Edgar Filing: Rosetta Resources Inc.

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended September 30, 2007

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

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T 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 T

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

The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of November 1, 2007 was 50,891,280.

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Part I –	Financial Information
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 3. Quantitative and Qualitative Disclosures About Market Risk	24
	Item 4. Controls and Procedures	24
Part II –	Other Information
	Item 1. Legal Proceedings	24
	Item 1A. Risk Factors	28
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	29
	Item 3. Defaults Upon Senior Securities	30
	Item 4. Submission of Matters to a Vote of Security Holders	30
	Item 5. Other Information	30
	Item 6. Exhibits	31
Signatures		32
Exhibit Index		33
Rule 13a-14(a) Certification executed by Randy L. Limbacher
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)

	September 30, 2007			December 31, 2006
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	13,656		$	62,780
Accounts receivable		36,324			36,408
Derivative instruments		7,271			20,538
Prepaid expenses		18,986			8,761
Other current assets		4,157			2,965
Total current assets		80,394			131,452
Oil and natural gas properties, full cost method, of which $46.3 million at September 30, 2007 and $37.8 million at December 31, 2006 were excluded from amortization		1,481,033			1,223,337
Other fixed assets		5,978			4,562
		1,487,011			1,227,899
Accumulated depreciation, depletion, and amortization		(248,396	)		(145,289	)
Total property and equipment, net		1,238,615			1,082,610
Deferred loan fees		2,490			3,375
Other assets		1,426			1,968
Total other assets		3,916			5,343
Total assets	$	1,322,925		$	1,219,405

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	35,307		$	23,040
Accrued liabilities		57,773			43,099
Royalties payable		14,925			9,010
Prepayment on gas sales		16,678			17,868
Deferred income taxes		2,741			7,743
Total current liabilities		127,424			100,760
Long-term liabilities:
Derivative instruments		12,052			11,014
Long-term debt		250,000			240,000
Asset retirement obligation		17,437			10,253
Deferred income taxes		58,778			35,089
Total liabilities		465,691			397,116
Commitments and contingencies (Note 8)
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 50,525,323 shares and 50,405,794 shares at September 30, 2007 and December 31, 2006, respectively		50			50
Additional paid-in capital		760,004			755,343
Treasury stock, at cost; 105,436 and 85,788 shares at September 30, 2007 and December 31, 2006, respectively		(1,973	)		(1,562	)
Accumulated other comprehensive (loss) income		(2,785	)		6,315
Retained earnings		101,938			62,143
Total stockholders' equity		857,234			822,289
Total liabilities and stockholders' equity	$	1,322,925		$	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 September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenues:
Natural gas sales	$	79,061		$	61,366		$	225,658		$	171,783
Oil sales		10,657			9,831			26,730			27,339
Total revenues		89,718			71,197			252,388			199,122
Operating Costs and Expenses:
Lease operating expense		11,912			9,449			33,274			27,330
Depreciation, depletion, and amortization		38,186			27,906			105,079			77,574
Treating and transportation		1,412			317			3,057			2,043
Marketing fees		518			526			1,850			1,634
Production taxes		1,243			2,153			3,428			5,476
General and administrative costs		12,032			8,316			29,999			24,645
Total operating costs and expenses		65,303			48,667			176,687			138,702
Operating income		24,415			22,530			75,701			60,420

Other (income) expense
Interest expense, net of interest capitalized		4,332			4,557			13,382			13,060
Interest income		(240	)		(1,099	)		(1,469	)		(3,351	)
Other (income) expense, net		(105	)		(171	)		(287	)		6
Total other expense		3,987			3,287			11,626			9,715

Income before provision for income taxes		20,428			19,243			64,075			50,705
Provision for income taxes		7,715			7,321			24,280			19,293
Net income	$	12,713		$	11,922		$	39,795		$	31,412

Earnings per share:
Basic	$	0.25		$	0.24		$	0.79		$	0.63
Diluted	$	0.25		$	0.24		$	0.79		$	0.62

Weighted average shares outstanding:
Basic		50,409			50,282			50,363			50,211
Diluted		50,570			50,426			50,572			50,384

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)

	Nine Months Ended September 30,
	2007			2006
Cash flows from operating activities
Net income	$	39,795		$	31,412
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		105,079			77,574
Deferred income taxes		24,195			18,991
Amortization of deferred loan fees recorded as interest expense		885			885
Income from unconsolidated investments		(117	)		(168	)
Stock compensation expense		4,090			4,348
Change in operating assets and liabilities:
Accounts receivable		84			5,300
Income taxes receivable		-			6,000
Prepaid expenses		(10,225	)		605
Other current assets		(1,192	)		(890	)
Other assets		331			1,355
Accounts payable		12,267			2,494
Accrued liabilities		3,636			(324	)
Royalties payable		4,725			(5,961	)
Net cash provided by operating activities		183,553			141,621
Cash flows from investing activities
Acquisition of oil and gas properties		(38,656	)		(11,587	)
Purchases of property and equipment		(205,310	)		(135,656	)
Disposals of property and equipment		1,104			36
Increase in restricted cash		-			(15,000	)
Other		25			46
Net cash used in investing activities		(242,837	)		(162,161	)
Cash flows from financing activities
Borrowing from revolving credit facility		10,000			-
Equity offering transaction fees		-			268
Proceeds from issuances of common stock		571			515
Stock-based compensation excess tax benefit		-			302
Purchases of treasury stock		(411	)		(1,526	)
Net cash provided by (used in) financing activities		10,160			(441	)

Net decrease in cash		(49,124	)		(20,981	)
Cash and cash equivalents, beginning of period		62,780			99,724
Cash and cash equivalents, end of period	$	13,656		$	78,743

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	6,900		$	3,783
Accrued purchase price adjustment		-			11,400

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. and Rosetta Resources California, LLC, Rosetta Resources Rockies, LLC, Rosetta Resources Offshore, LLC and Rosetta Resources Texas LP and its partners 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 September 30, 2007 and December 31, 2006 and for the three and nine months ended September 30, 2007 and 2006 contain the accounts of the Company 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 does not expect the adoption of SFAS No. 159 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157,“Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Company is currently evaluating the potential impact of this standard.

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”). FIN 48 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 50% 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:

	September 30, 2007			December 31, 2006
	(In thousands)
Proved properties	$	1,407,080		$	1,167,588
Unproved/unevaluated properties		46,322			37,813
Gas gathering systems and compressor stations		27,631			17,936
Other		5,978			4,562
Total oil and natural gas properties		1,487,011			1,227,899
Less: Accumulated depreciation, depletion, and amortization		(248,396	)		(145,289	)
Total property and equipment, net	$	1,238,615		$	1,082,610

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.0 million and $3.4 million of internal costs for the three and nine months ended September 30, 2007, respectively, and $0.9 million and $2.6 million for the three and nine months ended September 30, 2006, respectively.

Included in the Company’s oil and gas properties are asset retirement costs of $19.9 million and $9.6 million as of September 30, 2007 and December 31, 2006, respectively.

Oil and gas properties include costs of $46.3 million and $37.8 million at September 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 Water regions.

The Company’s ceiling test computation was calculated using hedge adjusted market prices at September 30, 2007, which were based on a Henry Hub price of $6.38 per MMBtu and a West Texas Intermediate oil price of $82.88 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at September 30, 2007 increased the calculated ceiling value by approximately $28.9 million (net of tax). There was no write-down for the three and nine months ended September 30, 2007. Had the effects of the Company's cash flow hedges not been considered in calculating the ceiling limitation, the impairment as of September 30, 2007 would have been approximaely $20.2 million, net of tax. 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.

(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. In the third quarter of 2007, the Company entered into additional 5,000 MMBtu per day of financial fixed price swaps with an average underlying price of $8.10 per MMBtu covering a portion of the Company’s 2009 production. The Company also entered into 5,000 MMBtu per day of basis swaps covering a portion of the Company’s 2008 production. The basis swap requires the Company to pay Natural Gas Intelligence (“NGI”) PG&E Citygate Index on notional volumes equal to 5,000 MMBtu per day for calendar year 2008. The counterparty will pay the float price of the last trade day settlement of the corresponding forward month contract settlement of the NYMEX Henry Hub index minus $0.185. When combined with existing NYMEX Henry Hub fixed price swaps, this effectively creates a fixed price swap that settles at PG&E Citygate Index and establishes a fixed price of $8.20 per MMBtu for 5,000 MMBtu per day for 2008.

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 September 30, 2007:

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Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu	Total of Notional Volume MMBtu	Average Underlying Prices MMBtu	Total of Proved Natural Gas Production Hedged (1)	Fair Market Value Gain/(Loss) (In thousands)
2007	Swap	Cash flow	55,316	5,089,100	7.80	45%		5,363
2008	Swap	Cash flow	54,909	20,096,616	7.64	48%		(386)
2009	Swap	Cash flow	31,141	11,366,465	7.17	31%		(10,106)
				36,552,181			$	(5,129)

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

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 September 30, 2007:

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

2007	Costless Collar	Cash flow	10,000		920,000	$	7.19	$	10.03	8%	$	658
					920,000						$	658

(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 September 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 September 30,				Nine Months Ended September 30,
Natural Gas	2007		2006		2007		2006
Quantity settled (MMBtu)		6,009,100		5,060,000		17,750,400		15,015,000
Increase in natural gas sales revenue (In thousands)	$	10,333	$	9,114	$	17,810	$	19,804

The Company expects to reclassify gains of $4.5 million based on market pricing as of September 30, 2007 to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.

At September 30, 2007, the Company had derivative assets of $7.6 million on the Consolidated Balance Sheet, of which $0.3 million was classified as other assets. The Company also had derivative liabilities of $12.1 million which was included in long-term liabilities on the Consolidated Balance Sheet at September 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 September 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 nine months ended September 30, 2007 and 2006.

(5)

Asset Retirement Obligation

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

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	Nine Months Ended September 30, 2007
	(In thousands)
ARO as of January 1, 2007	$	10,689
Revision of previous estimates		8,610
Liabilities incurred during period		1,677
Accretion expense		1,035
ARO as of September 30, 2007	$	22,011

Of the total ARO, approximately $4.6 million is classified as a current liability included in accrued liabilities on the Consolidated Balance Sheet at September 30, 2007.

(6)

Long-Term Debt

The Company’s credit facilities consist of a four-year senior secured revolving line of credit (“Revolver”) 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.

In the third quarter of 2007, the Company increased their borrowings against the Revolver by $10.0 million. As of September 30, 2007, the Company had total outstanding borrowings and letters of credit of $250.0 million and $1.0 million, respectively. Net borrowing availability under the Revolver was $174.0 million at September 30, 2007. The Company was in compliance with all covenants at September 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 Taxes

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 September 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 September 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 commenced an adversary proceeding against the Company in the Bankruptcy Court (the “Lawsuit”). The complaint alleges that the purchase by the Company of the domestic oil and natural gas business 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, plus interest, or (ii) in the alternative, return of the Assets from the Company. The Company believes that the allegations in the Lawsuit are wholly baseless, and the Company continues to believe that it is unlikely that this challenge by Calpine to the fairness of the Acquisition will be successful upon the ultimate disposition of the Lawsuit or, if necessary, in the appellate courts. The Official Committee of Equity Security Holders and the Official Committee of the Unsecured Creditors have both intervened in the Lawsuit for the stated purpose of monitoring the proceedings because the committees claim to have an interest in the Lawsuit, which the Company disputes because creditors are likely to be paid in full under Calpine’s plan of reorganization ("Plan of Reorganization") without regard to the Lawsuit and equity holders have no interest in fraudulent conveyance actions.

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On September 10, 2007, the Company filed a motion to dismiss the complaint or, in the alternative, to stay the adversary proceeding. The Bankruptcy Court conducted a hearing upon the Company’s motion on October 24, 2007. Following the hearing, the Bankruptcy Court denied the Company’s motion on the basis that certain issues raised by the Company’s motion were premature as the bankruptcy process had not yet established how much Calpine’s creditors would receive. The Company filed its answer and counterclaims against Calpine on November 5, 2007. The parties are targeting completing discovery in the Lawsuit in March 2008. The Bankruptcy Court has not set a trial date.

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 September 25, 2007, the Bankruptcy Court approved Calpine’s Disclosure Statement accompanying its proposed Plan of Reorganization under Chapter 11 of the Bankruptcy Code, 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. The Company may contend that the Purchase Agreement is not an executory contract which Calpine may choose to reject. If the Court were to determine that the Purchase Agreement is an executory contract, the Company contends 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.

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 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 the Company 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 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 (excluding that portion of these properties subject to a validly exercised third party’s preferential right to purchase) 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 three and nine months ended September 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.

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On September 11, 2007, the Bankruptcy Court entered an order approving that certain Partial Transfer and Release Agreement (“PTRA”) negotiated by and between the Company and Calpine which, among other things, resolves issues in regard to title of certain of the other oil and natural gas properties the Company purchased from Calpine in the Acquisition and for which payment was made to Calpine on July 7, 2005, and extends the Marketing and Services Agreement (“MSA”) with Calpine Producer Services, L.P. (“CPS”). The additional documentation received from Calpine under the PTRA eliminates open issues in the Company’s title and resolves any issues as to the clarity of the Company’s ownership in certain properties located in the Gulf of Mexico, California, and Wyoming (the “PTRA Properties”), including all oil and gas properties requiring ministerial approvals, such as leases with the U.S. Minerals Management Service (“MMS”), California State Lands Commission (“CSLC”) and U.S. Bureau of Land Management (“BLM”). However, the PTRA was executed without prejudice to Calpine’s fraudulent conveyance action or its right, if any, to reject the Purchase Agreement, and the Company’s rights and legal arguments in relation thereto. The PTRA did not address or resolve open issues with respect to the Non-Consent Properties and certain other properties.

The Company recorded the conveyances of those PTRA Properties in California not requiring governmental agency approval. On October 30, 2007, the CSLC approved the assignment of the State of California leases and rights of way to the Company from Calpine. The Company is still awaiting the ministerial approval from the MMS and BLM for the assignment of Calpine’s interests in these PTRA Properties to the Company.

Notwithstanding the PTRA, as a result of Calpine’s bankruptcy filing, it remains uncertain as to whether Calpine will respond cooperatively as to the remaining outstanding issues under the Purchase Agreement. 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 remaining issues whether under the Purchase Agreement or the PTRA, 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 or cash flows.

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

As part of the PTRA, the Company entered into the MSA with CPS, effective July 1, 2007, which was approved by the Bankruptcy Court on September 11, 2007. Under the MSA, CPS provides marketing and related services in relation to the sales of our natural gas production and charges the Company a fee. This MSA extends CPS’ obligations to provide such services until June 30, 2009. The MSA is subject to early termination by the Company upon the occurrence of certain events.

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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 its pending bankruptcy proceeding 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 that Calpine’s motion 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 MMS 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

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 (excluding that portion of these properties subject to a validly exercised third party’s preferential right to purchase) and approximately $11 million in other true-up payment obligations. The Company is currently updating these calculations with respect to the final amounts, if any, the Company is to pay Calpine.

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 CSLC 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 MMS) (the “MMS Oil and Gas Leases”) and the State of California (and managed by the CSLC) (the “CSLC Leases”). Calpine, 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 have not presently been 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 rights 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 cannot predict what amounts it may recover from the Calpine bankruptcy should Calpine reject or refuse to perform under the Purchase Agreement.

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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. The MMS Oil and Gas Leases and CSLC Leases were included in the PTRA that was approved by the Bankruptcy Court on September 11, 2007, with the result that there is no further need for the parties to contest whether the MMS Oil and Gas Leases and the CLSC Leases are appropriate for inclusion in Calpine’s 365 motion. The PTRA approved by the Bankruptcy Court, among other things, resolves open issues in regard to the Company’s title to ownership of all of the unexpired MMS Oil and Gas Leases and the CLSC Leases. However, the PTRA was executed without prejudice to Calpine’s fraudulent conveyance action or its rights, if any, to reject the purchase agreement and the Company’s rights and legal arguments in relation thereto.

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. The Court has scheduled the confirmation hearing on Calpine’s proposed plan to commence on December 18, 2007 and continue through December 27, 2007.

On August 3, 2007, the Company and Calpine executed the PTRA 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 the MSA with CPS until June 30, 2009, effective as of July 1, 2007. This agreement is subject to earlier termination rights by the Company upon the occurrence of certain events;

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

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.

On September 11, 2007, the Bankruptcy Court approved the PTRA. The PTRA did not resolve the open issues on the Non-Consent Properties and certain other properties.

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.

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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 on two sites in California and correspondingly, recorded a liability, which at September 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 and negotiations 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 September 30, 2007 or December 31, 2006 as the study is still in the preliminary stage.

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Comprehensive Income

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

	Three Months Ended September 30,												Nine Months Ended September 30,

	2007						2006						2007						2006
	(In thousands)												(In thousands)
Accumulated other comprehensive (loss) income beginning of period				$	(8,636	)				$	(11,852	)				$	6,315					$	(50,731	)
Net income	$	12,713					$	11,922					$	39,795					$	31,412

Change in fair value of derivative hedging instruments		19,723						45,638						3,202						119,036
Hedge settlements reclassed to income		(10,333	)					(9,114	)					(17,810	)					(19,804	)
Tax effect related to hedges		(3,539	)					(13,880	)					5,508						(37,709	)
Total other comprehensive income (loss)		5,851			5,851			22,644			22,644			(9,100	)		(9,100	)		61,523			61,523

Comprehensive income		18,564						34,566						30,695						92,935
Accumulated other comprehensive (loss) income				$	(2,785	)				$	10,792					$	(2,785	)				$	10,792

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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 outstanding common stock awards and stock options were exercised at the end of the period.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(In thousands)
Basic weighted average number of shares outstanding		50,409		50,282		50,363		50,211
Dilution effect of stock option and awards at the end of the period		161		144		209		173
Diluted weighted average number of shares outstanding		50,570		50,426		50,572		50,384

Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect		415		179		403		229

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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.

Oil and Natural Gas Revenue

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007 (1)		2006 (1)		2007 (1)		2006 (1)
	(In thousands)
California	$	22,110	$	18,820	$	77,705	$	54,921
Rocky Mountains		2,463		591		6,749		1,555
Mid-Continent		494		596		1,851		1,506
Gulf of Mexico		11,573		6,172		27,954		22,093
Lobo		30,792		21,009		84,059		50,090
Perdido		5,951		4,939		19,289		21,722
State Waters		529		1,750		2,176		7,039
Other Onshore		5,473		8,206		14,795		20,392
Total revenue excluding hedges	$	79,385	$	62,083	$	234,578	$	179,318

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Excludes the effects of hedging of $10.3 million and $9.1 million for the three months ended September 30, 2007 and 2006, respectively, and $17.8 million and $19.8 million for the nine months ended September 30, 2007 and 2006, respectively.

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Oil and Natural Gas Properties

	September 30, 2007		December 31, 2006
	(In thousands)
California	$	517,358	$	435,167
Rocky Mountains		68,411		44,455
Mid-Continent		14,678		9,584
Gulf of Mexico		154,447		125,425
Lobo		491,358		426,348
Perdido		69,762		52,702
State Waters		50,594		26,922
Other Onshore		114,425		102,734
Other		5,978		4,562
Total property and equipment	$	1,487,011	$	1,227,899

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Subsequent Events

New CEO

In July 2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen resigned. As a result of the resignation, the Company entered into a separation agreement with B.A. Berilgen that included a payment of $3.0 million. The Company’s Executive Vice President, Charles F. Chambers, served as acting President and CEO, until October 31, 2007, when he resumed his former position as the Company’s Executive Vice President, Corporate Development. On November 1, 2007, Randy L. Limbacher became President and CEO of the Company. Randy L. Limbacher has also been appointed to serve as a member of the Company’s Board of Directors. D. Henry Houston, chair of the Company’s Audit Committee and current director, was named Non-Executive Chairman of the Board.

Commodity Hedge Contracts

Since September 30, 2007, the Company has entered into an additional 10,000 MMBtu per day of financial fixed price swaps for 2008 at an average underlying price of $8.29 and an additional 11,000 MMBtu per day of financial fixed price swaps for 2009 at an average underlying price of $8.40. The Company also entered into a basis swap for November and December of 2007 for 5,000 MMBtu per day. When combined with existing NYMEX Fixed Price swaps of 5,000 MMBtu per day, establishes a fixed price of $8.00 for a portion of the Company's production for November and December of 2007.

Interest Rate Swaps

Since September 30, 2007, the Company has entered into two interest rate swaps. The swaps were entered into to establish a fixed interest rate for a portion of the Company's debt outstanding starting November 1, 2007 and ending June 30, 2009. The notional amount under the swaps is $50,000,000 with an average fixed interest rate of 4.55%.

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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, 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 nine months ended September 30, 2007 compared to the three and nine months ended September 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, as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations, disclosures regarding critical accounting policies

We continue to execute our strategy to increase value per share. The following summarizes our performance for the first nine months of 2007 as compared to the same period for 2006:

·	Production on an equivalent basis increased 32%;

·	The average revenue price, including the effects of hedging, decreased $0.32 per Mcfe or 3.9%;

·	Total revenue, including the effects of hedging, increased $53.3 million or 27%;

·	Net income increased $8.4 million or 27%;

·	Diluted earnings per share increased $0.17 or 27%;

·	Capital expenditures increased by $99.9 million or 66% including acquisitions of oil and natural gas properties; and

·	Drilled 149 gross wells with a success rate of 81%.

We have significantly grown our oil and natural gas production operations since we acquired Calpine Natural Gas L.P. and its affiliates in July 2005 (the “Acquisition”), and management believes we have the ability to continue growing production by drilling identified locations on our current existing leases.

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.

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. In the third quarter of 2007, we entered into additional 5,000 MMBtu per day of financial fixed price swaps with an average underlying price of $8.10 per MMBtu covering a portion of our 2009 production. We also entered into 5,000 MMBtu per day of basis swaps covering a portion of our 2008 production. The basis swap requires us to pay Natural Gas Intelligence (“NGI”) PG&E Citygate Index on notional volumes equal to 5,000 MMBtu per day for calendar year 2008. The counterparty will pay the float price of the last trade day settlement of the corresponding forward month contract settlement of the NYMEX Henry Hub index minus $0.185. When combined with existing NYMEX Henry Hub fixed price swaps, this effectively creates a fixed price swap that settles at PG&E Citygate Index and establishes a fixed price of $8.20 per MMBtu for 5,000 MMBtu per day for 2008.

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 September 30, 2007, which were based on a Henry Hub price of $6.38 per MMBtu and a West Texas Intermediate oil price of $82.88 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at September 30, 2007 increased the calculated ceiling value by approximately $28.9 million (net of tax). There was no write-down recorded at September 30, 2007. Had the effects of our cash flow hedges not been considered in calculating the ceiling limitation, the impairment as of September 30, 2007 would have been approximately $20.2 million, net of tax. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a write-down could occur.

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Recent Accounting Developments

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

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 nine months of 2007 was $252.4 million which is an increase of $53.3 million, or 27%, from the nine months ended September 30, 2006. Approximately 89% of revenue was attributable to natural gas sales on total volumes of 32.2 Bcfe.

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2007		2006		% Change Increase/ (Decrease)			2007		2006		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Total revenues	$	89,718	$	71,197		26	%	$	252,388	$	199,122		27	%

Production:
Gas (Bcf)		10.7		7.9		35	%		29.7		21.9		36	%
Oil (MBbls)		141.4		143.5		(1	%)		410.7		414.3		(1	%)
Total Equivalents (Bcfe)		11.6		8.7		33	%		32.2		24.4		32	%

$ per unit:
Avg. Gas Price per Mcf	$	7.39	$	7.77		(5	%)	$	7.60	$	7.84		(3	%)
Avg. Gas Price per Mcf excluding Hedging		6.42		6.61		(3	%)		7.00		6.94		1	%
Avg. Oil Price per Bbl		75.37		68.51		10	%		65.08		65.99		(1	%)
Avg. Revenue per Mcfe including hedges		7.73		8.18		(6	%)		7.84		8.16		(4	%)

Natural Gas. For the three months ended September 30, 2007, natural gas revenue increased by $17.7 million, including the realized impact of derivative instruments, from the comparable period in 2006, to $79.1 million. This increase is primarily due to an increase in the number of wells producing in 2007 as compared to 2006 as well as an increase in production volumes in California, which includes the acquisition of the OPEX properties in the second quarter of 2007, the Rocky Mountains, Offshore and Lobo regions. The effect of gas hedging activities on natural gas revenue for the three months ended September 30, 2007 was a gain of $10.3 million as compared to a gain of $9.1 million for the three months ended September 30, 2006.

For the nine months ended September 30, 2007, natural gas revenue increased to $225.7 million from $171.8 million for the comparable period in 2006. This increase of $53.9 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 California, which includes the acquisition of the OPEX properties in the second quarter of 2007, the Rocky Mountains, Offshore and Lobo regions. The 2007 realized average natural gas price was $7.60 per Mcf as compared to $7.84 per Mcf for 2006. The effect of gas hedging activities on natural gas revenue for the nine months ended September 30, 2007 was a gain of $17.8 million as compared to a gain of $19.8 million for the nine months ended September 30, 2006.

Crude Oil. For the three months ended September 30, 2007, oil revenue was $10.7 million as compared to $9.8 million for the same period in 2006. This increase is attributable to the average realized price increase of $6.86 per Bbl from $68.51 per Bbl for the three months ended September 30, 2006 to $75.37 per Bbl for the three months ended September 30, 2007. The oil production volumes were 141.4 MBbls which is comparable to the same period in 2006.

For the nine months ended September 30, 2007, oil revenue decreased by $0.6 million due to the decrease in the average realized oil price of $0.91 per Bbl from $65.99 per Bbl to $65.08 per Bbl. The oil production volumes were 410.7 MBbls which is comparable to the same period in 2006.

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Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2007		2006		% Change Increase/ (Decrease)			2007		2006		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	11,912	$	9,449		26	%	$	33,274	$	27,330		22	%
Depreciation, depletion and amortization		38,186		27,906		37	%		105,079		77,574		35	%
General and administrative costs		12,032		8,316		45	%		29,999		24,645		22	%

$ per unit:
Avg. lease operating expense per Mcfe	$	1.03	$	1.09		(6	%)	$	1.03	$	1.12		(8	%)
Avg. DD&A per Mcfe		3.29		3.21		2	%		3.26		3.18		3	%
Avg. G&A per Mcfe		1.04		0.96		8	%		0.93		1.01		(8	%)

Our operating expenses are primarily related to the following items:

Lease Operating Expense. Lease operating expense increased $2.5 million for the three months ended September 30, 2007 as compared to the three months ended September 30, 2006. The overall increase is due to a $3.0 million increase in direct lease operating expense offset by a $0.5 million decrease in workover expense. The increase in direct lease operating expense is due to the increase in production of 33% which contributed to higher costs for equipment rentals and costs associated with non-operated properties. The decrease in workover expense due to the insurance reimbursement of $2.4 million for claims submitted as a result of Hurricane Rita. The average lease operating expense decreased to $1.03 per Mcfe for the three months ended September 30, 2007 from $1.09 per Mcfe for the three months ended September 30, 2006.

Lease operating expense increased $5.9 million for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006. This overall increase is primarily due to an increase in ad valorem tax related to property appraisals in California. In addition, the increase in production of 32% for 2007 contributed to higher costs for equipment rentals, maintenance and repairs, and costs associated with non-operated properties. The overall increase was offset by a $1.1 million decrease in workover expense primarily due to the insurance reimbursement of $2.4 million for claims submitted as a result of Hurricane Rita and a decrease of $1.2 million in expense incurred in 2006 associated with the offshore region that was not incurred in 2007.

Depreciation, Depletion, and Amortization. Depreciation, depletion and amortization expense increased $10.3 million for the three months ended September 30, 2007 as compared to the three months ended September 30, 2006. The increase is due to a 33% increase in total production and a higher depletion rate for 2007 as compared to 2006. The depletion rate for the third quarter of 2007 was $3.20 per Mcfe while the rate for the third quarter of 2006 was $3.13 per Mcfe.

Depreciation, depletion and amortization expense increased $27.5 million for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006. The increase is due to a 32% 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 $3.17 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 $3.7 million for the three months ended September 30, 2007 as compared to the three months ended September 30, 2006. This increase is primarily associated with the severance expense of $3.0 million with the former CEO as well as an increase in legal fees associated with the Calpine litigation.

General and administrative costs increased by $5.4 million for the nine months ended September 30, 2007 as compared to the nine months ended September 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 incurred in the current period are primarily associated with the severance expense of $3.0 million with the former CEO, legal fees associated with the Calpine litigation, payroll expenses and costs associated with the first year implementation of Section 404 of the Sarbanes-Oxley Act.

Total Other Expense

Other expense includes interest expense, interest income and other income/expense, net which increased $0.7 million and $1.9 million for the three and nine months ended September 30, 2007, respectively, as compared to the respective periods in 2006. The increase in other expense is the result of reduced interest income in 2007 to offset interest expense as compared to 2006. The interest income is earned on the cash balances, which were greater during the quarter ended September 30, 2006 versus September 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 three months ended September 30, 2007 and 2006 was 37.8% and 38.0%, respectively. The effective tax rate for the nine months ended September 30, 2007 was 37.9%, which is comparable to the tax rate for the nine months ended September 30, 2006 of 38.0%. 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. In July 2005, BNP Paribas 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. In addition, in the third quarter of 2007, we increased our borrowings against the Revolver by $10.0 million, bringing the balance to $175.0 million. 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 2007 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 September 30, 2007, our current ratio was 1.9 to 1.0, as adjusted per current agreements, and our leverage ratio was 1.0 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 obtained a waiver of any breach of a loan covenant arising out of Calpine’s institution of Calpine’s fraudulent conveyance action against us and were in compliance with all covenants at September 30, 2007. All amounts drawn under the Revolver are due and payable on July 7, 2009. Availability under the revolving line of credit was $174.0 million at September 30, 2007.

Second Lien Term Loan. In July 2005, BNP Paribas provided us with a second lien term loan in the amount of $100.0 million (“Term Loan”). On September 27, 2005, we repaid $25.0 million of borrowings on the Term Loan, reducing the balance to $75.0 million and syndicated the Term Loan to a group of lenders including BNP Paribas. Borrowings under the Term Loan initially bore interest at LIBOR plus 5.00%. As a result of the hedges put in place in July 2005 and the favorable effects of our private equity placement, as described above, the interest rate for the Term Loan has been reduced to LIBOR plus 4.00%. The Term Loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We obtained a waiver of any breach of a loan covenant raising out of Calpine’s institution of Calpine’s fraudulent conveyance action against us and were in compliance with all covenants at September 30, 2007. The revised principal balance of the Term Loan is due and payable on July 7, 2010.

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Cash Flows

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

	Nine Months Ended September 30,
	2007			2006
	(In thousands)
Cash flows provided by operating activities	$	183,553		$	141,621
Cash flows used in investing activities		(242,837	)		(162,161	)
Cash flows provided by (used in) financing activities		10,160			(441	)
Net decrease in cash and cash equivalents	$	(49,124	)	$	(20,981	)

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 nine months ended September 30, 2007.

Cash flows provided by operating activities increased by $41.9 million for the nine months ended September 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 September 30, 2007, we had a working capital deficit of $47.0 million. This deficit was largely caused by the decrease in our cash balance to fund capital expenditures, including property acquisitions. For the nine months ended September 30, 2007, we incurred approximately $250.9 million in capital expenditures as compared to $151.0 million for the nine months ended September 30, 2006.

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

Cash flows used in investing activities increased by $80.7 million for the nine months ended September 30, 2007 as compared to the same period for 2006. During the nine months ended September 30, 2007, we participated in the drilling of 149 gross wells and acquired the OPEX Properties for $38.7 million.

Financing Activities. The primary driver of cash provided by or used in financing activities are borrowings associated with the revolving credit facility and equity transactions.

Cash flows provided by financing activities increased by $10.6 million as compared to the same period for 2006. The net increase is primarily related to the additional borrowing of $10.0 million made in the third quarter of 2007 against the revolving credit facility 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 nine months ended September 30, 2007 increased by $99.9 million to $250.9 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 as compared to $11.6 million for the nine months ended September 30, 2006 for the purchase of oil and gas properties from Contango Oil and Gas. During the nine months ended September 30, 2007, we participated in the drilling of 149 gross wells with the majority of these being in the Rocky Mountains and the Lobo region. 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 were projected to be $250.0 million and has been adjusted in October 2007 to $280.0 million.

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.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk primarily related to adverse changes in oil and natural gas prices and interest rates. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosure About Market Risks” in our annual report filed on Form 10-K for the year ended December 31, 2006 and footnote 4 and 12 included in Part I. Item 1. Financial Statements of this form 10-Q.

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 September 30, 2007. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of September 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 “Lawsuit”). The complaint alleges that the purchase by us of the domestic oil and natural gas business 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, plus interest, or (ii) in the alternative, return of the Assets from us. We believe that the allegations in the Lawsuit are wholly baseless, and we continue to believe that it is unlikely that this challenge by Calpine to the fairness of the Acquisition will be successful upon the ultimate disposition of this litigation in the Bankruptcy Court, or if necessary, in the appellate courts. The Official Committee of Equity Security Holders and the Official Committee of the Unsecured Creditors have both intervened in the Lawsuit for the stated purpose of monitoring the proceedings because the committees claim to have an interest in the Lawsuit, which we dispute because creditors are likely to be paid in full under Calpine’s plan of reorganization ("Plan of Reorganization") without regard to the Lawsuit and equity holders have no interest in fraudulent conveyance actions.

On September 10, 2007, we filed a motion to dismiss the complaint or in the alternative, to stay the adversary proceeding. The Bankruptcy Court conducted a hearing upon our motion on October 24, 2007. Following the hearing, the Bankruptcy Court denied our motion on the basis that certain issues we raised in our motion were premature as the bankruptcy process had not yet established how much Calpine’s creditors would receive. We filed our answer and counterclaims against Calpine on November 5, 2007. The parties are targeting completing discovery in the Lawsuit in March 2008. The Bankruptcy Court has not set a trial date.

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 September 25, 2007, the Bankruptcy Court approved Calpine’s Disclosure Statement accompanying its proposed Plan of Reorganization under Chapter 11 of the Bankruptcy Code, 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. We may contend that the Purchase Agreement is not an executory contract which Calpine may choose to reject. If the Court were to determine that the Purchase Agreement is an executory contract, we contend 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 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 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 (excluding that portion of these properties subject to a validly exercised third party’s preferential right to purchase) 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 nine months ended September 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.

On September 11, 2007, the Bankruptcy Court entered an order approving that certain Partial Transfer and Release Agreement (“PTRA”) negotiated by and between us and Calpine which, among other things, resolves issues in regard to title of certain of the other oil and natural gas properties we purchased from Calpine in the Acquisition and for which payment was made to Calpine on July 7, 2005, and extends the Marketing and Services Agreement (“MSA”) with Calpine Producer Services, L.P. (“CPS”). The additional documentation received from Calpine under the PTRA eliminates any open issues in our title and resolves any issues as to the clarity of our ownership in certain properties located in the Gulf of Mexico, California, and Wyoming (the “PTRA Properties”), including all oil and gas properties requiring ministerial approvals, such as leases with the U.S. Minerals Management Service (“MMS”), California State Lands Commission (“CSLC”) and U.S. Bureau of Land Management (“BLM”). However, the PTRA was executed without prejudice to Calpine’s fraudulent conveyance action or its right, if any, to reject the Purchase Agreement, and our rights and legal arguments in relation thereto. The PTRA did not address or resolve issues with respect to the Non-Consent Properties and certain other properties.

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We recorded the conveyances of those PTRA Properties in California not requiring governmental agency approval. On October 30, 2007, the CSLC approved the assignment of the State of California leases and rights of way to us from Calpine. We are still awaiting the ministerial approval from the MMS and BLM for the assignment of Calpine’s interests in these PTRA Properties to us.

Notwithstanding the PTRA, as a result of Calpine’s bankruptcy filing, it remains uncertain as to whether Calpine will respond cooperatively as to the remaining outstanding issues under the Purchase Agreement. 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 remaining issues whether under the Purchase Agreement or the PTRA, 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 or cash flows.

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

As part of the PTRA, we entered into the MSA with CPS, effective July 1, 2007, which was approved by the Bankruptcy Court on September 11, 2007. Under the MSA, CPS provides marketing and related services in relation to the sales of our natural gas production and charges us a fee. This MSA extends CPS’ obligations to provide such services until June 30, 2009. The MSA is subject to early termination by us upon the occurrence of certain events.

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 its pending bankruptcy proceeding 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 Calpine’s motion 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 the 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 MMS 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:

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

Resolution of the final amounts we are to pay Calpine, which we had at that time concluded was approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties (excluding that portion of these properties subject to a validly exercised third party’s preferential right to purchase) and approximately $11 million in other true-up payment obligations. We are currently updating these calculations with respect to the final amounts, if any, we are to pay Calpine.

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

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

On August 1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy asserting claims against a variety of Calpine debtors seeking recovery of $27.9 million in liquidated amounts, as well as unliquidated damages in amounts that have not presently been 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 possesses 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. The MMS Oil and Gas Leases and CSLC Leases were included in the PTRA that was approved by the Bankruptcy Court on September 11, 2007, with the result that there is no further need for the parties to contest whether the MMS Oil and Gas Leases and the CLSC Leases are appropriate for inclusion in Calpine’s 365 motion. The PTRA approved by Bankruptcy Court, among other things, resolves open issues in regard to the Company’s title to ownership of all of the unexpired MMS Oil and Gas Leases and the CLSC Leases. However, the PTRA was executed without prejudice to Calpine’s fraudulent conveyance action or its rights, if any, to reject the purchase agreement and the Company’s rights and legal arguments in relation thereto.

On August 3, 2007, we executed the PTRA, 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 principal terms are as follows:

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We will extend the MSA With CPS until June 30, 2009, effective July 1, 2007. 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 the Properties defined as certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming;

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.

On September 11, 2007, the Bankruptcy Court approved the PTRA. The PTRA did not resolve the open issues on the Non-Consent Properties and certain other properties.

Notwithstanding the PTRA, 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 September 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 “Lawsuit”). 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 a 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, 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. The Official Committee of Equity Security Holders and the Official Committee of the Unsecured Creditors have both intervened in the Lawsuit for the stated purpose of monitoring the proceedings because the committees claim to have an interest in the Lawsuit, which we dispute because creditors are likely to be paid in full under Calpine’s Plan of Reorganization without regard to the Lawsuit and equity holders have no interest in fraudulent conveyance actions. On September 10, 2007, we filed a motion to dismiss the complaint, which the Bankruptcy Court heard on October 24, 2007. Following the hearing, the Bankruptcy denied our motion on the basis that certain issues we raised in our motion were premature as the bankruptcy process had not yet established how much Calpine’s creditors would receive. We filed our answer and counterclaims against Calpine on November 5, 2007. The parties are targeting completing discovery in the Lawsuit in March 2008.

The Bankruptcy Court has not set a trial date. Discovery is expected to continue up through March 2008. 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 operations 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.

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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 Agreement, including the 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 Rosetta sells gas to Calpine Energy Services (“CES”) and the CPS Marketing Agreement under which CPS sells Rosetta’s 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, which was approved by the Bankruptcy Court on September 11, 2007, 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, effective as of July 1, 2007, 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.

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. Those properties that may still be subject to ministerial governmental action approving us as qualified assignee and operator were included as part of the properties for which issues are being resolved under the PTRA. 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 resolved the title issues on a significant number of those properties. As noted, we reached agreement with Calpine upon and executed the PTRA on August 3, 2007, which the Bankruptcy Court entered an order approving on September 11, 2007, without prejudice to the other pending claims, disputes and defenses between Calpine and Rosetta. 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. The PTRA does not address the Non-Consent Properties which Calpine withheld from the July 2005 closing due to lack of receipt of the lessors’ consents determined at that time (in many instances mistakenly) as needed for transfer and for which we withheld from the closing of the transaction with Calpine approximately $75 million of the purchase price. On October 30, 2007, the California State Lands Commission approved Calpine’s assignment of its interests in a certain State of California lease and certain rights-of-way.

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 September 30, 2007

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May yet Be Purchased Under the Plans or Programs
July 1 - July 31	11,428	$ 21.84	-	-
August 1 - August 31	2,038	17.58	-	-
September 1 - September 30	753	17.67	-	-

(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.

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Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

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

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Item 6. Exhibits

10.1

Separation Agreement with B. A. Berilgen (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K as filed with the Commission on July 9, 2007)

10.2

Second Amended and Restated Employment Agreement with Michael J. Rosinski

10.3

Amended and Restated Employment Agreement with Charlie F. Chambers

10.4

Partial Transfer and Release Agreement with Calpine Corporation et al.

10.5

Marketing and Related Services Agreement with Calpine Producer Services, L.P.

31.1

Certification of Periodic Financial Reports by Randy L. Limbacher 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 Randy L. Limbacher 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: November 9, 2007

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ROSETTA RESOURCES INC.

EXHIBIT INDEX

Exhibit Number		Description
10.1		Separation Agreement with B. A. Berilgen (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K as filed with the Commission on July 9, 2007)
10.2		Second Amended and Restated Employment Agreement with Michael J. Rosinski
10.3		Amended and Restated Employment Agreement with Charlie F. Chambers
10.4		Partial Transfer and Release Agreement with Calpine Corporation et al.
10.5		Marketing and Related Services Agreement with Calpine Producer Services, L.P.
31.1		Certification of Periodic Financial Reports by Randy L. Limbacher 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 Randy L. Limbacher and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350