Edgar Filing: Rosetta Resources Inc.

form10-q.htm

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 31,2007

¨	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 4, 2007 was 50,771,054.

Table of Contents

Part I –	Financial Information	3
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	20
	Item 4. Controls and Procedures	20
Part II –	Other Information	21
	Item 1. Legal Proceedings	21
	Item 1A. Risk Factors	23
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	23
	Item 3. Defaults Upon Senior Securities	23
	Item 4. Submission of Matters to a Vote of Security Holders	23
	Item 5. Other Information	23
	Item 6. Exhibits	24
Signatures		25
Exhibit Index		26
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 share amounts)

	March 31, 2007			December 31, 2006
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	50,907		$	62,780
Accounts receivable		36,774			36,408
Derivative instruments		122			20,538
Deferred income taxes		3,628			-
Prepaid expenses		19,298			8,761
Other current assets		3,444			2,965
Total current assets		114,173			131,452
Oil and natural gas properties, full cost method, of which $44.1 million at March 31, 2007 and $37.8 million at December 31, 2006 were excluded from amortization		1,290,739			1,223,337
Other fixed assets		4,888			4,562
		1,295,627			1,227,899
Accumulated depreciation, depletion, and amortization		(175,533	)		(145,289	)
Total property and equipment, net		1,120,094			1,082,610
Deferred loan fees		3,080			3,375
Other assets		1,105			1,968
Total other assets		4,185			5,343
Total assets	$	1,238,452		$	1,219,405

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	25,687		$	23,040
Accrued liabilities		49,392			43,099
Royalties payable		10,811			9,010
Derivative instruments		9,622			-
Prepayment on gas sales		18,590			17,868
Deferred income taxes		46			7,743
Total current liabilities		114,148			100,760
Long-term liabilities:
Derivative instruments		17,753			11,014
Long-term debt		240,000			240,000
Asset retirement obligation		11,262			10,253
Deferred income taxes		40,895			35,089
Total liabilities		424,058			397,116
Commitments and contingencies (Note 8)
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 50,427,523 shares and 50,405,794 shares at March 31, 2007 and December 31, 2006, respectively		50			50
Additional paid-in capital		756,809			755,343
Treasury stock, at cost; 88,887 and 85,788 shares at March 31, 2007 and December 31, 2006, respectively		(1,620	)		(1,562	)
Accumulated other comprehensive (loss) income		(16,979	)		6,315
Retained earnings		76,134			62,143
Total stockholders' equity		814,394			822,289
Total liabilities and stockholders' equity	$	1,238,452		$	1,219,405

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

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Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended March 31,
	2007			2006
Revenues:
Natural gas sales	$	69,161		$	56,735
Oil sales		6,635			7,809
Total revenues		75,796			64,544
Operating Costs and Expenses:
Lease operating expense		8,796			9,558
Depreciation, depletion, and amortization		30,551			24,067
Treating and transportation		763			895
Marketing fees		663			624
Production taxes		985			1,697
General and administrative costs		8,069			9,251
Total operating costs and expenses		49,827			46,092
Operating income		25,969			18,452

Other (income) expense
Interest expense, net of interest capitalized		4,370			4,132
Interest income		(972	)		(1,137	)
Other (income) expense, net		-			25
Total other expense		3,398			3,020

Income before provision for income taxes		22,571			15,432
Provision for income taxes		8,580			5,906
Net income	$	13,991		$	9,526

Earnings per share:
Basic	$	0.28		$	0.19
Diluted	$	0.28		$	0.19

Weighted average shares outstanding:
Basic		50,325			50,121
Diluted		50,483			50,355

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

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Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2007			2006
Cash flows from operating activities
Net income	$	13,991		$	9,526
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		30,551			24,067
Deferred income taxes		8,580			5,906
Amortization of deferred loan fees recorded as interest expense		295			295
Income from unconsolidated investments		(47	)		25
Stock compensation expense		1,352			1,835
Change in operating assets and liabilities:
Accounts receivable		(366	)		8,212
Income taxes receivable		-			6,000
Other assets		(10,720	)		(4,160	)
Accounts payable		2,647			(1,753	)
Accrued liabilities		(2,285	)		(2,857	)
Royalties payable		2,523			(6,081	)
Net cash provided by operating activities		46,521			41,015
Cash flows from investing activities
Purchases of property and equipment		(58,452	)		(36,325	)
Deposits		-			25
Other		3			111
Net cash used in investing activities		(58,449	)		(36,189	)
Cash flows from financing activities
Equity offering transaction fees		-			267
Proceeds from issuances of common stock		114			192
Purchases of treasury stock		(59	)		(1,246	)
Other		-			(12	)
Net cash provided by (used in) financing activities		55			(799	)

Net (decrease) increase in cash		(11,873	)		4,027
Cash and cash equivalents, beginning of period		62,780			99,724
Cash and cash equivalents, end of period	$	50,907		$	103,751

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	4,397		$	2,249

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

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Rosetta Resources Inc.

Notes to Consolidated Financial Statements (unaudited)

(1)

Organization and Operations of the Company

Nature of Operations. Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) was formed in June 2005 to acquire Calpine Natural Gas L.P., the domestic oil and natural gas business formerly owned by Calpine Corporation and affiliates (“Calpine”). The Company acquired Calpine Natural Gas L.P. in July 2005 (hereinafter, the “Acquisition”) and together with all subsequently acquired oil and natural gas properties is engaged in oil and natural gas exploration, development, production and acquisition activities in the United States. The Company’s main operations are concentrated in the Sacramento Basin of California, the Lobo and Perdido Trends in South Texas, the State Waters of Texas, 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 the Company’s audited Consolidated/Combined Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

Certain reclassifications of prior year balances have been made to conform such amounts to corresponding 2007 classifications. These reclassifications have no impact on net income.

(2)

Summary of Significant Accounting Policies

The Company has provided discussion of significant accounting policies, estimates and judgments in its Annual Report on Form 10-K for the year ended December 31, 2006.

Principles of Consolidation and Basis of Presentation. The accompanying consolidated financial statements as of March 31, 2007 and December 31, 2006 and for the three months ended March 31, 2007 and 2006 contain the accounts of Rosetta Resources Inc. and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.

Recent Accounting Developments

The Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option For Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (“SFAS” No. 159), which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. The Company has not yet evaluated the potential impact of this standard.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157,“Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Company is still assessing the impact of this standard but does not expect the adoption of this standard to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company did not have any unrecognized tax benefits and there was no effect on the Company's consolidated financial condition, results of operations or cash flows as a result of implementing FIN 48. For additional information see Note 7 to the Consolidated Financial Statements.

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(3)

Property, Plant and Equipment

The Company’s total property, plant and equipment consist of the following:

	March 31, 2007			December 31, 2006
	(In thousands)
Proved properties	$	1,237,939		$	1,170,223
Unproved properties		31,517			35,178
Gas gathering systems and compressor stations		21,283			17,936
Other		4,888			4,562
Total		1,295,627			1,227,899
Less: Accumulated depreciation, depletion, and amortization		(175,533	)		(145,289	)
	$	1,120,094		$	1,082,610

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.3 million and $0.8 million of internal costs for the three months ended March 31, 2007 and 2006, respectively.

Included in the Company’s oil and natural gas properties are asset retirement obligations of $14.5 million and $9.6 million as of March 31, 2007 and December 31, 2006, respectively.

Oil and natural gas properties include costs of $44.1 million and $37.8 million at March 31, 2007 and December 31, 2006, respectively, which were excluded from capitalized costs being amortized. These amounts primarily represent unproved properties and unevaluated exploration projects in which the Company owns a direct interest. The increase in costs excluded during 2007 is primarily related to the increase in exploration activities in Offshore and Texas State Waters.

The Company’s ceiling test computation was calculated using hedge adjusted market prices at March 31, 2007 which were based on a Henry Hub price of $7.34 per MMBtu and a West Texas Intermediate oil price of $66.20 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2007 increased the calculated ceiling value by approximately $15 million (net of tax). There was no writedown recorded at March 31, 2007. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a writedown could occur.

In April 2007, the Company acquired properties located in the Sacramento Basin from Output Exploration, LLC and OPEX Energy, LLC at a total purchase price of $40 million, subject to final adjustments.

(4)

Commodity Hedging Contracts and Other Derivatives

In the first quarter of 2007, the Company entered into additional 6,000 MMBtu per day financial fixed price swaps with an average price of $8.11 per MMBtu covering a portion of the Company’s 2007 production. The following financial fixed price swaps were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations at March 31, 2007:

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 (In thousands)
2007	Swap	Cash flow		55,327		15,215,000		$7.80		45%		(2,245	)
2008	Swap	Cash flow		49,909		18,266,616		$7.62		44%		(15,007	)
2009	Swap	Cash flow		26,141		9,541,465		$6.99		26%		(10,233	)
						43,023,081					$	(27,485	)

(1) Estimated based on net gas reserves presented in the December 31, 2006 Netherland, Sewell, & Associates, Inc. reserve report.

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The following costless collar transactions were outstanding with associated notional volumes and contracted ceiling and floor prices that represent hedge prices at various market locations at March 31, 2007:

Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor Price MMBtu		Average Ceiling Price MMBtu		Total of Proved Natural Gas Production Hedged (1)		Fair Market Value Gain (In thousands)

2007	Costless Collar	Cash flow		10,000		2,750,000	$	7.19	$	10.03		8%	$	232
						2,750,000							$	232

(1) Estimated based on net gas reserves presented in the December 31, 2006 Netherland, Sewell, & Associates, Inc. reserve report.

The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities. This eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations. As of March 31, 2007, the Company made no deposits for collateral.

The following table sets forth the results of third party hedge transactions for the respective period for the Consolidated Statement of Operations:

	Three Months Ended March 31,
Natural Gas	2007		2006
Quantity settled (MMBtu)		5,499,500		4,950,000
Increase in natural gas sales revenue (In thousands)	$	5,044	$	1,563

The Company expects to reclassify losses of $5.9 million based on market pricing as of March 31, 2007 to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.

At March 31, 2007, the Company had derivative assets of $0.1 million on the Consolidated Balance Sheet. The Company also had derivative liabilities of $27.4 million of which $17.8 million is included in long-term liabilities on the Consolidated Balance Sheet at March 31, 2007. The derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of March 31, 2007. Hedging activities related to cash settlements on commodities increased revenues by $5.0 million and $1.6 million for the three months ended March 31, 2007 and 2006.

Gains and losses related to ineffectiveness and derivative instruments not designated as hedging instruments are included in other income (expense) and were immaterial for the three months ended March 31, 2007 and 2006.

In April 2007, the Company entered into two additional financial fixed price swaps with prices ranging from $7.25 per MMBtu to $8.63 per MMBtu for a total of 5,000 MMBtu per day covering a portion of the Company’s 2008 production.

(5)

Asset Retirement Obligation

Activity related to the Company’s asset retirement obligation (“ARO”) is as follows:

	Three Months Ended March 31, 2007
	(In thousands)
ARO as of January 1, 2007	$	10,689
Revision of previous estimates		4,697
Liabilities incurred during period		187
Accretion expense		289
ARO as of March 31, 2007	$	15,862

Of the total ARO, approximately $4.6 million is classified as a current liability at March 31, 2007.

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(6)

Long-Term Debt

The Company’s credit facilities consist of a four-year senior secured revolving line of credit (“Revolver”) of up to $400.0 million with a borrowing base of $325.0 million and a five-year $75.0 million second lien term loan.

On March 31, 2007, the Company had outstanding borrowings and letters of credit of $240.0 million and $1.0 million, respectively. Net borrowing availability was $159.0 million at March 31, 2007. The Company was in compliance with all covenants at March 31, 2007.

In May 2007, the borrowing base of the Revolver was adjusted to $350.0 million. All amounts drawn under the Revolver are due and payable on July 7, 2009. The principal balance associated with the second lien term loan is due and payable on July 7, 2010.

(7)

Income Tax

The Company did not have any unrecognized tax benefits and there was no effect on the Company’s consolidated financial condition, results of operations or cash flows as a result of implementing FIN 48. The amount of unrecognized tax benefits did not materially change as of March 31, 2007.

The Company files a federal income tax return in the United States Federal jurisdiction and various filings in several state and local jurisdictions. The Company began operations in 2005, and therefore is not subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2005.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statement of Operations. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter.

The Company’s effective tax rate differs from the federal statutory rate primarily due to state taxes, tax credits and other permanent differences. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2008.

(8)

Commitment and Contingencies

The Company is party to various oil and natural gas litigation matters arising out of the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Management does not believe any such matters will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Calpine Bankruptcy

Calpine Corporation and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (the “Bankruptcy Court”) on December 20, 2005. Calpine Energy Services, L.P., which filed for bankruptcy, has continued to make the required deposits into the Company’s margin account and to timely pay for natural gas production it purchases from the Company’s subsidiaries under various natural gas supply agreements. Additionally, Calpine Producer Services, L.P., which filed for bankruptcy, is under contract through June 30, 2007 with the Company and is generally performing its obligations under the Marketing and Services Agreement.

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 and interrelated agreements concurrently executed therewith, dated July 7, 2005, by and among Calpine, the Company, and various other signatories thereto (collectively, the “Purchase Agreement”), including unasserted claims and assessments with respect to (i) the still pending 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 Purchase Agreement; and (iii) the ultimate disposition of the remaining Non-Consent Properties (and related royalty revenues). Calpine has specific obligations to the Company under the Purchase Agreement relating to these matters, and also has “further assurances” duties to the Company under the Purchase Agreement.

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In addition, as to certain of the other oil and natural gas properties the Company purchased from Calpine in the Acquisition and for which payment was made on July 7, 2005, the Company will seek additional documentation from Calpine to eliminate any open issues in the Company’s title or resolve any issues as to the clarity of the Company’s ownership. Requests for additional documentation are customary in connection with transactions similar to the Acquisition. In the Acquisition, certain of these properties require ministerial governmental action approving the Company as qualified assignee and operator, which is typically required even though in most cases Calpine has already conveyed the properties to the Company free and clear of mortgages and liens by Calpine’s creditors. As to certain other properties, the documentation delivered by Calpine at closing under the Purchase Agreement was incomplete. The Company remains hopeful that Calpine will work cooperatively with the Company to secure these ministerial governmental approvals and to accomplish the curative corrections for all of these properties. In addition, as to all properties acquired by the Company in the Acquisition, Calpine contractually agreed to provide the Company with such further assurances as the Company may reasonably request. Nevertheless, as a result of Calpine’s bankruptcy filing, it remains uncertain as to whether Calpine will respond cooperatively. If Calpine does not fulfill its contractual obligations and does not complete the documentation necessary to resolve these issues, the Company will pursue all available remedies, including but not limited to a declaratory judgment to enforce the Company’s rights and actions to quiet title. After pursuing these matters, if the Company experiences a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to the Company, an outcome the Company’s management considers to be remote, then the Company could experience losses which could have a material adverse effect on the Company’s consolidated financial condition, statement of operations and cash flows.

On June 29, 2006, Calpine filed a motion in connection with its pending bankruptcy proceeding in the Bankruptcy Court seeking the entry of an order authorizing Calpine to assume certain oil and natural gas leases that Calpine had previously sold or agreed to sell to the Company in the Acquisition, to the extent those leases constitute “unexpired leases of non-residential real property” and were not fully transferred to the Company at the time of Calpine’s filing for bankruptcy. According to this motion, Calpine filed in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a statutory deadline. Calpine’s motion did not request that the Bankruptcy Court determine whether these properties belong to the Company or Calpine, but the Company understands it was meant to allow Calpine to preserve and avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may possess, if any, in these oil and natural gas leases. The Company disputes Calpine’s contention that it may have an interest in any significant portion of these oil and natural gas leases and intends to take the necessary steps to protect all of the Company’s rights and interest in and to the leases. On July 7, 2006, the Company filed an objection in response to Calpine’s motion, wherein the Company asserted that oil and natural gas leases constitute interests in real property that are not subject to “assumption” under the Bankruptcy Code. In the objection, the Company also requested that (a) the Bankruptcy Court eliminate from the order certain Federal offshore leases from the Calpine motion because these properties were fully conveyed to the Company in July 2005, and the Minerals Management Service has subsequently recognized the Company as owner and operator of all but three of these properties, and (b) any order entered by the Bankruptcy Court be without prejudice to, and fully preserve the Company’s rights, claims and legal arguments regarding the characterization and ultimate disposition of the remaining described oil and natural gas properties. In the Company’s objection, the Company also urged the Bankruptcy Court to require the parties to promptly address and resolve any remaining issues under the pre-bankruptcy definitive agreements with Calpine and proposed to the Bankruptcy Court that the parties seek arbitration (or at least mediation) to complete the following:

Calpine’s conveyance of the Non-Consent Properties to the Company;

Calpine’s execution of all documents and performance of all tasks required under “further assurances” provisions of the Purchase Agreement with respect to certain of the oil and natural gas properties for which the Company has already paid Calpine; and

Resolution of the final amounts the Company is to pay Calpine, which the Company has concluded is approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations.

At a hearing held on July 12, 2006, the Bankruptcy took the following steps:

In response to an objection filed by the Department of Justice and asserted by the California State Lands Commission that the Debtors’ Motion to Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not allow adequate time for an appropriate response, Calpine withdrew from the list of Oil and Gas Leases that were the subject of the Motion those leases issued by the United States (and managed by the Minerals Management Service of the United States Department of Interior) (the “MMS Oil and Gas Leases”) and the State of California (and managed by the California State Lands Commission) (the “CSLC Leases”). Calpine and both the Department of Justice and the State of California agreed to an extension of the existing deadline to November 15, 2006 to assume or reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases are leases subject to Section 365. The effect of these actions was to render the objection of the Company inapplicable at that time; and

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The Bankruptcy Court also encouraged Calpine and the Company to arrive at a business solution to all remaining issues including approximately $68 million payable to Calpine for conveyance of the Non-Consent Properties.

On August 1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy asserting claims against a variety of Calpine debtors seeking recovery of $27.9 million in liquidated amounts as well as unliquidated damages in amounts that can not presently be determined. The Company continues to work with Calpine on a cooperative and expedited basis toward resolution of unresolved conveyance of properties and post closing adjustments under the Purchase Agreement.

With respect to the stipulations between Calpine and MMS and Calpine and CSLC extending the deadline to assume or reject the MMS Oil and Gas Leases, these parties have further extended this deadline time by stipulation. The deadline was first extended to January 31, 2007, then was further extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007 with respect to the CSLC Leases, and recently was further extended to September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007 with respect to the CSLC Leases. The Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC Leases which included appropriate language that the Company negotiated with Calpine for protection in this regard.

Recently, Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy Court for the period in which only Calpine, exclusively, may file its plan of reorganization. While there is no assurance that Calpine will file a plan of reorganization by this deadline, or that such a plan will be approved by the creditors and the Bankruptcy Court, the Company remains optimistic that the issues involving conclusion of the remaining conveyances of the Non-Consent Properties and obtaining the further assurances from Calpine under the Purchase Agreement, including perhaps resolution of any and all claims, may occur during 2007.

Calpine recently requested Bankruptcy Court approval of a new credit facility which would require it to grant liens to these new lenders in all of its assets, including any interest it may still hold in any oil and natural gas properties it obligated itself to convey to the Company under the Purchase Agreement. The Bankruptcy Court entered an Order approving Calpine’s ability to obtain this new loan which includes appropriate language that the Company negotiated with Calpine for the Company’s protection in this regard.

Furthermore, there can be no assurance that Calpine, its creditors or other interest holders will not challenge the fairness of the Acquisition. For a number of reasons, including the Company’s understanding of the process that Calpine followed in allowing market forces to set the purchase price for the Acquisition, the Company believes that it is unlikely that any challenges by the Calpine debtors or their creditors to the overall fairness of the Acquisition would be successful. The Company will take all necessary action to ensure the Company’s rights under the Purchase agreement, the MMS Oil and Gas Leases, the CSLC Leases and the Bankruptcy Code are fully protected.

Arbitration between Calpine Corp./RROLP and Pogo Producing Company

On September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course of the sale, Pogo made three title defect claims on properties sold by Calpine (valued at approximately $2.7 million in the aggregate, subject to a $0.5 million deductible assuming no reconveyance) claiming, that certain leases subject to the sale had expired because of lack of production. Calpine had undertaken without success to resolve this matter by obtaining ratifications of a majority of the questionable leases. Calpine filed for bankruptcy protection before Pogo filed arbitration against it. Even though this is a retained liability of Calpine, Calpine declined to accept the Company’s tender of defense and indemnity when Pogo filed for arbitration against the Company. The Company filed a motion to stay this arbitration under the automatic stay provision of the Bankruptcy Code which motion was granted by the Bankruptcy Court on April 24, 2007 for a period of time of the earlier of fifteen months from the date of entry of the stay order or the effective date of a final order confirming Calpine’s plan of reorganization. This is a retained liability by the Company and it is too early for management to determine whether this matter will have any financial impact to the Company.

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 two sites in California and correspondingly, recorded a liability, which at March 31, 2007 and December 31, 2006 was $0.1 million. The Company does not expect that the outcome of environmental matters discussed above will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

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Participation in a Regional Carbon Sequestration Partnership

The Company has made preliminary preparations in connection with its participating in the United States 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 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, 2007 or December 31, 2006 as the study is still in the preliminary stage.

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Comprehensive Income

The Company’s total comprehensive income (loss) is shown below.

	Three Months Ended March 31, 2007						Three Months Ended March 31, 2006
	(In thousands)
Accumulated other comprehensive income (loss) - beginning of period				$	6,315					$	(50,731	)
Net income		13,991						9,526

Change in fair value of derivative hedging instruments		(21,497	)					51,750
Hedge settlements reclassed to income		5,044						(1,563	)
Tax provision related to hedges		(6,841	)					(19,071	)
Total other comprehensive (loss) income		(23,294	)		(23,294	)		31,116			31,116

Comprehensive (loss) income		(9,303	)					40,642
Accumulated other comprehensive loss				$	(16,979	)				$	(19,615	)

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Earnings Per Share

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

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

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	Three Months Ended March 31,
	2007		2006
	(In thousands)
Basic weighted average number of shares outstanding		50,325		50,121
Dilution effect of stock option and awards at the end of the period		158		234
Diluted weighted average number of shares outstanding		50,483		50,355
Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect		435		103

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Geographic Area Information

The Company owns oil and natural gas interests in eight main geographic areas all within the United States or its territorial waters. Geographic revenue and property, plant and equipment information below are based on physical location of the assets at the end of each period.

Oil and Natural Gas Revenue

	Three Months Ended March 31,
	2007 (1)		2006 (1)
	(In thousands)
California	$	27,092	$	20,396
Lobo		24,876		15,408
Perdido		5,768		9,822
State Waters		809		3,148
Other Onshore		4,403		3,860
Gulf of Mexico		5,474		9,526
Rockies		1,526		342
Mid-Continent		804		479
	$	70,752	$	62,981

(1)

Excludes the effects of hedging.

Oil and Natural Gas Properties

	March 31, 2007		December 31, 2006
	(In thousands)
California	$	445,501	$	435,167
Lobo		449,028		426,348
Perdido		59,673		52,702
State Waters		34,453		26,922
Other Onshore		106,222		102,734
Gulf of Mexico		131,251		125,425
Rockies		52,527		44,455
Mid-Continent		12,084		9,584
Other		4,888		4,562
	$	1,295,627	$	1,227,899

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

The forward-looking statements contained in this report are largely based on our expectations for the future, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 as updated by this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances, or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

·	The supply and demand for oil, natural gas, and other products and services;

·	The price of oil, natural gas, and other products and services;

·	Conditions in the energy markets;

·	Changes or advances in technology;

·	Reserve levels;

·	Currency exchange rates and inflation;

·	The availability and cost of relevant raw materials, goods and services;

·	Commodity prices;

·	Future processing volumes and pipeline throughput;

·	Conditions in the securities and/or capital markets;

·	The occurrence of property acquisitions or divestitures;

·	Drilling and exploration risks;

·	The availability and cost of processing and transportation;

·	Developments in oil-producing and natural gas-producing countries;

·	Competition in the oil and natural gas industry;

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

·	Our ability to access the capital markets on favorable terms or at all;

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

·	Present and possible future claims, litigation and enforcement actions;

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

·	Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

·	General economic conditions, either internationally, nationally or in jurisdictions affecting our business;

·	The amount of resources expended in connection with Calpine’s bankruptcy, including costs for lawyers, consultant experts and related expenses, as well as all lost opportunity costs associated with our internal resources dedicated to these matters;

·	Disputes with mineral lease and royalty owners regarding calculation and payment of royalties;

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

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

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

Overview

The following discussion addresses material changes in the results of operations for the three months ended March 31, 2007, compared to the three months ended March 31, 2006, and the material changes in financial condition since December 31, 2006. It is presumed that readers have read or have access to our Annual Report on Form 10-K for the year ended December 31, 2006, which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We continue to execute our strategy to increase value per share. The following summarizes our performance for the first quarter of 2007 compared to the first quarter of 2006:

·	Net income for the quarter increased 47% to $14.0 million;

·	Earnings per share rose 47% to $0.28 per diluted share;

·	Total revenue, including the effects of hedging, increased 17% to $75.8 million;

·	Average sales price, including the effects of hedging, declined 7% to $7.68 per Mcfe;

·	Production climbed 26% to 9.7 Bcfe;

·	Capital expenditures increased over 60% to $62.8 million; and

·	Drilled 45 gross wells with a success rate of 91%.

We have significantly grown our natural gas and oil production operations since our July 2005 Acquisition and management believes it has the ability to continue growing production by drilling already identified locations on our current existing leases.

In addition, in April 2007, we entered into two additional financial fixed price swaps with prices ranging from $7.25 per MMBtu to $8.63 per MMBtu for a total of 5,000 MMBtu per day covering a portion of our production.

Critical Accounting Policies and Estimates

In our Annual Report on Form 10-K for the year ended December 31, 2006, 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, income taxes and stock-based compensation.

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

Our ceiling test computation was calculated using hedge adjusted market prices at March 31, 2007 which were based on a Henry Hub price of $7.34 per MMBtu and a West Texas Intermediate oil price of $66.20 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2007 increased the calculated ceiling value by approximately $15 million (net of tax). There was no writedown recorded at March 31, 2007. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a writedown could occur.

Results of Operations

Revenues. Our revenues are derived from the sale of our oil and natural gas production, which includes the effects of qualifying hedge contracts. Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold. Total revenue for the first three months of 2007 was $75.8 million which is an increase of $11.3 million, or 17%. Approximately, 91% of the first quarter revenue was attributable to natural gas sales on total volumes of 9.7 Bcfe.

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	Three Months Ended March 31,
	2007		2006		% Change Increase/(Decrease)
	(In thousands, except per unit amounts)
Total revenues	$	75,796	$	64,544		17	%

Production:
Gas (Bcf)		9.0		6.9		30	%
Oil (MBbls)		120.0		127.2		(6	%)
Total Equivalents (Bcfe)		9.7		7.7		26	%

$ per unit:
Avg. Gas Price per Mcf	$	7.68	$	8.22		(7	%)
Avg. Gas Price per Mcf excluding Hedging		7.12		7.99		(11	%)
Avg. Oil Price per Bbl		55.29		61.39		(10	%)
Avg. Revenue per Mcfe	$	7.81	$	8.38		(7	%)

Natural Gas. For the three months ended March 31, 2007, natural gas revenue increased by $12.4 million, including the realized impact of derivative instruments, from the comparable period in 2006, to $69.2 million. The increase is primarily attributable to an increase in production in the California and the Lobo regions resulting in an increase of $16.6 million and an increase in gains related to hedging activities of $3.5 million. Lower natural gas prices led to an approximate $7.7 million decrease in natural gas revenues from the comparable period in 2006.

Crude Oil. For the three months ended March 31, 2007, oil sales revenue was $6.6 million as compared to $7.8 million for the same period in 2006. This decrease of $1.2 million is due to both a $6.10 per Bbl decrease in the realized oil price and a 7.2 MBbl decrease in production. The decrease in production is primarily the result of natural declines in our Offshore area.

Operating Expenses

	Three Months Ended March 31,
	2007		2006		% Change Increase/(Decrease)
	(In thousands, except per unit amounts)
Lease operating expense	$	8,796	$	9,558		(8	%)
Depreciation, depletion and amortization		30,551		24,067		27	%
General and administrative costs	$	8,069	$	9,251		(13	%)

$ per unit:
Avg. lease operating expense per Mcfe	$	0.91	$	1.24		(27	%)
Avg. DD&A per Mcfe		3.15		3.13		1	%
Avg. G&A per Mcfe	$	0.83	$	1.20		(31	%)

Our operating expenses are primarily related to the following items:

Lease Operating Expense. Lease operating expense decreased $0.8 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. In 2006, we incurred $1.2 million more in workover expenses which were associated with the Offshore area that were not incurred in 2007.

Depreciation, Depletion, and Amortization. Depreciation, depletion and amortization expense increased $6.5 million from the same period in 2006 to $30.6 million for the three months ended March 31, 2007. Depletion expense for oil and gas properties is calculated using the unit of production method, which amortizes the capitalized costs associated with the evaluated properties based on the ratio of production volumes for the current period to the total remaining reserve volumes for the evaluated properties. The increase for 2007 is due to the 26% increase in production for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006.

General and Administrative Costs. General and administrative costs were $8.1 million for the three months ended March 31, 2007 as compared to $9.3 million for the same period in 2006. This decrease is primarily associated with the costs incurred during the three months ended March 31, 2006 relating to legal, accounting and consulting fees associated with becoming a public entity, which were not incurred in the current reporting period for 2007. In addition, $0.5 million of the decrease is associated with stock compensation expense which was $1.3 million for the three months ended March 31, 2007 as compared to $1.8 million for the same period in 2006. For the first quarter of 2006, certain bonus stock awards granted in July 2005 vested resulting in increased compensation expense for 2006 as compared to the first quarter of 2007.

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Total Other Expense

Other expense includes interest expense, interest income and other income/expense, net and was comparable for the three months ended March 31, 2007 to the corresponding period in 2006, with a $0.4 million increase. The increase in other expense is the result of less interest income in the first three months of 2007 to offset expenses as compared to 2006. The interest income is earned on the cash balance, which was greater at March 31, 2006 than at March 31, 2007. Approximately $35.3 million was expended primarily during the fourth quarter of 2006 to fund various asset acquisitions.

Provision for Income Taxes

The effective tax rate for the three months ended March 31, 2007 was 38.0%, which is comparable to the tax rate for the three months ended March 31, 2006 of 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.

Liquidity and Capital Resources

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

Operating Cash Flow. Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production thereby mitigating our exposure to price declines, but these transactions 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. The effects of these derivative transactions on our natural gas revenue is discussed above under “Results of Operations – Natural Gas”. In addition, the majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels.

Senior Secured Revolving Line of Credit. BNP Paribas, in July 2005 provided us with a senior secured revolving line of credit concurrent with our acquisition of Calpine Corporation’s domestic oil and natural gas business, (the “Acquisition”), in the amount of up to $400.0 million (“Revolver”). This Revolver was syndicated to a group of lenders on September 27, 2005. Availability under the Revolver is restricted to the borrowing base, which initially was $275.0 million and was reset to $325.0 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. In July 2005, we repaid $60.0 million of the $225.0 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. In May 2007, the borrowing base was adjusted to $350.0 million. Initial amounts outstanding under the Revolver bore interest, as amended, at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%. These rates over LIBOR were adjusted in May to be 1.00% to 1.75%. 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 SEC PV-10 pretax 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 contract. 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 each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At March 31, 2007, our current ratio was 2.6 to 1.0, as adjusted per current agreements and our leverage ratio was 1.2 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, 2007. All amounts drawn under the Revolver are due and payable on July 7, 2009. Availability under the revolving line of credit was $159.0 million at March 31, 2007.

Second Lien Term Loan. In July 2005, BNP Paribas provided us with a second lien term loan in the amount of $100.0 million (“Term Loan”). On September 27, 2005, we repaid $25.0 million of borrowings on the Term Loan, reducing the balance to $75.0 million and syndicated the Term 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 Term Loan has been reduced to LIBOR plus 4.00%. The Term 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, 2007. The revised principal balance of the Term Loan is due and payable on July 7, 2010.

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Cash Flows

	Three Months Ended March 31,
	2007			2006
	(In thousands)
Cash flows provided by operating activities	$	46,521		$	41,015
Cash flows used in investing activities		(58,449	)		(36,189	)
Cash flows provided by (used in) financing activities		55			(799	)
Net (decrease) increase in cash and cash equivalents	$	(11,873	)	$	4,027

Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation and general and administrative expenses. Net cash provided by operating activities (“Operating Cash Flow”) continued to be a primary source of capital and liquidity used to finance our capital expenditures in the first quarter of 2007.

Cash flows provided by operating activities increased by $5.5 million for the three months ended March 31, 2007 compared to the same period in 2006. The increase in 2007 primarily resulted from higher oil and gas production. Working capital at March 31, 2007 was less than $1 million compared to $30.7 million at December 31, 2006. This decrease for the first quarter 2007 was largely driven by non-cash fair value changes in our derivative instruments as well as cash calls paid to fund on-going drilling programs in the Offshore and Texas State Waters areas and for the payment of ad valorem taxes.

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

Cash flows used in investing activities increased by $22.3 million for the three months ended March 31, 2007 compared to the same period in 2006. During the three month period ended March 31, 2007, the Company participated in the drilling of 45 gross wells with the majority of these being in the Rocky Mountains and the Lobo areas.

Financing Activities. The primary driver of cash used in financing activities is equity transactions.

Cash flows provided by financing activities increased by $0.9 million for the three months ended March 31, 2007 compared to the same period in 2006. The increase was primarily related to fewer repurchases of shares of common stock. The shares were surrendered by certain employees to pay tax withholding upon vesting of restricted stock awards. These repurchases are not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of common stock.

Capital Expenditures

Our capital expenditures for the three months ended March 31, 2007 increased by $24.2 million to $62.8 million over the comparable period in 2006. During the three months ended March 31, 2007, we participated in the drilling of 45 gross wells with the majority of these being in the Rocky Mountains and the Lobo areas. Our positive Operating Cash Flow, along with the availability under our revolving credit facility, is projected to be sufficient to fund our budgeted capital expenditures for 2007, which are currently projected to be $250.0 million.

Calpine Bankruptcy

On December 20, 2005 Calpine and certain of its subsidiaries filed for protection under federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (the “Bankruptcy Court”). The filing raises certain concerns regarding aspects of our relationship with Calpine which we will continue to closely monitor as the Calpine bankruptcy proceeds. See Part II. Item 1. Legal Proceedings for further information regarding the Calpine bankruptcy.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are 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, 2006. There have been no significant changes in our market risk from what was disclosed in our Annual Report filed on Form 10-K for the year ended December 31, 2006.

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, 2007. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2007, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There are no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

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PART II. Other Information

Item 1. Legal Proceedings

We and our subsidiaries are party to various oil and natural gas litigation matters arising out of 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.

Calpine Bankruptcy

Calpine Corporation and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the Bankruptcy Court on December 20, 2005. Calpine Energy Services, L.P., which filed for bankruptcy, has continued to make the required deposits into our margin account and to timely pay for natural gas production it purchases from our subsidiaries under various natural gas supply agreements. Additionally, Calpine Producer Services, L.P., which filed for bankruptcy, is under contract through June 30, 2007 with us and is generally performing its obligations under the Marketing and Services Agreement.

There remains the possibility, however, that there will be issues between us and Calpine that could amount to material contingencies in relation to the Purchase and Sale Agreement and interrelated agreements concurrently executed therewith, dated July 7, 2005, by and among Calpine, us, and various other signatories thereto (collectively, the “Purchase Agreement”), including unasserted claims and assessments with respect to (i) the still pending 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 Purchase Agreement; and (iii) the ultimate disposition of the remaining Non-Consent Properties (and related royalty revenues). Calpine has specific obligations to us under the Purchase Agreement relating to these matters, and also has “further assurances” duties to us under the Purchase Agreement.

In addition, as to certain of the other oil and natural gas properties we purchased from Calpine in the Acquisition and for which payment was made on July 7, 2005, we will seek additional documentation from Calpine to eliminate any open issues in our title or resolve any issues as to the clarity of our ownership. Requests for additional documentation are customary in connection with transactions similar to the Acquisition. In the Acquisition, certain of these properties require ministerial governmental action approving us as qualified assignee and operator, which is typically required even though in most cases Calpine has already conveyed the properties to us free and clear of mortgages and liens by Calpine’s creditors. As to certain other properties, the documentation delivered by Calpine at closing under the Purchase Agreement was incomplete. We remain hopeful that Calpine will work cooperatively with us to secure these ministerial governmental approvals and to accomplish the curative corrections for all of these properties. In addition, as to all properties acquired by us in the Acquisition, Calpine contractually agreed to provide us with such further assurances as we may reasonably request. Nevertheless, as a result of Calpine’s bankruptcy filing, it remains uncertain as to whether Calpine will respond cooperatively. If Calpine does not fulfill its contractual obligations and does not complete the documentation necessary to resolve these 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 financial condition, statement of operations and cash flows.

On June 29, 2006, Calpine filed a motion in connection with its pending bankruptcy proceeding in the Bankruptcy Court seeking the entry of an order authorizing Calpine to assume certain oil and natural gas leases that Calpine had previously sold or agreed to sell to us in the Acquisition, to the extent those leases constitute “unexpired leases of non-residential real property” and were not fully transferred to us at the time of Calpine’s filing for bankruptcy. According to this motion, Calpine filed in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a statutory deadline. Calpine’s motion did not request that the Bankruptcy Court determine whether these properties belong to us or Calpine, but we understand it was meant to allow Calpine to preserve and avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may possess, if any, in these oil and natural gas leases. We dispute Calpine’s contention that it may have an interest in any significant portion of these oil and natural gas leases and intend to take the necessary steps to protect all of our rights and interest in and to the leases. On July 7, 2006, we filed an objection in response to Calpine’s motion, wherein we asserted that oil and natural gas leases constitute interests in real property that are not subject to “assumption” under the Bankruptcy Code. In the objection we also requested that (a) the Bankruptcy Court eliminate from the order certain Federal offshore leases from the Calpine motion because these properties were fully conveyed to us in July 2005, and the Minerals Management Service has subsequently recognized us as owner and operator of all but three of these properties, and (b) any order entered by the Bankruptcy Court be without prejudice to, and fully preserve our rights, claims and legal arguments regarding the characterization and ultimate disposition of the remaining described oil and natural gas properties. In our objection, we also urged the Bankruptcy Court to require the parties to promptly address and resolve any remaining issues under the pre-bankruptcy definitive agreements with Calpine and proposed to the Bankruptcy Court that the parties seek arbitration (or at least mediation) to complete the following:

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Calpine’s conveyance of the Non-Consent Properties to us;

Resolution of the final amounts we are to pay Calpine, which we have concluded is approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations.

At a hearing held on July 12, 2006, the Bankruptcy took the following steps:

The Bankruptcy Court also encouraged Calpine and us to arrive at a business solution to all remaining issues including approximately $68 million payable to Calpine for conveyance of the Non-Consent Properties.

On August 1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy asserting claims against a variety of Calpine debtors seeking recovery of $27.9 million in liquidated amounts as well as unliquidated damages in amounts that can not presently be determined. We continue to work with Calpine on a cooperative and expedited basis toward resolution of unresolved conveyance of properties and post closing adjustments under the Purchase Agreement.

With respect to the stipulations between Calpine and MMS and Calpine and CSLC extending the deadline to assume or reject the MMS Oil and Gas Leases, these parties have further extended this deadline time by stipulation. The deadline was first extended to January 31, 2007, then was further extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007 with respect to the CSLC Leases, and recently was further extended to September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007 with respect to the CSLC Leases. The Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC Leases which included appropriate language that we negotiated with Calpine for our protection in this regard.

Recently, Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy Court for the period in which only Calpine, exclusively, may file its plan of reorganization. While there is no assurance that Calpine will file a plan of reorganization by this deadline, or that such a plan will be approved by the creditors and the Bankruptcy Court, we remain optimistic that the issues involving conclusion of the remaining conveyances of the Non-Consent Properties and obtaining the further assurances from Calpine under the Purchase Agreement, including perhaps resolution of any and all claims, may occur during 2007.

Calpine recently requested Bankruptcy Court approval of a new credit facility which would require it to grant liens to these new lenders in all of its assets, including any interest it may still hold in any oil and natural gas properties it obligated itself to convey to us under the Purchase Agreement. The Bankruptcy Court entered an Order approving Calpine’s ability to obtain this new loan which includes appropriate language that we negotiated with Calpine for our protection in this regard.

Furthermore, there can be no assurance that Calpine, its creditors or other interest holders will not challenge the fairness of the Acquisition. For a number of reasons, including our understanding of the process that Calpine followed in allowing market forces to set the purchase price for the Acquisition, we believe that it is unlikely that any challenges by the Calpine debtors or their creditors to the overall fairness of the Acquisition would be successful. We will take all necessary action to ensure our rights under the Purchase agreement, the MMS Oil and Gas Leases, the CSLC Leases and the Bankruptcy Code are fully protected.

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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, 2006.

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		82	$	18.76		-		-
February 1 - February 28		2,473		18.87		-		-
March 1 - March 31		544		19.52		-		-

(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.

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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

32.1

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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Signatures

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

	ROSETTA RESOURCES INC.
	By:	/s/ MICHAEL J. ROSINSKI
	Michael J. Rosinski
	Executive Vice President and Chief Financial Officer

	(Duly Authorized Officer and Principal Financial Officer)

Date: May 15, 2007

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ROSETTA RESOURCES INC.

EXHIBIT INDEX

Exhibit Number		Description
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
32.1		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