Gas Price per Mcf	$	8.22
Avg. Gas Price per Mcf excluding Hedging		7.99
Avg. Oil Price per Bbl		61.39
Avg. Revenue per Mcfe		8.38

Operating Expenses


	Three Months Ended March 31, 2006
	(In thousands, expect per unit amounts)
Lease operating expense	$	9,558
Depreciation, depletion and amortization		24,067
Treating and transportation		895
Marketing fees		624
Production taxes		1,697
General and administrative costs		9,251

$ per unit:
Avg. lease operating expense per Mcfe	$	1.24
Avg. DD&A (excluding ceiling test write-downs) per Mcfe		3.13
Avg. transportation & marketing per Mcfe		0.20
Avg. production tax expense per Mcfe		0.22
Avg. G&A per Mcfe		1.20

Our operating expenses for the first three months of 2006 are primarily related to the following items:

Lease Operating Expense. Lease operating expense of $9.6 million related directly to oil and natural gas volumes which totaled 7.7 Bcfe for the three months ended March 31, 2006 or costs of $1.24 per Mcfe. In addition, lease operating costs were effected by the number of wells that came on-line in South Texas. The costs included work over cost, ad valorem taxes, insurance, well servicing and equipment rentals.

Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization expense was $24.1 million for the three month period ended March 31, 2006 under the full cost method of accounting for oil and natural gas properties. The depletion rate was $3.06 per Mcfe in the first quarter of 2006. There was no ceiling test write-downs for the three months ended March 31, 2006.

General and Administrative Costs. General and administrative costs of $9.3 million is net of capitalization of general and administrative costs of $0.8 million as a component of our oil and natural gas properties under the full cost method of accounting for oil and natural gas properties. General and administrative costs include salary and employee benefits as well as legal, consulting, and auditing fees associated with becoming a stand alone public entity. In addition, stock compensation expense of $1.8 million for the three months ending March 31, 2006 is included in general and administrative costs.

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Total Other (income) expense. Other (income) expense is composed of interest expense of $4.1 million associated with the note payable and interest income of $1.1 million due to the interest earned on overnight cash investments.

Provision for Income Taxes. The effective tax rate for the three months ended March 31, 2006 was 38.3%. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state taxes, tax credits and other permanent differences.

Predecessor

Revenues. Total Revenues of $50.5 million for the three months ended March 31, 2005 consists primarily of natural gas sales comprising 92.0 % of total revenue on total volumes of 8.0 Bcfe. Natural gas sales revenue was $46.5 million based on total gas production volumes of 7.5 Bcf. Production volumes were lower than expected due to capital expenditure constraints resulting in reduced drilling activity. There were no effects of hedging on the revenue or production amounts as no derivative instruments existed during the three month period ended March 31, 2005.

Oil sales revenue was $4.0 million with oil production of 82.6 Mbbl. The average oil price was $48.40 per Bbl and oil production was also lower than expected due to the decline of three offshore wells in E. Cameron, S. Pelto and High Island Fields.

Production


	Three Months Ended March 31, 2005
	(In thousands, expect per unit amounts)
Oil and natural gas sales	$	50,555

Production:
Gas (Bcf)		7.5
Oil (MBbl)		82.6
Total Equivalents per (Bcfe)		8.0

$ per unit:
Avg. Gas Price per Mcf	$	6.20
Avg. Oil Price per Bbl		48.40
Avg. revenue per Mcfe		6.32

Operating Expenses


	Three Months Ended March 31, 2005
	(In thousands, expect per unit amounts)
Lease operating expense	$	7,537
Depreciation, depletion and amortization		15,124
Exploration expense		1,429
Dry hole costs		76
Treating and transportation		968
Affiliated marketing fees		439
Production taxes		1,188
General and administrative costs		3,345

$ per unit:
Avg. lease operating expense per Mcfe	$	0.94
Avg. DD&A (excluding impairments) per Mcfe		1.89
Avg. transportation & marketing per Mcfe		0.18
Avg. production tax expense per Mcfe		0.15
Avg. G&A per Mcfe		0.42

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The operating expenses for the three month period ended March 31, 2005 are primarily related to the following items:

•

Lease Operating Expense. Lease operating expense of $7.5 million related directly to oil and natural gas volumes which totaled 8.0 Bcfe for the three months ended March 31, 2005 or costs of $0.94 per Mcfe. The costs included work over cost, ad valorem taxes, insurance, well servicing and equipment rentals.

•

Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization expense was $15.1 million for the three month period ended March 31, 2005 under the successful efforts method of accounting for oil and natural gas properties. The depletion rate was $2.70 per Mcfe in the first quarter of 2005.

•

Exploration expense. Exploration expense was $1.4 million for the three months ended March 31, 2005 under the successful efforts method of accounting for oil and natural gas properties. The exploration expense was comprised of geological and geophysical salaries and expenses.

•

Production Taxes. Production taxes are primarily based on wellhead values of production and vary across the different regions. For the first quarter of 2005, there was increased drilling activity in the Impac field in South Texas which resulted in higher accrued severance taxes. Production taxes as a percentage of natural gas and oil sales were approximately 2.3%.

•

General and Administrative Costs. General and Administrative costs of $3.3 million is net of capitalization of general and administrative costs of $1.2 million as a component of the oil and natural gas properties. General and administrative costs are comprised of items as salaries and employee benefits, legal fees, and contract fees.

Other (income) expense. Other (income) expense is composed of interest expense of $3.6 million related to intercompany debt with Calpine Corporation.

Provision for Income Taxes. The effective tax rate for the three months ended March 31, 2006 was 37.9%. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state taxes, tax credits and other permanent differences.

Liquidity and Capital Resources

Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We will actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production thereby mitigating our exposure to price declines, but will also limit our earnings potential in periods of rising natural gas prices. This derivative transaction activity will allow us the flexibility to continue to execute our capital plan if prices decline during the period our derivative transactions are in place. In addition, the majority of our capital expenditures will be discretionary and could be curtailed if our cash flows declined from expected levels. In connection with entering into our credit facilities in July 2005, we entered into a series of natural gas fixed-price swaps for a significant portion of our expected production through 2009. Consistent with our hedge policy, in December 2005, we entered into two costless collar transactions, which are intended to establish a floor price and ceiling price for approximately 10,000 MMBtu per day which represents approximately 10% of our 2006 natural gas production based on a third party reserve report at December 31, 2005. Additionally, we may enter into other agreements including fixed-price, forward price, physical purchase and sales contracts, futures, financial swaps, option contracts and put options.

Senior Secured Revolving Line of Credit. BNP Paribas, in July 2005 provided us with a senior secured revolving line of credit concurrent with the acquisition in the amount of up to $400 million. This revolving line of credit was syndicated to a group of lenders on September 27, 2005. Availability under the revolver is restricted to the borrowing base, which initially was $275 million and was reset to $325 million, upon amendment, as a result of the hedges put in place in July 2005 and the favorable effects of the exercise of the over-allotment option we granted in our private equity offering in July, 2005 through which we received $70 million of funds (net of transaction fees). In July 2005, we repaid $60 million of the $225 million in original borrowings on the Revolver. The borrowing base is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements. Amounts outstanding under the revolver bear interest, as amended, at specified margins over the London Interbank Offered Rate (LIBOR) of 1.25% to 2.00%. Such margins will fluctuate based on the utilization of the facility. Borrowings under the Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the PV-10 reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock of domestic subsidiaries, and a lien on cash securing the Calpine gas purchase and sale contracts. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of

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each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At March 31, 2006, our current ratio was 4.8 to 1.0 and our leverage ratio was 1.5 to 1.0 . In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at March 31, 2006. All amounts drawn under the revolver are due and payable on July 7, 2009. Availability under the revolving line of credit was $159 million at March 31, 2006.

Second Lien Term Loan. BNP Paribas, in July 2005, also provided us with a second lien term loan concurrent with the acquisition, in the amount of $100 million. On September 27, 2005, we repaid $25 million of borrowings on the Term Loan, reducing the balance to $75 million and syndicated loan to a group of lenders including BNP Paribas. Borrowings under the term loan initially bore interest at LIBOR plus 5.00%. As a result of the hedges put in place in July 2005 and the favorable effects of our private equity placement, as described above, the interest rate for the second lien term loan has been reduced to LIBOR plus 4.00%. The loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at March 31, 2006. The revised principal balance is due and payable on July 7, 2010.

Cash Flows


	Successor Consolidated			Predecessor Combined
	Three Months Ended March 31, 2006			Three Months Ended March 31, 2005
	Three Months Ended March 31, 2006			Three Months Ended March 31, 2005
	(In thousands)
Cash flows provided by operating activities	$	41,015		$	40,883
Cash flows used in investing activities		(36,189	)		(17,232	)
Cash flows used in financing activities		(799	)		(23,136	)

Net increase in cash and cash equivalents	$	4,027		$	515

Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation expense and administrative expenses.

Net cash provided from operations for the three months ended March 31, 2006 was $41.0 million generated from total production of 7.7 Bcfe with revenue of $64.5 million and net income of $15.4 million before taxes. Natural gas prices averaged $8.22 per Mcf, including the effects of hedging, and oil averaged $61.39 per Bbl during the quarter.

Net cash provided from operating activities for the three months ended March 31, 2005 was $40.9 million generated from total production of 8.0 Bcfe with revenue of $50.5 million and net income of $17.2 million before taxes. During the three months ended March 31, 2005, there was a price increase of 14% from $5.58 per Mcfe to $6.36 per Mcfe.

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

Cash used in investing activities for the three months ended March 31, 2006 was $36.2 million primarily relating to the purchases of property and equipment with additional capital expenditures accrued for at quarter end.

Cash used in investing activities for the three months ended March 31, 2005 was $17.2 million. The majority of the cash used in investing activities relates to the purchases of property, plant, and equipment associated with the increased drilling activity in South Texas.

Financing Activities. Net cash used in financing activities for the three months ended March 31, 2006 was $0.8 million primarily related to the purchases of treasury stock of $1.2 million offset by the equity transaction fees and proceeds from issuances of common stock.

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Net cash used in financing activities for the three months ended March 31, 2005 was comprised of repayments of notes to affiliates totaling $23.1 million.

Capital Expenditures

Our capital expenditures for the three-month period ended March 31, 2006 were $ 38.6 million. These capital expenditures were primarily associated with increased drilling activity in California and the Texas State Waters. We currently expect to expend approximately $199 million for capital expenditures during 2006. We believe we have adequate expected cash flows from operations and available borrowings under our revolving credit facility to cover our budgeted capital expenditures.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Rosetta is currently exposed to market risk primarily related to adverse changes in oil and natural gas prices and interest rates. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosure About Market Risks” in our annual report filed on Form 10-K for the year ended December 31, 2005. There have been no significant changes in our market risk from what was disclosed in the Form 10-K for the year ended December 31, 2005.

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 Securities Exchange Act of 1934, as amended (“Exchange Act”), as of March 31, 2006. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance that the information required to be disclosed in our Exchange Act filings is (1) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission’s rules and forms, and (2) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2006, our disclosure controls and procedures were not effective, at the reasonable assurance level, due to the identification of the material weaknesses in internal control over financial reporting described below. Notwithstanding the material weaknesses described below, we believe our unaudited consolidated financial statements included in this Quarterly filing on Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles as applicable to interim reporting.

In preparing our Exchange Act filings, including this Quarterly filing on Form 10-Q, we implemented processes and procedures to provide reasonable assurance that the identified material weaknesses in our internal control over financial reporting were mitigated with respect to the information that we are required to disclose. As a result, we believe, and our Chief Executive Officer and Chief Financial Officer have certified to their knowledge, that this Quarterly filing on Form 10-Q does not contain any untrue statements of material fact or omit to state any material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered in this report.

Material Weaknesses in Internal Control Over Financial Reporting

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. We have identified various deficiencies in internal control over financial reporting. We believe that many of these are attributable to our transition from a subsidiary of a much larger company to a standalone entity. In connection with the preparation of our unaudited consolidated financial statements and our assessment of the effectiveness of our disclosure controls and procedures as of March 31, 2006 to be included in this Quarterly Report on Form 10-Q to be filed under the Exchange Act, we determined that the following specific control deficiencies, which represent material weaknesses in our internal control over financial reporting as of March 31, 2006:

a) We did not have a sufficient complement of permanent personnel to have an appropriate accounting and financial reporting organizational structure to support the activities of the Company. Specifically, we did not have permanent personnel with an appropriate level of accounting knowledge, experience and training in the selection, application and implementation of generally accepted accounting principles and financial reporting commensurate with our financial reporting requirements.

b) We did not have effective controls as it relates to the identification and documentation of accounting policies, including selection and application of generally accepted accounting principles used for accounting for select transactions and other activities. This deficiency resulted in a reduced ability to ensure the timely and accurate recording of certain transactions and activities primarily relating to accounting for derivatives and debt modifications. As a result, we did not have sufficient procedures to ensure significant underlying select transactions were appropriately and timely accounted for in the general ledger.

In addition these material weaknesses could result in a misstatement of substantially all accounts and disclosures which would result in a material misstatement of annual or interim financial statements that would not be prevented or detected. Accordingly, management has concluded that these control deficiencies constitute material weaknesses. These material weaknesses also existed at December 31, 2005.

Remediation Activities

As discussed above, management has identified certain material weaknesses that exist in our internal control over financial reporting and management is taking steps to strengthen our internal control over financial reporting. During the first quarter of 2006, we hired additional accounting personnel and began improving our documentation of our accounting policies and procedures. Specifically, during the first quarter of 2006 we have taken the following remedial actions:

We have hired a certified public accountant with specific expertise in accounting software systems to evaluate and implement further enhancements to our software and related procedures to improve our accounting controls;

We have replaced our manager of fixed assets and accounts payable with a more highly credentialed person having a masters degree in business administration who is also a certified public accountant;

We have hired a person to fill the position of manager of internal audit to review and audit our internal control environment and make recommendations for improvement; and

We have authorized and filled the additional position of manager of financial reporting who will begin employment in the second quarter of 2006.

While we have taken certain actions to address the material weaknesses identified, additional measures will be necessary and these measures, along with other measures we expect to take to improve our internal control over financial reporting, may not be sufficient to address the material weaknesses identified to provide reasonable assurance that our internal control over financial reporting is effective. In addition, we may in the future identify additional material weaknesses in our internal control over financial reporting.

Beginning with the year ending December 31, 2007, pursuant to Section 404 of the Sarbanes-Oxley Act, we will be required to deliver a report that assesses the effectiveness of our internal control over financial reporting, and our auditors will be required to audit and report on our assessment of and the effectiveness of our internal control over financial reporting. We have a substantial effort ahead of us to complete the documentation and testing of our internal control over financial reporting and remediate any additional material weaknesses identified during that activity. Accordingly, we may not be able to complete the required management assessment by our reporting deadline. An inability to complete this assessment would result in receiving something other than an unqualified report from our auditors with respect to our assessment of our internal control over financial reporting. In addition, if material weaknesses are not remediated, we would not be able to conclude that our internal control over financial reporting was effective, which would result in the inability of our external auditors to deliver an unqualified report on the effectiveness of our internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

We and our subsidiaries may become party to legal proceedings that arise from time to time in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the financial statements.

We carry insurance with coverage and coverage limits consistent with our assessment of risks in our business and of an acceptable level of financial exposure. Although there can be no assurance that such insurance will be sufficient to mitigate all damages, claims or contingencies, we believe that our insurance provides reasonable coverage for known asserted or unasserted claims. In the event we sustain a loss from a claim and the insurance carrier disputed coverage or coverage limits, we may record a charge in a different period than the recovery, if any, from the insurance carrier.

Item 1A. Risk Factors

There have been no material changes in our risk factors from those disclosed in Item 1A of our annual report on Form 10-K for the year ended December 31, 2005.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers


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 yet Be Purchased Under the Plans or Programs
January 1—January 31	—		—	—	—
February 1—February 28	—		—	—	—
March 1—March 31	66,831	$	18.64	—	—

(1)

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

Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

Rosetta reported on Form 8-K during the quarter covered by this report all information required to be reported on such form.

Item 6. Exhibits


31.1		Certification of Periodic Financial Reports by B.A. Berilgen in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

32		Certification of Periodic Financial Reports by B.A. Berilgen and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350

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SIGNATURE

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.

May 15 , 2006		/s/ Michael J. Rosinski
Date		Michael J. Rosinski,
		Executive Vice President and Chief Financial Officer
		(Duly Authorized and Principal Financial Officer)

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ROSSETA RESOURCES INC.

INDEX OF EXHIBITS


31.1		Certification of Periodic Financial Reports by B.A. Berilgen in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002

32		Certification of Periodic Financial Reports by B.A. Berilgen and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350

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