Edgar Filing: Rosetta Resources Inc.

form10q.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 June 30,2007

¨	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 August 2, 2007 was 50,776,158.

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	22
	Item 4. Controls and Procedures	23
Part II–	Other Information
	Item 1. Legal Proceedings	23
	Item 1A. Risk Factors	27
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28
	Item 3. Defaults Upon Senior Securities	29
	Item 4. Submission of Matters to a Vote of Security Holders	29
	Item 5. Other Information	29
	Item 6. Exhibits	30
Signatures		31
Exhibit Index		32
Rule 13a-14(a) Certification executed by Charles F. Chambers
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)

	June 30,			December 31,
	2007			2006
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	11,769		$	62,780
Accounts receivable		37,900			36,408
Derivative instruments		4,035			20,538
Prepaid expenses		19,585			8,761
Other current assets		3,800			2,965
Total current assets		77,089			131,452
Oil and natural gas properties, full cost method, of which $41.2 million at June 30, 2007 and $37.8 million at December 31, 2006 were excluded from amortization		1,399,194			1,223,337
Other fixed assets		5,378			4,562
		1,404,572			1,227,899
Accumulated depreciation, depletion, and amortization		(210,712	)		(145,289	)
Total property and equipment, net		1,193,860			1,082,610
Deferred loan fees		2,785			3,375
Other assets		1,094			1,968
Total other assets		3,879			5,343
Total assets	$	1,274,828		$	1,219,405

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	30,385		$	23,040
Accrued liabilities		51,470			43,099
Royalties payable		12,272			9,010
Prepayment on gas sales		22,488			17,868
Deferred income taxes		1,521			7,743
Total current liabilities		118,136			100,760
Long-term liabilities:
Derivative instruments		17,905			11,014
Long-term debt		240,000			240,000
Asset retirement obligation		11,989			10,253
Deferred income taxes		48,744			35,089
Total liabilities		436,774			397,116
Commitments and contingencies (Note 8)
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 50,466,973 shares and 50,405,794 shares at June 30, 2007 and December 31, 2006, respectively		50			50
Additional paid-in capital		759,090			755,343
Treasury stock, at cost; 91,217 and 85,788 shares at June 30, 2007 and December 31, 2006, respectively		(1,675	)		(1,562	)
Accumulated other comprehensive (loss) income		(8,636	)		6,315
Retained earnings		89,225			62,143
Total stockholders' equity		838,054			822,289
Total liabilities and stockholders' equity	$	1,274,828		$	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						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Revenues:
Natural gas sales	$	77,436		$	53,682		$	146,597		$	110,417
Oil sales		9,438			9,699			16,073			17,508
Total revenues		86,874			63,381			162,670			127,925
Operating Costs and Expenses:
Lease operating expense		12,566			8,323			21,362			17,881
Depreciation, depletion, and amortization		36,342			25,601			66,893			49,668
Treating and transportation		882			831			1,645			1,726
Marketing fees		669			484			1,332			1,108
Production taxes		1,200			1,626			2,185			3,323
General and administrative costs		9,898			7,078			17,967			16,329
Total operating costs and expenses		61,557			43,943			111,384			90,035
Operating income		25,317			19,438			51,286			37,890

Other (income) expense
Interest expense, net of interest capitalized		4,680			4,371			9,050			8,503
Interest income		(257	)		(1,115	)		(1,229	)		(2,252	)
Other (income) expense, net		(182	)		152			(182	)		177
Total other expense		4,241			3,408			7,639			6,428

Income before provision for income taxes		21,076			16,030			43,647			31,462
Provision for income taxes		7,985			6,066			16,565			11,972
Net income	$	13,091		$	9,964		$	27,082		$	19,490

Earnings per share:
Basic	$	0.26		$	0.20		$	0.54		$	0.39
Diluted	$	0.26		$	0.20		$	0.54		$	0.39

Weighted average shares outstanding:
Basic		50,354			50,229			50,340			50,175
Diluted		50,625			50,370			50,565			50,361

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)

	Six Months Ended
	June 30,
	2007			2006
Cash flows from operating activities
Net income	$	27,082		$	19,490
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		66,893			49,668
Deferred income taxes		16,479			11,723
Amortization of deferred loan fees recorded as interest expense		590			590
Income from unconsolidated investments		(85	)		(112	)
Stock compensation expense		3,176			3,322
Change in operating assets and liabilities:
Accounts receivable		(1,492	)		15,121
Income taxes receivable		-			6,000
Other current assets		(11,659	)		(2,624	)
Other assets		331			934
Accounts payable		7,345			3,411
Accrued liabilities		(2,247	)		(5,385	)
Royalties payable		7,882			(8,707	)
Net cash provided by operating activities		114,295			93,431
Cash flows from investing activities
Acquisition of oil and gas properties		(38,656	)		(11,580	)
Purchases of property and equipment		(128,139	)		(87,983	)
Disposals of property and equipment		1,005			36
Deposits		25			25
Other		1			(14	)
Net cash used in investing activities		(165,764	)		(99,516	)
Cash flows from financing activities
Equity offering transaction fees		-			268
Proceeds from issuances of common stock		571			296
Stock-based compensation excess tax benefit		-			249
Purchases of treasury stock		(113	)		(1,246	)
Net cash provided by (used in) financing activities		458			(433	)

Net decrease in cash		(51,011	)		(6,518	)
Cash and cash equivalents, beginning of period		62,780			99,724
Cash and cash equivalents, end of period	$	11,769		$	93,206

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	6,020		$	2,281

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 primarily 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 a 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. The accompanying consolidated financial statements as of June 30, 2007 and December 31, 2006 and for the three and six months ended June 30, 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 is currently evaluating 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 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 our financial condition or results of operations 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 consists of the following:

	June 30,			December 31,
	2007			2006
	(In thousands)
Proved properties	$	1,342,654		$	1,170,223
Unproved properties		32,796			35,178
Gas gathering systems and compressor stations		23,744			17,936
Other		5,378			4,562
Total		1,404,572			1,227,899
Less: Accumulated depreciation, depletion, and amortization		(210,712	)		(145,289	)
	$	1,193,860		$	1,082,610

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.1 million and $2.4 million of internal costs for the three and six months ended June 30, 2007, respectively, and $0.9 million and $1.7 million for the three and six months ended June 30, 2006, respectively.

Included in the Company’s oil and gas properties are asset retirement obligations of $15.3 million and $9.6 million as of June 30, 2007 and December 31, 2006, respectively.

Oil and gas properties include costs of $41.2 million and $37.8 million at June 30, 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 the Offshore and Texas State Waters regions.

The Company’s ceiling test computation was calculated using hedge adjusted market prices at June 30, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and a West Texas Intermediate oil price of $69.63 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2007 increased the calculated ceiling value by approximately $21.7 million (net of tax). There was no write-down recorded at June 30, 2007. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a write-down 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 $38.7 million, subject to final adjustments.

(4)

Commodity Hedging Contracts and Other Derivatives

In the second quarter of 2007, the Company entered into additional 5,000 MMBtu per day of financial fixed price swaps with an average underlying price of $8.08 per MMBtu covering a portion of the Company’s 2008 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 June 30, 2007:

							Total of
			Notional	Total of		Average	Proved	Fair Market
			Daily	Notional		Underlying	Natural Gas	Value
Settlement	Derivative	Hedge	Volume	Volume		Prices	Production	Gain/(Loss)
Period	Instrument	Strategy	MMBtu	MMBtu		MMBtu	Hedged (1)	(In thousands)
2007	Swap	Cash flow	55,316		10,178,200	7.80	45%		7,231
2008	Swap	Cash flow	54,909		20,096,616	7.66	48%		(9,898	)
2009	Swap	Cash flow	26,141		9,541,465	6.99	26%		(12,221	)
					39,816,281			$	(14,888	)

(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 June 30, 2007:

Total of

Fair

Notional

Total of

Average

Proved

Market

Daily

Notional

Floor

Ceiling

Natural Gas

Value

Settlement

Derivative

Hedge

Volume

Price

Production

Gain/(Loss)

Period

Instrument

Strategy

MMBtu

Hedged (1)

(In thousands)

2007

Costless Collar

Cash flow

10,000

1,840,000

7.19

10.03

1,026

1,840,000

1,026

(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 June 30, 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 June 30,				Six Months Ended June 30,
Natural Gas	2007		2006		2007		2006
Quantity settled (MMBtu)		5,946,800		5,005,000		11,471,300		9,955,000
Increase in natural gas sales revenue (In thousands)	$	2,433	$	9,127	$	7,477	$	10,690

The Company expects to reclassify losses of $2.5 million based on market pricing as of June 30, 2007 to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.

At June 30, 2007, the Company had derivative assets of $4.0 million on the Consolidated Balance Sheet. The Company also had derivative liabilities of $17.9 million which was included in long-term liabilities on the Consolidated Balance Sheet at June 30, 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 June 30, 2007.

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 and six months ended June 30, 2007 and 2006.

(5)

Asset Retirement Obligation

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

	Six Months Ended
	June 30, 2007
	(In thousands)
ARO as of January 1, 2007	$	10,689
Revision of previous estimates		4,697
Liabilities incurred during period		1,031
Accretion expense		605
ARO as of June 30, 2007	$	17,022

Of the total ARO, approximately $5.0 million is classified as a current liability included in accrued liabilities on the Consolidated Balance Sheet at June 30, 2007.

(6)

Long-Term Debt

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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 which was adjusted in May 2007 to $350.0 million and a five-year $75.0 million second lien term loan.

On June 30, 2007, the Company had outstanding borrowings and letters of credit of $240.0 million and $1.0 million, respectively. Net borrowing availability under the Revolver was $184.0 million at June 30, 2007. The Company was in compliance with all covenants at June 30, 2007.

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 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 June 30, 2007.

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 June 30, 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 financial position, results of operations or cash flows.

Calpine Bankruptcy

On December 20, 2005, Calpine 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”).

Calpine’s Lawsuit Against Rosetta

On June 29, 2007, Calpine filed an adversary proceeding against the Company in the Bankruptcy Court. The complaint alleges that the purchase by the Company of the domestic oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for bankruptcy, was completed when Calpine was insolvent and was for less than a reasonably equivalent value. Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for these assets which it estimates to be approximately $400 million dollars, plus interest, or (ii) in the alternative, return of the Assets from the Company. The Company believes that these allegations are wholly baseless, intends to vigorously defend against all claims made by Calpine and is further considering additional steps it may take to fully protect the Company's interests. The Company continues to believe that it is unlikely that this challenge by the Calpine debtors to the fairness of the Acquisition will be successful upon ultimate disposition after appeals, if any. The deadline for the Company to answer or file its responsive pleading is September 10, 2007, and the Company has advised the Bankruptcy Court that it intends to file a motion to dismiss the complaint on or before the answer date. Calpine has requested a trial date in December 2007, but at the present time, no trial date has been set by the Bankruptcy Court.

Remaining Issues with Respect to the Acquisition

Separate from the Calpine lawsuit, Calpine has taken the position that 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”) are “executory contracts”, which Calpine may assume or reject. Following the July 7, 2005 closing of the Acquisition and as of the date of Calpine’s bankruptcy filing, there were open issues regarding legal title to certain properties included in the Purchase Agreement. On June 20, 2007, Calpine filed with the Bankruptcy Court its proposed Plan of Reorganization under Chapter 11 of the Bankruptcy Code, together with the accompanying Disclosure Statement, in which Calpine revealed it had not yet made a decision as to whether to assume or reject its remaining duties and obligations under the Purchase Agreement. If the Court were to determine that the Purchase Agreement is an executory contract, the various agreements entered into as part of the transaction constitute a single contract for purposes of assumption or rejection under the Bankruptcy Code, and the Company contends that Calpine cannot choose to assume certain of the agreements and to reject others. This issue may be contested by Calpine. If the Purchase Agreement is held to be executory, the deadline by when Calpine must exercise its decision to assume or reject the Purchase Agreement and the further duties and obligations required therein is the date on which Calpine’s Plan of Reorganization is confirmed.

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Open Issues Regarding Legal Title to Certain Properties

Under the Purchase Agreement, Calpine is required to resolve the open issues regarding legal title to certain properties. At the closing of the Acquisition on July 7, 2005, the Company retained approximately $75 million of the purchase price in respect to Non-Consent Properties identified by Calpine as requiring third-party consents or waivers of preferential rights to purchase that were not received by the parties before closing ("Non-Consent Properties"). Those Non-Consent Properties were therefore not included in the conveyances delivered at the closing. Subsequent analysis determined that a significant portion of the Non-Consent Properties did not require consents or waivers. For that portion of the Non-Consent Properties for which third-party consents were in fact required and for which either the Company or Calpine obtained the required consents or waivers, as well as for all Non-Consent Properties that did not require consents or waivers, the Company contends Calpine was and is obligated to have transferred to it the record title, free of any mortgages and other liens.

The approximate allocated value under the Purchase Agreement for the portion of the Non-Consent Properties subject to a third-party’s preferential right to purchase is $7.4 million. The Company has retained $7.1 million of the purchase price under the Purchase Agreement for the Non-Consent Properties subject to the third-party preferential right, and, in addition, a post-closing adjustment is required to credit the Company for approximately $0.3 million for a property which was transferred to it but, if necessary, will be transferred to the appropriate third party under its exercised preferential purchase right upon Calpine’s performance of its obligations under the Purchase Agreement.

The Company believes all conditions precedent for its receipt of record title, free of any mortgages or other liens, for substantially all of the Non-Consent Properties (excluding that portion of these properties subject to the third-party preferential right) were satisfied earlier, and certainly no later, than December 15, 2005, when the Company tendered once again the amounts necessary to conclude the settlement of the Non-Consent Properties.

The Company believes it is the equitable owner of each of the Non-Consent Properties for which Calpine was and is obligated to have transferred the record title and that such properties are not part of Calpine’s bankruptcy estate. Upon the Company’s receipt from Calpine of record title, free of any mortgages or other liens, to these Non-Consent Properties and further assurances required to eliminate any open issues on title to the remaining properties discussed below, the Company is prepared to pay Calpine approximately $68 million, subject to appropriate adjustment, if any. The Company’s statement of operations for the six months ended June 30, 2007, the year ended December 31, 2006 and six months ended December 31, 2005, does not include any net revenues or production from any of the Non-Consent Properties, including those properties subject to preferential rights.

If Calpine does not provide the Company with record title, free of any mortgages for all of these properties and other liens, to any of the Non-Consent Properties (excluding that portion of these properties subject to a validly exercised third party’s preferential right to purchase), the Company will have a total of approximately $68 million available to them for general corporate purposes, including for the purpose of acquiring additional properties. The Company also has approximately $7.1 million, previously withheld for that portion of the Non-Consent Properties subject to a third party’s preferential right to purchase, which will also be available for general corporate purposes, including for the purpose of acquiring additional properties should that third party properly exercise the preferential rights.

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 is seeking 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 (as a result of rejection of the Purchase Agreement or otherwise) 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 unlikely upon ultimate disposition, including appeals, if any, then the Company could experience losses which could have a material adverse effect on the Company’s financial condition, statement of operations and cash flows.

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Sale of Natural Gas to Calpine

In addition, the issues involving legal title to certain properties, the Company executed, as part of the interrelated agreements that constitute the Purchase Agreement, certain natural gas supply agreements with Calpine Energy Services, L.P. (“CES”), which also filed for bankruptcy on December 20, 2005. During the period following Calpine’s filing for bankruptcy, CES 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 these various natural gas supply agreements. Although Calpine has indicated in a supplement to its recently proposed plan of reorganization that it intends to assume the CES natural gas supply agreements with the Company, the Company disagrees that Calpine may assume anything less than the entire Purchase Agreement and intends to oppose any effort by Calpine to do less.

Calpine’s Marketing of the Company’s Production

Additionally, Calpine Producer Services, L.P. (“CPS”), which also filed for bankruptcy, entered into a Marketing and Services Agreement (“MSA”) with the Company as part of the interrelated agreements that constitute the Purchase Agreement. Under the MSA, CPS provided marketing and sales of the Company’s natural gas production to third-parties and charged the Company a fee. The MSA, however, expired by its terms on June 30, 2007. Through a recently executed letter agreement, CPS and the Company agreed to extend the MSA until September 30, 2007, subject to and to enable the parties to negotiate and execute a New Marketing and Services Agreement (“New MSA”). On August 3, 2007, as part of the Partial Transfer and Release Agreement, discussed in greater detail below, the Company and CPS concurrently executed the New MSA, which, if approved by the Bankruptcy Court, will be effective as of July 1, 2007 and extend CPS’ obligation to provide such services until June 30, 2009. The New MSA is subject to earlier termination by the Company upon the occurrence of certain events. In the interim, CPS is generally performing its obligations under the MSA.

Events Within Calpine’s Bankruptcy Case

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. The oil and gas leases identified in Calpine’s motion are, in large part, those properties with open issues in regards to their legal title in which Calpine contends it may possess some legal interest. According to this motion, Calpine filed it in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a bankruptcy code 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 could seek 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

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Resolution of the final amounts the Company is to pay Calpine, which the Company had at that time concluded was approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations. The Company is currently updating these calculations.

At a hearing held on July 12, 2006, the Bankruptcy Court 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

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. In the event that Calpine elects to reject the Purchase Agreement or otherwise refuses to perform its remaining obligations therein, the Company anticipates it will be allowed to amend its proofs of claim to assert any additional damages it suffers as a result of the ultimate impact of Calpine’s refusal or failure to perform under the Purchase Agreement. In the bankruptcy, Calpine may elect to contest or dispute the amount of damages the Company seeks in its proofs of claim. The Company will assert all right to offset any of its damages against any funds it possesses that may be owed to Calpine. Until the allowed amount of the Company’s claims are finally established and the Bankruptcy Court issues its rulings with respect to Calpine’s plan confirmation, the Company can not predict what amounts it may recover from the Calpine bankruptcy should Calpine reject or refuse to perform 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 and the CSLC Leases respectively, these parties have further extended this deadline by stipulation. The deadline was first extended to January 31, 2007, 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, was further extended again to September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007 and more recently, October 31, 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 the Company’s protection in this regard.

On June 20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure Statement with the Bankruptcy Court. Calpine has indicated in its filings with the Court that it believes substantial payments in the form of cash or newly issued stock, or some combination thereof, will be made to unsecured creditors under its proposed Plan of Reorganization that could conceivably result in payment of 100% of allowed claims and possibly provide some payment to its equity holders. The amounts any plan ultimately distributes to its various claimants of the Calpine estate, including unsecured creditors, will depend on the Court’s conclusion with regard to Calpine’s enterprise value and the amount of allowed claims that remain following the objection process.

On June 29, 2007, Calpine filed a notice with the Bankruptcy Court that it was in discussions with unnamed third parties regarding alternative plans of reorganization that might yield guaranteed payments to equity holders, thus paying all unsecured creditors, and requested an extension of time to allow such discussions to continue. Although the deadlines with respect to confirming any plan would be pushed back by approximately one month, Calpine stated in its notice that its beneficial financing terms required it emerge from bankruptcy by January 31, 2008.

On August 3, 2007, the Company and Calpine executed a Partial Transfer and Release Agreement (“PTRA”), subject to Bankruptcy Court approval, resolving certain open issues without prejudice to Calpine’s avoidance action and, if the Court concludes the Purchase Agreement is executory, Calpine’s ability to assume or reject the Purchase Agreement. The principle terms are as follows:

The Company will extend its existing natural gas marketing agreement with Calpine until June 30, 2009. This agreement is subject to earlier termination right by the Company upon the occurrence of certain events;

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Calpine will deliver to the Company documents that resolve title issues pertaining to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (“Properties”);

The Company will assume all Calpine's rights and obligations for an audit by the California State Lands Commission on part of the Properties; and

The Company will assume all rights and obligations for the Properties, including all plugging and abandonment liabilities.

A number of the properties that, after the closing of the Acquisition, had open issues in regards to legal title will be resolved by the PTRA, if approved by the Bankruptcy Court. Until a final order is received approving Calpine’s entry into the PTRA, the possibility remains that the PTRA will not become binding obligations of the parties.

As a result of Calpine’s bankruptcy, there remains the possibility that there will be issues between the Company and Calpine that could amount to material contingencies in relation to the litigation filed by Calpine against the Company or 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 revenues).

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 that 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 of Calpine and it is too early for management to determine whether or in what amount, if any, this matter will have on 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 June 30, 2007 and December 31, 2006 was $0.1 million. The Company does not expect that the outcome of the 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

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 June 30, 2007 or December 31, 2006 as the study is still in the preliminary stage.

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Comprehensive Income

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

	Three Months Ended June 30,												Six Months Ended June 30,
	2007						2006						2007						2006
	(In thousands)
Accumulated other comprehensive (loss) income beginning of period				$	(16,979	)				$	(19,615	)				$	6,315					$	(50,731	)
Net income		13,091						9,964						27,082						19,490

Change in fair value of derivative hedging instruments		8,570						21,648						(16,521	)					73,398
Hedge settlements reclassed to income		(2,433	)					(9,127	)					(7,477	)					(10,690	)
Tax provision related to hedges		2,206						(4,758	)					9,047						(23,829	)
Total other comprehensive income (loss)		8,343			8,343			7,763			7,763			(14,951	)		(14,951	)		38,879			38,879

Comprehensive income		21,434						17,727						12,131						58,369
Accumulated other comprehensive loss				$	(8,636	)				$	(11,852	)				$	(8,636	)				$	(11,852	)

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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:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
	(In thousands)
Basic weighted average number of shares outstanding		50,354		50,229		50,340		50,175
Dilution effect of stock option and awards at the end of the period		271		141		225		186
Diluted weighted average number of shares outstanding		50,625		50,370		50,565		50,361

Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect		268		206		407		154

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Geographic Area Information

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”.

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.

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Oil and Natural Gas Revenue

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007 (1)		2006 (1)		2007 (1)		2006 (1)
	(In thousands)
California	$	28,504	$	15,715	$	55,596	$	36,110
Rocky Mountains		2,760		622		4,286		964
Mid-Continent		551		431		1,356		910
Gulf of Mexico		10,908		6,394		16,381		15,921
Lobo		28,391		13,673		53,267		29,082
Perdido		7,570		6,962		13,338		16,784
State Waters		838		2,142		1,647		5,289
Other Onshore		4,919		8,315		9,322		12,175
	$	84,441	$	54,254	$	155,193	$	117,235

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Excludes the effects of hedging of $2.4 million and $9.1 million for the three months ended June 30, 2007 and 2006, respectively, and $7.5 million and $10.7 million for the six months ended June 30, 2007 and 2006, respectively.

Oil and Natural Gas Properties

	June 30, 2007		December 31, 2006
	(In thousands)
California	$	497,077	$	435,167
Rocky Mountains		58,441		44,455
Mid-Continent		14,149		9,584
Gulf of Mexico		144,254		125,425
Lobo		467,500		426,348
Perdido		64,445		52,702
State Waters		46,204		26,922
Other Onshore		107,124		102,734
Other		5,378		4,562
	$	1,404,572	$	1,227,899

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Subsequent Event

In July 2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen resigned. The Company’s Executive Vice President, Charles F. Chambers, is serving as acting President and CEO. D. Henry Houston, chair of the Company's Audit Committee and current director, has been named Chairman of the Board and will lead the Board in the search for a permanent President and CEO. The Company has not filled the vacancy on the Board caused by Mr. Berilgen’s resignation.

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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 and six months ended June 30, 2007 compared to the three and six months ended June 30, 2006, and the material changes in financial condition since December 31, 2006. It is presumed that readers have read or have access to our 2006 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 six months of 2007 as compared to the same period for 2006:

·	Production increased 31%;

·	The average revenue price, including the effects of hedging, decreased $0.25 per Mcfe or 3%;

·	Total revenue, including the effects of hedging, increased $34.7 million or 27%;

·	Net income increased $7.6 million or 39%;

·	Earnings per share increased $0.15 or 38%;

·	Capital expenditures increased by $71 million or 70% including acquisition of oil and gas properties; and

·	Drilled 94 gross wells with a success rate of 85%.

We have significantly grown our oil and natural gas production operations since we acquired Calpine Natural Gas L.P. in July 2005 (the “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 additional 5,000 MMBtu per day of financial fixed price swaps with an average underlying price of $8.08 per MMBtu covering a portion of our 2008 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 June 30, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and a West Texas Intermediate oil price of $69.63 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2007 increased the calculated ceiling value by approximately $21.7 million (net of tax). There was no write-down recorded at June 30, 2007. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a write-down could occur.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 2 to the Consolidated Financial Statements.

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 six months of 2007 was $162.7 million which is an increase of $34.7 million, or 27%, from the six months ended June 30, 2006. Approximately 90% of revenue was attributable to natural gas sales on total volumes of 20.6 Bcfe.

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The following table presents information regarding our revenues and production volumes:

	Three Months Ended							Six Months Ended
	June 30,							June 30,
					% Change							% Change
					Increase/							Increase/
	2007		2006		(Decrease)			2007		2006		(Decrease)
	(In thousands, except percentages and per unit amounts)
Total revenues	$	86,874	$	63,381		37	%	$	162,670	$	127,925		27	%

Production:
Gas (Bcf)		10.0		7.1		41	%		19.0		14.0		36	%
Oil (MBbls)		149.4		143.6		4	%		269.3		270.8		(1	%)
Total Equivalents (Bcfe)		10.9		8.0		36	%		20.6		15.7		31	%

$ per unit:
Avg. Gas Price per Mcf	$	7.74	$	7.56		2	%	$	7.72	$	7.89		(2	%)
Avg. Gas Price per Mcf excluding Hedging		7.50		6.28		19	%		7.32		7.12		3	%
Avg. Oil Price per Bbl		63.17		67.54		(6	%)		59.68		64.65		(8	%)
Avg. Revenue per Mcfe		7.97		7.92		1	%		7.90		8.15		(3	%)

Natural Gas. For the three months ended June 30, 2007, natural gas revenue increased by $23.7 million, including the realized impact of derivative instruments, from the comparable period in 2006, to $77.4 million. This increase is primarily due to an increase in production in the California, the Rocky Mountains, the Offshore and the Lobo regions. Also, the acquisition of the Sacramento Basin properties from Output Exploration, LLC and OPEX Energy, LLC (“OPEX Properties”) in April 2007 contributed to the overall increase in production. The increase in natural gas sales were offset by a decrease in the gain related to hedging activities of $6.7 million.

For the six months ended June 30, 2007, natural gas revenue increased to $146.6 million from $110.4 million for the comparable period in 2006. This increase of $36.2 million is primarily due to an increase in the number of wells producing in 2007 as well as an increase in production volumes associated with the California, the Rocky Mountains, the Offshore and the Lobo regions. Also, the acquisition of the OPEX Properties in April 2007 contributed to the overall increase in production. The 2007 realized average natural gas price was $7.72 as compared to $7.89 for 2006.

Crude Oil. For the three months ended June 30, 2007, oil revenue was $9.4 million as compared to $9.7 million for the same period in 2006. This decrease is attributable to a decrease in the average realized gas prices from $67.54 per Bbl to $63.17 per Bbl. The effects of the decrease in the average realized price was offset by an increase in production volume of 4% primarily as a result of new wells producing in the Offshore region.

For the six months ended June 30, 2007, oil revenue decreased by $1.4 million due to the decrease in the average realized oil price of $4.97 from $64.65 per Bbl to $59.68 per Bbl. The production volumes were 269.3 MBbls for the six months ended June 30, 2007 which is comparable to the same period in 2006.

Operating Expenses

The following table presents information regarding our operating expenses:

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	Three Months Ended							Six Months Ended
	June 30,							June 30,
					% Change							% Change
					Increase/							Increase/
	2007		2006		(Decrease)			2007		2006		(Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	12,566	$	8,323		51	%	$	21,362	$	17,881		19	%
Depreciation, depletion and amortization		36,342		25,601		42	%		66,893		49,668		35	%
General and administrative costs		9,898		7,078		40	%		17,967		16,329		10	%

$ per unit:
Avg. lease operating expense per Mcfe	$	1.15	$	1.04		11	%	$	1.04	$	1.14		(9	%)
Avg. DD&A per Mcfe		3.33		3.20		4	%		3.25		3.16		3	%
Avg. G&A per Mcfe		0.91		0.88		3	%		0.87		1.04		(16	%)

Our operating expenses are primarily related to the following items:

Lease Operating Expense. Lease operating expense increased $4.2 million for the three months ended June 30, 2007 as compared to the three months ended June 30, 2006. This increase is primarily due to an increase in Ad Valorem tax related to property appraisals in California. In addition, the increase in production of 36% contributed to higher costs for equipment rentals, maintenance and repairs, and costs associated with non-operated properties.

Lease operating expense increased $3.5 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. This increase is primarily due to an increase in Ad Valorem tax related to property appraisals in California. In addition, the increase in production of 31% for 2007 contributed to higher costs for equipment rentals, maintenance and repairs, and costs associated with non-operated properties. In the first six months of 2006, we incurred $1.2 million more in workover expenses associated with the Offshore region which was not incurred in 2007.

Depreciation, Depletion, and Amortization. Depreciation, depletion and amortization expense increased $10.7 million for the three months ended June 30, 2007 as compared to the three months ended June 30, 2006. The increase is due to a 36% increase in total production and a higher depletion rate for 2007 as compared to 2006. The depletion rate for the second quarter of 2007 was $3.25 per Mcfe while the rate for the second quarter of 2006 was $3.16 per Mcfe.

Depreciation, depletion and amortization expense increased $17.2 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. The increase is due to a 31% increase in total production and a higher depletion rate for 2007 as compared to 2006. The depletion rate for the respective period in 2007 was $3.15 per Mcfe while the rate for the same period in 2006 was $3.11 per Mcfe.

General and Administrative Costs. General and administrative costs increased by $2.8 million for the three months ended June 30, 2007 as compared to the three months ended June 30, 2006. This increase is primarily associated with legal fees, payroll expenses and costs associated with the first year implementation of Section 404 of the Sarbanes-Oxley Act. In addition, $0.3 million of the increase is due to an increase in stock compensation expense which was $1.8 million for the three months ended June 30, 2007 as compared to $1.5 million for the respective period in 2006.

General and administrative costs increased by $1.6 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. This increase is net of decreases in audit and consulting fees related to higher costs in the first six months of 2006 associated with becoming a public company, which was not incurred in 2007. The costs in the current period are primarily associated with legal fees, payroll expenses and costs associated with the first year implementation of Section 404 of the Sarbanes-Oxley Act. In addition, stock compensation expense of $3.2 million for the six months ended June 30, 2007 was comparable to the 2006 expense of $3.3 million.

Total Other Expense

Other expense includes interest expense, interest income and other income/expense, net which increased $0.8 million and $1.2 million for the three and six months ended June 30, 2007, respectively, as compared to the respective periods in 2006. The increase in other expense is the result of less interest income in 2007 to offset expenses as compared to 2006. The interest income is earned on the cash balance, which was greater at June 30, 2006 than at June 30, 2007. Approximately $35 million was expended during the fourth quarter of 2006 to fund various asset acquisitions and approximately $38 million was expended during the second quarter of 2007 for the acquisition of the OPEX Properties.

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Provision for Income Taxes

The effective tax rate for the six months ended June 30, 2007 was 37.9%, which is comparable to the tax rate for the six months ended June 30, 2006 of 38.1%. The effective tax rate for the three months ended June 30, 2007 and 2006 was 37.8%. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes, tax credits and other permanent differences.

Liquidity and Capital Resources

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

Operating Cash Flow. Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of 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 in which our derivative transactions are in place. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas”. In addition, the majority of our capital expenditures are 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 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 June 30, 2007, our current ratio was 2.2 to 1.0, as adjusted per current agreements, and our leverage ratio was 2.9 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 June 30, 2007. All amounts drawn under the Revolver are due and payable on July 7, 2009.

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 June 30, 2007. The revised principal balance of the Term Loan is due and payable on July 7, 2010.

Availability. Availability under the revolving line of credit was $184.0 million at June 30, 2007.

Cash Flows

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

	Six Months Ended June 30,
	2007			2006
	(In thousands)
Cash flows provided by operating activities	$	114,295		$	93,431
Cash flows used in investing activities		(165,764	)		(99,516	)
Cash flows provided by (used in) financing activities		458			(433	)
Net decrease in cash and cash equivalents	$	(51,011	)	$	(6,518	)

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 liquidity and capital used to finance our capital expenditures for the six months ended June 30, 2007.

Cash flows provided by operating activities increased by $20.9 million for the six months ended June 30, 2007 as compared to the same period for 2006. The increase in 2007 primarily resulted from higher oil and gas production in 2007. In addition, at June 30, 2007, we had a working capital deficit of $41.0 million. This deficit was largely caused by the decrease in our cash balance to fund capital expenditures, including property acquisitions. For the six months ended June 30, 2007, we incurred approximately $172.8 million in capital expenditures as compared to $101.8 million for the six months ended June 30, 2006.

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

Cash flows used in investing activities increased by $66.2 million for the six months ended June 30, 2007 as compared to the same period for 2006. During the six months ended June 30, 2007, we participated in the drilling of 94 gross wells and acquired the OPEX Properties.

Financing Activities. The primary driver of cash provided by or used in financing activities are equity transactions.

Cash flows provided by financing activities increased by $0.9 million as compared to the same period for 2006. The net increase is primarily related to an increase in the issuance of common stock and fewer repurchases of treasury stock. The repurchases of stock 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 six months ended June 30, 2007 increased by $71.0 million to $172.8 million, over the comparable period in 2006. Included in the current year capital expenditures is $38.7 million for the acquisition of the OPEX Properties. During the six months ended June 30, 2007, we participated in the drilling of 94 gross wells with the majority of these being in the Rocky Mountains and the Lobo regions. Our positive Operating Cash Flow, along with the availability under our revolving credit facility, are projected to be sufficient to fund our budgeted capital expenditures for 2007, which are currently projected to be $250.0 million. Currently, we are evaluating increasing our capital activity for the year.

Calpine Matters

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 and disputes regarding aspects of our relationship with Calpine which we will continue to closely monitor as the Calpine bankruptcy proceeds. Additionally, on June 29, 2007, Calpine filed an adversary proceeding against us seeking $400 million, plus interest as a result of alleged shortfall in value received for the assets involved in the Acquisition or in the alternative, a return of the domestic oil and gas assets sold to us by Calpine. See Part II. Item 1. Legal Proceedings for further information regarding the Calpine bankruptcy.

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.

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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 June 30, 2007. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 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 were 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.

PART II. Other Information

Item 1. Legal Proceedings

We and our subsidiaries are parties 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.

Calpine Bankruptcy

Calpine’s Lawsuit Against Rosetta

On June 29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy Court. The complaint alleges that our purchase of the domestic oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for bankruptcy, was completed when Calpine was insolvent and was for less than a reasonably equivalent value. Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for these assets which it estimates to be approximately $400 million dollars, plus interest, or (ii) in the alternative, return of the Assets from us. We believe that these allegations are wholly baseless, intend to vigorously defend against all claims made by Calpine and are further considering additional steps we may take to fully protect our interests. We continue to believe that it is unlikely that this challenge by the Calpine debtors to the fairness of the Acquisition will be successful upon ultimate disposition after appeals, if any. The deadline for us to answer or file our responsive pleading is September 10, 2007, and we have advised the Bankruptcy Court that we intend to file a motion to dismiss the complaint on or before the answer date. Calpine has requested a trial date in December 2007, but at the present time, no trial date has been set by the Bankruptcy Court.

Remaining Issues with Respect to the Acquisition

Separate from the Calpine lawsuit, Calpine has taken the position that 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”) are “executory contracts”, which Calpine may assume or reject. Following the July 7, 2005 closing of the Acquisition and as of the date of Calpine’s bankruptcy filing, there were open issues regarding legal title to certain properties included in the Purchase Agreement. On June 20, 2007, Calpine filed with the Bankruptcy Court its proposed Plan of Reorganization under Chapter 11 of the Bankruptcy Code, together with the accompanying Disclosure Statement, in which Calpine revealed it had not yet made a decision as to whether to assume or reject its remaining duties and obligations under the Purchase Agreement. If the Court were to determine that the Purchase Agreement is an executory contract, the various agreements entered into as part of the transaction constitute a single contract for purposes of assumption or rejection under the Bankruptcy Code, and we contend that Calpine cannot choose to assume certain of the agreements and to reject others. This issue may be contested by Calpine. If the Purchase Agreement is held to be executory, the deadline by when Calpine must exercise its decision to assume or reject the Purchase Agreement and the further duties and obligations required therein is the date on which Calpine’s Plan of Reorganization is confirmed.

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Open Issues Regarding Legal Title to Certain Properties

Under the Purchase Agreement, Calpine is required to resolve the open issues regarding legal title to certain properties. At the closing of the Acquisition on July 7, 2005, we retained approximately $75 million of the purchase price in respect to Non-Consent Properties identified by Calpine as requiring third-party consents or waivers of preferential rights to purchase that were not received by the parties before closing (“Non-Consent Properties”). Those Non-Consent Properties were therefore not included in the conveyances delivered at the closing. Subsequent analysis determined that a significant portion of the Non-Consent Properties did not require consents or waivers. For that portion of the Non-Consent Properties for which third-party consents were in fact required and for which either us or Calpine obtained the required consents or waivers, as well as for all Non-Consent Properties that did not require consents or waivers, we contend Calpine was and is obligated to have transferred to us the record title, free of any mortgages and other liens.

The approximate allocated value under the Purchase Agreement for the portion of the Non-Consent Properties subject to a third-party’s preferential right to purchase is $7.4 million. We have retained $7.1 million of the purchase price under the Purchase Agreement for the Non-Consent Properties subject to the third-party preferential right, and, in addition, a post-closing adjustment is required to credit us for approximately $0.3 million for a property which was transferred to us but, if necessary, will be transferred to the appropriate third party under its exercised preferential purchase right upon Calpine’s performance of its obligations under the Purchase Agreement.

We believe all conditions precedent for our receipt of record title, free of any mortgages or other liens, for substantially all of the Non-Consent Properties (excluding that portion of these properties subject to the third-party preferential right) were satisfied earlier, and certainly no later, than December 15, 2005, when we tendered once again the amounts necessary to conclude the settlement of the Non-Consent Properties.

We believe we are the equitable owner of each of the Non-Consent Properties for which Calpine was and is obligated to have transferred the record title and that such properties are not part of Calpine’s bankruptcy estate. Upon our receipt from Calpine of record title, free of any mortgages or other liens, to these Non-Consent Properties and further assurances required to eliminate any open issues on title to the remaining properties discussed below, we are prepared to pay Calpine approximately $68 million, subject to appropriate adjustment, if any. Our statement of operations for the six months ended June 30, 2007, the year ended December 31, 2006 and six months ended December 31, 2005, does not include any net revenues or production from any of the Non-Consent Properties, including those properties subject to preferential rights.

If Calpine does not provide us with record title, free of any mortgages for all of these properties and other liens, to any of the Non-Consent Properties (excluding that portion of these properties subject to a validly exercised third party’s preferential right to purchase), 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 also have approximately $7.1 million, previously withheld for that portion of the Non-Consent Properties subject to a third party’s preferential right to purchase, which will also be available for general corporate purposes, including for the purpose of acquiring additional properties should that third party properly exercise the preferential rights.

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 are seeking 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 (as a result of rejection of the Purchase Agreement or otherwise) 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 experiences 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 unlikely upon ultimate disposition including appeals, if any, then we could experience losses which could have a material adverse effect on our financial condition, statement of operations and cash flows.

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Sale of Natural Gas to Calpine

In addition, the issues involving legal title to certain properties, we executed, as part of the interrelated agreements that constitute the Purchase Agreement, certain natural gas supply agreements with Calpine Energy Services, L.P. (“CES”), which also filed for bankruptcy on December 20, 2005. During the period following Calpine’s filing for bankruptcy, CES 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 these various natural gas supply agreements. Although Calpine has indicated in a supplement to its recently proposed plan of reorganization that it intends to assume the CES natural gas supply agreements with us, we disagree that Calpine may assume anything less than the entire Purchase Agreement and intend to oppose any effort by Calpine to do less.

Calpine’s Marketing of the Company’s Production

Additionally, Calpine Producer Services, L.P. (“CPS”), which also filed for bankruptcy, entered into a Marketing and Services Agreement (“MSA”) with us as part of the interrelated agreements that constitute the Purchase Agreement. Under the MSA, CPS provided marketing and sales of our natural gas production to third-parties and charged us a fee. The MSA, however, expired by its terms on June 30, 2007. Through a recently executed letter agreement, we and CPS agreed to extend the MSA until September 30, 2007, subject to and to enable the parties to negotiate and execute a New Marketing and Services Agreement (“New MSA”). On August 3, 2007, as part of the Partial Transfer and Release Agreement, discussed in greater detail below, we and CPS concurrently executed the New MSA, which, if approved by the Bankruptcy Court, will be effective as of July 1, 2007 and extend CPS’ obligation to provide such services until June 30, 2009. The New MSA is subject to earlier termination by us upon the occurrence of certain events. In the interim, CPS is generally performing its obligations under the MSA.

Events Within Calpine’s Bankruptcy Case

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. The oil and gas leases identified in Calpine’s motion are, in large part, those properties with open issues in regards to their legal title in which Calpine contends it may possess some legal interest. According to this motion, Calpine filed it in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a bankruptcy code 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 could seek mediation to complete the following:

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

Resolution of the final amounts we are to pay Calpine, which we had at that time concluded was approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations. We are currently updating these calculations.

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

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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. In the event that Calpine elects to reject the Purchase Agreement or otherwise refuses to perform its remaining obligations therein, we anticipate we will be allowed to amend our proofs of claim to assert any additional damages we suffer as a result of the ultimate impact of Calpine’s refusal or failure to perform under the Purchase Agreement. In the bankruptcy, Calpine may elect to contest or dispute the amount of damages we seek in our proofs of claim. We will assert all right to offset any of our damages against any funds we possess that may be owed to Calpine. Until the allowed amount of our claims are finally established and the Bankruptcy Court issues its rulings with respect to Calpine’s plan confirmation, we can not predict what amounts we may recover from the Calpine bankruptcy should Calpine reject or refuse to perform 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 and the CSLC Leases respectively, these parties have further extended this deadline by stipulation. The deadline was first extended to January 31, 2007, 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, was further extended again to September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007 and more recently, October 31, 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.

On August 3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”) with Calpine, subject to Bankruptcy Court approval, resolving certain open issues without prejudice to Calpine’s avoidance action and, if the Court concludes the Purchase Agreement is executory, Calpine’s ability to assume or reject the Purchase Agreement. The principle terms are as follows:

We will extend our existing natural gas marketing agreement with Calpine until June 30, 2009. This agreement is subject to earlier termination right by us upon the occurrence of certain events;

Calpine will deliver to us documents that resolve title issues pertaining to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (“Properties”);

We will assume all Calpine's rights and obligations for an audit by the California State Lands Commission on part of the Properties; and

We will assume all rights and obligations for the Properties, including all plugging and abandonment liabilities.

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As a result of Calpine’s bankruptcy, there remains the possibility that there will be issues between us and Calpine that could amount to material contingencies in relation to the litigation filed by Calpine against us or 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 revenues).

Item 1A. Risk Factors

Other than with respect to the risk factors below, 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. The following risk factor was disclosed on form 10-K and has been updated as of June 30, 2007.

Calpine’s bankruptcy filing may adversely affect us in several respects.

Calpine, its creditors or interest holders may challenge the fairness of some or all of the Acquisition.

On June 29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy Court. The complaint alleges that the purchase by us of the domestic oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for $1.05 billion, prior to Calpine's declaring bankruptcy, was completed when Calpine was insolvent and was for less than reasonably equivalent value. Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for the Assets which it estimates to be approximately $400 million dollars, plus interest, or (ii) in the alternative, return of the Assets from us. We deny and intend to vigorously defend against all claims made by Calpine, and we are considering additional steps we may take to fully protect our interests. Our deadline to file our responsive pleading or answer is September 10, 2007, and the trial has not yet been scheduled. If after a trial on the merits, the Bankruptcy Court was to determine that the Debtors have met their burden of proof, it could void the transfer or take other actions against us, including (i) setting aside the Acquisition and returning our purchase price and give us a first lien on all the properties and assets we purchased in the Acquisition or (ii) sustaining the Acquisition subject to our being required to pay the Debtors the amount, if any, by which the fair value of the business transferred, as determined by the Bankruptcy Court as of July 7, 2005, exceeded the purchase price determined and paid in July 2005. If the Bankruptcy Court should set aside the Acquisition, it would have a material adverse effect upon our results of operation and financial condition in that substantially all our properties conveyed at the time of the Acquisition would be returned to Calpine, subject to our right (as a good faith transferee) to retain a lien in our favor to secure the return of the purchase price we paid for the properties. Additionally, if the Bankruptcy Court should so rule, any requirement to pay an increased purchase price could have a material adverse effect upon our results of operation and financial condition depending on the amount we might be required to pay. See Item 1. Legal Proceedings for further information regarding the Calpine bankruptcy.

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 receive under the Purchase Agreement.

On June 20, 2007, Calpine filed with the Bankruptcy Court its proposed plan of reorganization and disclosure statement. In the disclosure statement, Calpine revealed that it had not yet made a decision on whether to assume or reject its remaining obligations and duties under the Purchase and Sale Agreement and interrelated agreements, which set forth the terms and agreements related to Calpine’s sale of its oil and gas assets to us. In its proposed supplement to the plan filed on the same date, however, Calpine indicated its desire to assume the NAESB agreement under which we sell gas to Calpine and the CPS Marketing Agreement under which CPS sells our production to third parties on our behalf. We contend that all of the transaction documents constitute one agreement and must therefore be assumed or rejected in their entirety as one agreement and will vigorously oppose any effort by Calpine to treat any aspect of the transaction as a stand-alone document.

Although Calpine has not made its election to assume or reject the Purchase Agreement, on August 3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”) with Calpine, subject to Bankruptcy Court approval, without prejudice to the other pending claims, disputes, and defenses between Calpine and us. As part of the PTRA, we agreed to extend the CPS marketing agreement by two years, until June 30, 2009; however, the marketing agreement is subject to earlier termination by us upon the occurrence of certain events. In return, Calpine has provided documents to resolve legal title issues as to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (“Properties”). Under the PTRA, we have also agreed to assume all liabilities with respect to those Properties, such as plugging and abandonment, as well as all liabilities and rights associated with any under- or over-payment to the State of California as it relates to certain state land. We anticipate that the Bankruptcy Court will address Calpine’s to-be-filed request for approval of the PTRA in a hearing scheduled for September 11, 2007. If the Bankruptcy Court does not approve the PTRA, our New Marketing and Services Agreement will not take effect, and we will discontinue using Calpine Producer Services, L.P. to market and sell our gas. Further, we will argue that the liabilities we were to assume under the PTRA will remain obligations of Calpine. We will continue our efforts to resolve open issues in regard to legal title of the properties; however, if Calpine were also to refuse to perform under the Purchase Agreement and the Bankruptcy Court were to rule against certain legal arguments we would raise such that the resolution of open issues involving legal title on any remaining properties (including any leases) does not occur, the portion of the purchase price we held back pending consent or waiver will be retained and will be available to us for general corporate purposes.

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The bankruptcy proceeding may prevent, frustrate or delay our ability to receive corrective documentation from Calpine for certain properties that we bought from Calpine and paid for, in cases where Calpine delivered incomplete documentation, including documentation related to certain ministerial governmental approvals.

Certain of the properties we purchased from Calpine and paid Calpine for on July 7, 2005, require certain additional documentation, depending on the particular facts and circumstances surrounding the particular properties involved, such documentation was to be delivered by Calpine to quiet title related to our ownership of these properties following closing. Certain of these properties are subject to ministerial governmental action approving us as qualified assignee and operator, even though in most cases there had been a conveyance by Calpine and release of mortgages and liens by Calpine’s creditors. For certain other properties, the documentation delivered by Calpine at closing was incomplete. While Calpine has not made a decision on whether to perform its remaining obligations under the Purchase Agreement with us and thus perform these required further assurances as to title, Calpine has agreed to resolve title issues on a significant number of those properties requiring the additional documentation to address title issues. As noted, we reached agreement with Calpine upon and executed the PTRA on August 3, 2007, subject to Bankruptcy Court approval, without prejudice to the other pending claims, disputes and defenses between them. Among other obligations and rights of the parties under PTRA, Calpine has provided documents to resolve legal title issues as to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (“Properties”). We anticipate that the Bankruptcy Court will address Calpine’s to-be-filed request for approval of the PTRA in a hearing scheduled for September 11, 2007. The PTRA does not address the Non-Consent Properties which Calpine withheld from the July 2005 closing due to lack of lessor consents determined at that time (in many instances mistakenly) as needed for transfer and for which we withheld approximately $75 million of the purchase price.

We have expended and may continue to expend significant resources in connection with Calpine’s bankruptcy.

We have expended and may continue to expend significant resources in connection with Calpine’s bankruptcy. These resources include our increased costs for lawyers, consultant experts and related expenses, as well as lost opportunity costs associated with our dedicating internal resources to these matters. If we continue to expend significant resources and our management is distracted from the operational matters by the Calpine bankruptcy, our business, results of operations, financial position or cash flows could be adversely affected.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended June 30, 2007



					Total Number of		Maximum Number (or
					Shares Purchased		Approximate Dollar Value)
					as Part of Publicly		of Shares that May yet Be
	Total Number of		Average Price		Announced Plans		Purchased Under the Plans
Period	Shares Purchased (1)		Paid per Share		or Programs		or Programs
April 1 - April 30		82	$	22.07		-		-
May 1 - May 31		1,413		23.01		-		-
June 1 - June 30		835		24.35		-		-

(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.

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Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Submission of Matters to a Vote of Security Holders

On May 15, 2007, we held our Annual Meeting of Shareholders. At the meeting, shareholders voted on election of all of our directors to serve until the next annual meeting of shareholders. The following is a summary of the votes on this item:

	Votes For	Votes Withheld
B.A. "Bill" Berilgen (1)	46,354,693	771,204
Richard W. Beckler	44,417,081	2,708,316
Donald D. Patteson, Jr.	46,269,282	856,615
D. Henry Houston (1)	44,415,131	2,708,516
G. Louis Graziadio, III	37,861,923	9,263,474
Josiah O. Low, III	46,416,241	709,156

(1) In July 2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen resigned. The Company’s Executive Vice President, Charles F. Chambers, is serving as acting President and CEO. D. Henry Houston, chair of our Audit Committee and current director, has been named Chairman of the Board and will lead the Board in the search for a permanent President and CEO. We have not filled the vacancy on the Board caused by Mr. Berilgen’s resignation.

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 Charles F. Chambers 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 Charles F. Chambers 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: August 13, 2007

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ROSETTA RESOURCES INC.

EXHIBIT INDEX

Exhibit Number		Description
31.1		Certification of Periodic Financial Reports by Charles F. Chambers 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 Charles F. Chambers and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350