Edgar Filing: Rosetta Resources Inc.

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

FORM 10-Q

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

For The Quarterly Period Ended June 30, 2008

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

_______________

Commission File Number: 000-51801

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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 S No £

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

Large accelerated filer S	Accelerated filer £
Non-Accelerated filer £	Smaller Reporting Company £
(Do not check if smaller reporting company)

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

The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of August 1, 2008 was 51,678,319.

Table of Contents

Part I – Financial Information

	Item 1. Financial Statements	3

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	25

	Item 4. Controls and Procedures	25

Part II – Other Information

	Item 1. Legal Proceedings	25

	Item 1A. Risk Factors	30

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	30

	Item 3. Defaults Upon Senior Securities	30

	Item 4. Submission of Matters to a Vote of Security Holders	30

	Item 5. Other Information	31

	Item 6. Exhibits	32

Signatures		33

Exhibit Index

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)

	June 30, 2008			December 31, 2007
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	70,768		$	3,216
Accounts receivable		87,335			55,048
Derivative instruments		-			3,966
Deferred income taxes		40,085			-
Prepaid expenses		5,392			10,413
Other current assets		3,892			4,249
Total current assets	$	207,472		$	76,892
Oil and natural gas properties, full cost method, of which $41.0 million at June 30, 2008 and $40.9 million at December 31, 2007 were excluded from amortization		1,702,274			1,566,082
Other fixed assets		7,357			6,393
		1,709,631			1,572,475
Accumulated depreciation, depletion, and amortization		(396,905	)		(295,749	)
Total property and equipment, net		1,312,726			1,276,726
Deferred loan fees		1,605			2,195
Other assets		1,321			1,401
Total other assets		2,926			3,596
Total assets	$	1,523,124		$	1,357,214

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	38,718		$	33,949
Accrued liabilities		48,888			64,216
Royalties payable		32,079			18,486
Derivative instruments		107,611			2,032
Prepayment on gas sales		27,844			20,392
Deferred income taxes		-			720
Total current liabilities		255,140			139,795
Long-term liabilities:
Derivative instruments		46,582			13,508
Long-term debt		245,000			245,000
Asset retirement obligation		26,028			18,040
Deferred income taxes		93,835			67,916
Total liabilities		666,585			484,259
Commitments and contingencies (Note 9)
Stockholders' equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2008 or 2007		-			-
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 50,849,270 shares and 50,542,648 shares at June 30, 2008 and December 31, 2007, respectively		50			50
Additional paid-in capital		769,402			762,827
Treasury stock, at cost; 121,639 and 109,303 shares at June 30, 2008 and December 31, 2007, respectively		(2,309	)		(2,045	)
Accumulated other comprehensive loss		(96,756	)		(7,225	)
Retained earnings		186,152			119,348
Total stockholders' equity		856,539			872,955
Total liabilities and stockholders' equity	$	1,523,124		$	1,357,214

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 June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Revenues:
Natural gas sales	$	136,142		$	77,436		$	248,587		$	146,597
Oil sales		18,325			9,438			34,213			16,073
Total revenues		154,467			86,874			282,800			162,670
Operating Costs and Expenses:
Lease operating expense		14,174			12,566			27,588			21,362
Depreciation, depletion, and amortization		51,738			36,342			103,152			66,893
Treating and transportation		1,539			882			2,843			1,645
Marketing fees		1,016			669			1,764			1,332
Production taxes		5,754			1,200			9,192			2,185
General and administrative costs		13,516			9,898			25,623			17,967
Total operating costs and expenses		87,737			61,557			170,162			111,384
Operating income		66,730			25,317			112,638			51,286

Other (income) expense
Interest expense, net of interest capitalized		4,470			4,680			8,024			9,050
Interest income		(317	)		(257	)		(556	)		(1,229	)
Other (income) expense, net		(89	)		(182	)		(131	)		(182	)
Total other expense		4,064			4,241			7,337			7,639

Income before provision for income taxes		62,666			21,076			105,301			43,647
Provision for income taxes		23,351			7,985			38,497			16,565
Net income	$	39,315		$	13,091		$	66,804		$	27,082

Earnings per share:
Basic	$	0.78		$	0.26		$	1.32		$	0.54
Diluted	$	0.77		$	0.26		$	1.31		$	0.54

Weighted average shares outstanding:
Basic		50,585			50,354			50,547			50,340
Diluted		50,961			50,625			50,873			50,565

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

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Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2008			2007
Cash flows from operating activities
Net income	$	66,804		$	27,082
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		103,152			66,893
Deferred income taxes		38,262			16,479
Amortization of deferred loan fees recorded as interest expense		590			590
Income from unconsolidated investments		(166	)		(85	)
Stock compensation expense		3,677			3,176
Change in operating assets and liabilities:
Accounts receivable		(32,287	)		(1,492	)
Other current assets		5,379			(11,659	)
Other assets		186			331
Accounts payable		4,769			7,345
Accrued liabilities		2,578			(2,247	)
Royalties payable		21,045			7,882
Net cash provided by operating activities		213,989			114,295
Cash flows from investing activities
Acquisition of oil and gas properties		(29,503	)		(38,656	)
Purchases of property and equipment		(119,594	)		(128,139	)
Disposals of property and equipment		27			1,005
Other		-			26
Net cash used in investing activities		(149,070	)		(165,764	)
Cash flows from financing activities
Proceeds from stock options excercised		2,898			571
Purchases of treasury stock		(265	)		(113	)
Net cash provided by financing activities		2,633			458

Net increase (decrease) in cash		67,552			(51,011	)
Cash and cash equivalents, beginning of period		3,216			62,780
Cash and cash equivalents, end of period	$	70,768		$	11,769

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	19,450		$	27,694

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., (and its partners), and the domestic oil and natural gas business formerly owned by Calpine Corporation and affiliates (“Calpine”). The Company acquired Calpine Natural Gas L.P. (and its partners) 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 North America. The Company’s main operations are primarily concentrated in the Sacramento Basin of California, the Rocky Mountains, the Lobo and Perdido Trends in South Texas, the State Waters of Texas and the Gulf of Mexico.

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, 2007.

Certain reclassifications of prior year balances have been made to conform such amounts to corresponding 2008 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, 2007.

Principles of Consolidation. The accompanying consolidated financial statements as of June 30, 2008 and December 31, 2007 and for the three and six months ended June 30, 2008 and 2007 contain the accounts of the Company and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.

Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“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 FASB has also issued Staff Position FAS 157-2 (“FSP No. 157-2”), which delayed the effective date of SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company partially adopted SFAS No. 157 as discussed in Note 5 and has chosen to defer the implementation of nonfinancial assets and liabilities in accordance with FSP No. 157-2. Accordingly, the Company will apply SFAS No. 157 to its nonfinancial assets and liabilities which are disclosed or recognized at fair value on a nonrecurring basis and other assets and liabilities in the first quarter of 2009. We are still in the process of evaluating SFAS 157 with respect to its effect on nonfinancial assets and liabilities and therefore have not yet determined the impact that it will have on our financial statements upon full adoption in 2009. Nonfinancial assets and liabilities for which we have not applied the provisions of SFAS 157 include our asset retirement obligations.

The Company also adopted SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115” (“SFAS No. 159”) on January 1, 2008. SFAS No. 159 permits companies to choose to measure financial instruments and certain other items at fair value that were not previously required to be measured at fair value. The Company has not elected to present assets and liabilities at fair value that were not required to be measured at fair value prior to the adoption of SFAS No. 159.

Recent Accounting Developments

The Hierarchy of Generally Accepted Accounting Principles. In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). This Statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the “GAAP hierarchy”). This Statement shall be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (“PCAOB”) amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. For pronouncements whose effective date is after March 15, 1992, and for entities initially applying an accounting principle after March 15, 1992 (except for EITF consensus positions issued before March 16, 1992, which become effective in the hierarchy for initial application of an accounting principle after March 15, 1993), an entity shall follow this Statement. Any effect of applying the provisions of this Statement shall be reported as a change in accounting principle in accordance with FASB Statement No. 154, Accounting Changes and Error Corrections. An entity shall follow the disclosure requirements of that Statement, and additionally, disclose the accounting principles that were used before and after the application of the provisions of this Statement and the reason why applying this Statement resulted in a change in accounting principle. The Company does not expect the adoption of SFAS No. 162 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

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Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (“SFAS No. 161”), which is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures. This statement is effective for fiscal years beginning after November 15, 2008. The Company is currently evaluating the potential impact of SFAS No. 161.

Noncontrolling Interests in Consolidated Financial Statements. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No. 160”), which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141R”), which creates greater consistency in the accounting and financial reporting of business combinations. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 141R to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

(3)	Property, Plant and Equipment

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

	June 30, 2008			December 31, 2007
	(In thousands)
Proved properties	$	1,629,344		$	1,499,046
Unproved/unevaluated properties		41,004			40,903
Gas gathering systems and compressor stations		31,926			26,133
Other		7,357			6,393
Total oil and natural gas properties		1,709,631			1,572,475
Less: Accumulated depreciation, depletion, and amortization		(396,905	)		(295,749	)
Total property and equipment, net	$	1,312,726		$	1,276,726

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.4 million and $1.1 million of internal costs for the three months ended June 30, 2008 and 2007, respectively, and $2.8 million and $2.4 million for the six months ended June 30, 2008 and 2007, respectively.

Included in the Company’s oil and gas properties are asset retirement costs of $24.3 million and $20.1 million as of June 30, 2008 and December 31, 2007, respectively.

Oil and gas properties include costs of $41.0 million and $40.9 million at June 30, 2008 and December 31, 2007, 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 Company’s ceiling test computation was calculated using hedge adjusted market prices at June 30, 2008, which were based on a Henry Hub price of $13.10 per MMBtu and a West Texas Intermediate oil price of $140.22 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2008 decreased the calculated ceiling value by approximately $88.6 million (net of tax). There was no write-down required to be recorded at June 30, 2008. 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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(4)	Commodity Hedging Contracts and Other Derivatives

The Company has entered into financial fixed price swaps with prices ranging from $6.81 per MMBtu to $8.63 per MMBtu covering a portion of the Company’s 2008, 2009 and 2010 production. The following financial fixed price swap transactions were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations at June 30, 2008:

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)
2008	Swap	Cash flow		67,892		12,492,184		7.75		52	%		(59,648	)
2009	Swap	Cash flow		52,141		19,031,465		7.65		44	%		(78,116	)
2010	Swap	Cash flow		10,000		3,650,000		8.31		9	%		(8,808	)
						35,173,649						$	(146,572	)

______________

(1) Estimated based on net gas reserves presented in the December 31, 2007 Netherland, Sewell, & Associates, Inc. reserve report.

The Company has also entered into costless collar transactions covering a portion of the Company’s 2008 and 2009 production. The costless collars have an average floor price of $8.00 per MMBtu and an average ceiling price of $10.22 per MMBtu. The following costless collar transactions were outstanding with associated notional volumes and contracted ceiling and floor prices that represent hedge prices at various market locations at June 30, 2008:

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)
2008	Costless Collar	Cash flow		5,000		920,000	$	8.00	$	10.55		4	%	$	(2,204	)
2009	Costless Collar	Cash flow		5,000		1,825,000	$	8.00	$	10.05		4	%	$	(4,476	)
						2,745,000								$	(6,680	)

______________

(1) Estimated based on net gas reserves presented in the December 31, 2007 Netherland, Sewell, & Associates, Inc. reserve report.

In addition, the Company has hedged the interest rates on $75.0 million of its outstanding debt through 2008 and $50.0 million through June 2009. As of June 30, 2008, the Company had the following financial interest rate swap positions outstanding:

Settlement Period	Derivative Instrument	Hedge Strategy	Average Fixed Rate			Fair Market Value Gain/(Loss) (In thousands)
2008	Swap	Cash Flow		4.41	%	$	(652	)
2009	Swap	Cash Flow		4.55	%		(289	)
						$	(941	)

The Company presents the fair value of their derivatives for which a master netting agreement exists on a net basis in accordance with FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts an interpretation of APB Opinion No. 10 and FASB Statement No. 105” (“FIN 39”).

The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities. This eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations. As of June 30, 2008, the Company made no deposits for collateral.

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The following table sets forth the results of the Company’s hedge transactions for the respective period for the Consolidated Statement of Operations:

	Three Months Ended June 30,					Six Months Ended June 30,
Natural Gas	2008			2007		2008			2007
Quantity settled (MMBtu)		6,636,216			5,946,800		12,792,432			11,471,300
Increase (Decrease) in natural gas sales revenue (In thousands)	$	(16,595	)	$	2,433	$	(17,296	)	$	7,477

The following table sets forth the results of the Company’s interest rate hedging transactions settled for the Consolidated Statement of Operations:

	Three Months Ended June 30,					Six Months Ended June 30,
Interest Rate Swaps	2008			2007		2008			2007
Decrease in interest expense (In thousands)		(335	)	$	-		(460	)	$	-

As of June 30, 2008, the Company expects to reclassify losses of $107.6 million to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.

Gains and losses related to ineffectiveness were immaterial for the three and six months ended June 30, 2008 and 2007.

(5)	Fair Value Measurements

Effective January 1, 2008, the Company partially adopted SFAS No. 157 as it relates to the valuation of financial assets and liabilities. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. The adoption of SFAS No. 157 for financial assets and liabilities did not have a significant effect on our consolidated financial position, results of operations or cash flows.

As defined in SFAS No. 157, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of fair value under SFAS No. 157 are as follows:

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

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

Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. Level 3 instruments include natural gas swaps, natural gas zero cost collars and interest rate swaps. The Company utilizes third party broker quotes to determine the valuation of its derivative instruments, accordingly, the Company did not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	At fair value as of June 30, 2008 (In thousands)
	Level 1		Level 2		Level 3			Total
Assets (Liabilities):
Commodity derivative contracts		-		-		(153,252	)		(153,252	)
Interest rate swap contracts		-		-		(941	)		(941	)
Total		-		-		(154,193	)		(154,193	)

The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements, but also the impact of the Company’s nonperformance risk on its liabilities.

The table below presents a reconciliation for the assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during 2008. The fair values of Level 3 derivative instruments are estimated using valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in management’s judgment, reflect the assumptions a marketplace participant would have used at June 30, 2008.

	Derivatives Asset (Liability) (In thousands)
Balance as of January 1, 2008	$	(10,792	)
Total realized or unrealized gains (losses)
included in earnings		-
included in other comprehensive income		(161,157	)
Purchases, issuances and settlements		17,756
Transfers in and out of level 3		-
Balance as of June 30, 2008	$	(154,193	)

Total gains (losses) included in earnings attributable to the change in unrealized gains (losses) relating to derivatives still held as of June 30, 2008	$	-

(6)	Asset Retirement Obligation

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

	Six Months Ended June 30, 2008
	(In thousands)
ARO as of December 31, 2007	$	22,670
Revision of previous estimates		4,505
Liabilities settled during period		(267	)
Accretion expense		993
ARO as of June 30, 2008	$	27,901

Of the total ARO, approximately $1.9 million is classified as a current liability included in accrued liabilities on the Consolidated Balance Sheet at June 30, 2008.

(7)	Long-Term Debt

The Company’s credit facilities consist of a senior secured revolving line of credit (“Revolver”) up to $400.0 million with a borrowing base of $400.0 million, increased from $350.0 million in June 2008, and a five-year $75.0 million second lien term loan.

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As of June 30, 2008, the Company had total outstanding borrowings and letters of credit of $245.0 million and $1.0 million, respectively. Net borrowing availability under the Revolver was $229.0 million at June 30, 2008. The Company was in compliance with all covenants at June 30, 2008.

All amounts drawn under the Revolver are due and payable on April 5, 2010. The principal balance associated with the second lien term loan is due and payable on July 7, 2010.

(8)	Income Taxes

As of June 30, 2008, the Company had no unrealized tax benefits. The effective tax rate for the three and six months ended June 30, 2008 was 37.3% and 36.6%, respectively. The effective tax rate for the three and six months ended June 30, 2007 was 37.8 % and 37.9%, respectively. 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.

(9)	Commitments 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”). On December 19, 2007, the Bankruptcy Court approved Calpine’s plan of reorganization (“Plan of Reorganization”). On January 31, 2008, Calpine and certain of its subsidiaries emerged from bankruptcy (the “Plan Effective Date”).

Calpine’s Lawsuit Against the Company

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. Through the Lawsuit, 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 both intervened in the Lawsuit for the stated purpose of monitoring the proceedings because the committees claimed to have an interest in the Lawsuit, which the Company disputes because it believes creditors may 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. Under Calpine’s Plan of Reorganization approved by the Bankruptcy Court on December 19, 2007, the Official Committee of Equity Security Holders was dissolved as of the Plan Effective Date and no longer has any interest in the Lawsuit. While the Unsecured Creditors Committee also was officially dissolved as of the Plan Effective Date, there are provisions under the approved Plan of Reorganization that will allow it to remain involved in lawsuits to which it is a party, which may include this Lawsuit.

On September 10, 2007, the Company filed a motion to dismiss the Lawsuit or, in the alternative, to stay the Lawsuit. 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. On November 5, 2007, the Company filed its answer, affirmative defenses and counterclaims with respect to the Lawsuit, denying the allegations set forth in both counts of the Lawsuit, and asserting affirmative defenses to Calpine’s claims as well as affirmative counterclaims against Calpine related to the Acquisition for (i) breach of its covenant of solvency contained in the Purchase and Sale Agreement with respect to the Acquisition 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”), (ii) fraud and fraud in a real estate transaction, (iii) breach of contract, (iv) conversion, (v) civil theft and (vi) setoff.

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On July 7, 2008, Rosetta filed a letter with the Bankruptcy Court requesting the required conference with the Court prior to filing a motion for summary judgment. The basis for the motion for summary judgment is that (i) Calpine is not the proper plaintiff because subsidiaries of Calpine, not Calpine, conveyed the oil and gas business to the Company; (ii) to the extent Calpine owned certain oil and gas leases prior to the transaction, the Company is not the proper defendant because those leases were conveyed to affiliated entities; and (iii) the Company qualifies for safe harbor protection under section 546(e) of the bankruptcy code from and against any fraudulent conveyance claims of Calpine. The Bankruptcy Court has not yet scheduled a conference; therefore, the Company is unable to state for certain when the actual motion for summary judgment will be filed with the Bankruptcy Court. On July 11, 2008, the Company filed a motion to disqualify Calpine’s valuation experts, PA Consulting, due to their conflicts of interest, including without limitation their agreement to receive a success fee as compensation, a violation of the New York ethical rules. A hearing on this motion has been scheduled for August 27, 2008.

Due to the time it has taken the parties to complete document discovery, the parties have agreed, at this point, to extend the time period for discovery in the Lawsuit; however, the Bankruptcy Court has not set a firm discovery deadline or a trial date.

Remaining Issues with Respect to the Acquisition

Separate from the Calpine lawsuit, Calpine has taken the position that the Purchase Agreement (and its constituent parts) 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 may 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 the Company may argue 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 would normally have been the date on which Calpine’s Plan of Reorganization was confirmed; however, in order to address certain issues, Calpine and the Company have agreed to extend this deadline until fifteen days following the entry of a final, unappealable order in the Lawsuit, and the parties set forth this agreement in the Plan of Reorganization approved by the Bankruptcy Court on December 19, 2007.

Open Issues Regarding Legal Title to Certain Properties

Under the Purchase Agreement, Calpine is required to resolve the open issues regarding legal title to interests in 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 leases and wells 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”). The interests in Non-Consent Properties were not included in the conveyances delivered at the closing of the Acquisition. 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 had been prepared to conclude the remaining aspects of the Acquisition. The Company has excluded from its statement of operations for the three and six months ended June 30, 2008 and 2007, estimated net revenues and estimated production from interests in certain leases and wells being a portion 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. The Company entered into a new Marketing and Services Agreement (“MSA”) with Calpine Producer Services, L.P. (“CPS”) for a two-year period commencing on July 1, 2007 but which is subject to earlier termination by the Company on the occurrence of certain events. 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 (collectively, 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 without prejudice to the Company’s rights and legal arguments in relation thereto, including the Company’s various counterclaims. The PTRA did not otherwise 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 and resolved open issues under an audit the State of California had conducted as to these PTRA Properties. The Company has received the ministerial approval by the MMS for the assignment of Calpine’s interests in MMS Federal Offshore leases for South Pelto 17 and South Timbalier 252 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 to 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 sales 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 sales agreements. Although Calpine indicated in conjunction with the Plan of Reorganization that it intended to assume the CES natural gas sales agreements with the Company separate from the Purchase Agreement, the Company disagrees that Calpine may assume anything less than the entire Purchase Agreement and the parties agreed to postpone any dispute on this issue until resolution of the Lawsuit.

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 the Company’s 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. In July 2008, the Company notified Calpine it would not be renewing the MSA and, unless it expired sooner by its terms, the MSA would conclude on June 30, 2009.

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 certain oil and natural gas leases 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. Certain of these properties have been subsequently addressed under the PTRA discussed above.

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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 (i) 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, as applicable, operator of all of these Federal offshore leases excepting two of them which expired before the Company received such recognition by the MMS, and (ii) 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 its retained interests in 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.

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 (excluding the properties subject to third party’s preferential right).

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 possess 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 approved Plan of Reorganization, the Company cannot predict what amounts it may recover from the Calpine bankruptcy should Calpine reject or refuse to perform under the Purchase Agreement.

With respect to the stipulations between Calpine and MMS and Calpine and CSLC extending the deadline to assume or reject the MMS Oil and Gas Leases and the CSLC Leases respectively, these parties 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, 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.

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On June 20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure Statement with the Bankruptcy Court. Calpine had indicated in its filings with the Bankruptcy Court that it believed substantial payments in the form of cash or newly issued stock, or some combination thereof, would 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 amount of allowed claims that remain following the objection process. The Bankruptcy Court approved Calpine’s Plan of Reorganization on December 19, 2007, overruling the Company’s objection to the releases granted by this plan to prior and current directors and officers of Calpine and certain of its law firms and other professional advisors. The effective date of the Plan was January 31, 2008.

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 principal terms are as follows:

The Company extended certain marketing services by executing a new MSA with CPS through and 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 delivers to the Company documents that resolve title issues pertaining to the PTRA Properties, defined as certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming;

The Company assumes all Calpine's rights and obligations for an audit by the CSLC on part of the PTRA Properties; and

The Company assumes all rights and obligations for the PTRA 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 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) Calpine’s remaining performance under the Purchase Agreement and the amounts that will be payable in connection therewith, (ii) whether or not Calpine and its affiliated debtors will, in fact, perform their remaining obligations in connection with the Purchase Agreement and PTRA; and (iii) the issues pertaining to the Non-Consent Properties.

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. With the Company’s assistance, 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 had earlier 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. The Company intends to cooperate with Calpine in defending against Pogo’s claim should it resume; however, it is too early for management to determine whether this matter will affect the Company, and if so, in what amount. This is due, but not limited to uncertainty concerning (i) whether or not Pogo’s proofs of claim will be fully satisfied by Calpine under its approved Plan of Reorganization; and (ii) whether, and if so, the extent to which, Calpine may reimburse the Company for its claim for its defense costs and any arbitration award regarding the Pogo claim. The Company and Calpine have entered into a joint defense agreement whereby Calpine has taken over the defense of Pogo’s claims and is indemnifying the Company.

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(10)	Comprehensive Income

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

	Three Months Ended June 30,												Six Months Ended June 30,
	2008						2007						2008						2007
	(In thousands)
Accumulated other comprehensive (loss) income beginning of period				$	(48,539	)				$	(16,979	)				$	(7,225	)				$	6,315
Net income		39,315						13,091						66,804						27,082

Change in fair value of derivative hedging instruments		(93,771	)					15,825						(160,435	)					(16,521	)
Hedge settlements reclassed to income		16,930						(2,433	)					17,756						(7,477	)
Tax provision related to hedges		28,624						(5,049	)					53,148						9,047
Total other comprehensive (loss) income		(48,217	)		(48,217	)		8,343			8,343			(89,531	)		(89,531	)		(14,951	)		(14,951	)

Comprehensive (loss) income		(8,902	)					21,434						(22,727	)					12,131
Accumulated other comprehensive loss				$	(96,756	)				$	(8,636	)				$	(96,756	)				$	(8,636	)

(11)	Earnings Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted 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 June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(In thousands)
Basic weighted average number of shares outstanding		50,585		50,354		50,547		50,340
Dilution effect of stock option and awards at the end of the period		376		271		326		225
Diluted weighted average number of shares outstanding		50,961		50,625		50,873		50,565

Anti-dilutive stock awards and shares		313		268		287		407

(12)	Geographic Area Information

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

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

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Oil and Natural Gas Revenue

	Three Months Ended June 30,				Six Months Ended June 30,
	2008 (1)		2007 (1)		2008 (1)		2007 (1)
	(In thousands)
California	$	43,816	$	28,504	$	80,587	$	55,596
Rocky Mountains		9,557		2,760		16,407		4,286
Mid-Continent		711		551		1,263		1,356
Lobo		60,777		28,391		96,920		53,267
Perdido		9,747		7,570		17,836		13,338
State Waters		15,705		838		30,737		1,647
Other Onshore		13,411		4,919		24,141		9,322
Gulf of Mexico		17,336		10,908		32,204		16,381
	$	171,060	$	84,441	$	300,095	$	155,193

(1) Excludes the effects of hedging losses of $16.6 million and hedging gains of $2.4 million for the three months ended June 30, 2008 and 2007, respectively, and hedging losses of $17.3 million and hedging gains of $7.5 million for the six months ended June 30, 2008 and 2007, respectively.

Oil and Natural Gas Properties

	June 30, 2008		December 31, 2007
	(In thousands)
California	$	569,133	$	540,924
Rocky Mountains		124,137		76,343
Mid-Continent		14,690		14,698
Lobo		558,314		515,096
Perdido		84,659		76,259
Texas State Waters		63,096		55,918
Other Onshore		131,336		130,977
Gulf of Mexico		156,909		155,867
Other		7,357		6,393
Total property and equipment	$	1,709,631	$	1,572,475

(13)	Subsequent Events

Effective July 14, 2008, the Company appointed Mr. Philip L. Frederickson, as an independent director, to the Board of Directors. In addition to serving on the Board of Directors, Mr. Frederickson was also named a member of the Audit Committee, the Compensation Committee and the Nominating and Corporate Governance Committee of Rosetta on August 5, 2008.

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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, 2007, 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 natural gas, and oil;

·	The price of natural gas, and oil;

·	Conditions in the energy markets;

·	Changes or advances in technology;

·	Reserve levels;

·	Inflation;

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

·	Commodity prices;

·	Future processing volumes and pipeline throughput;

·	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;

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

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·	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 and its fraudulent conveyance action, including significant ongoing costs for lawyers, consultants, experts and all related expenses, as well as all lost opportunity costs associated with our internal resources dedicated to these matters and possible impacts on our reputation;

·	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 six months ended June 30, 2008 compared to the three and six months ended June 30, 2007, and the material changes in financial condition since December 31, 2007. It is presumed that readers have read or have access to our 2007 Annual Report on Form 10-K for the year ended December 31, 2007, 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 six months of 2008 as compared to the same period for 2007:

·	Production on an equivalent basis increased 35%;

·	Total revenue, including the effects of hedging, increased $120.1 million or 74%;

·	Net income increased $39.7 million or 147%;

·	Diluted earnings per share increased $0.77 or 143%; and

·	Drilled 71 gross wells with a success rate of 83%.

Critical Accounting Policies and Estimates

In our Annual Report on Form 10-K for the year ended December 31, 2007, we identified our most critical accounting policies upon which our financial condition depends as those relating to oil and natural gas reserves, full cost method of accounting, derivative transactions and hedging activities, income taxes and stock-based compensation.

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

Our ceiling test computation was calculated using hedge adjusted market prices at June 30, 2008, which were based on a Henry Hub price of $13.10 per MMBtu and a West Texas Intermediate oil price of $140.22 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2008 decreased the calculated ceiling value by approximately $88.6 million (net of tax). There was no write-down required to be recorded at June 30, 2008. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a write-down could occur.

The Company has entered into financial fixed price swaps with prices ranging from $6.81 per MMBtu to $8.63 per MMBtu covering a portion of the Company’s 2008, 2009 and 2010 production of approximately 35.2 million MMBtu. The Company has also entered into costless collar transactions covering a portion of the Company’s 2008 and 2009 production of approximately 2.7 million MMBtu. The costless collars have an average floor price of $8.00 per MMBtu and an average ceiling price of $10.22 per MMBtu. Approximately 92% of total hedged transactions represent hedged prices of commodities at PG&E Citygate and Houston Ship Channel. The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities. This eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations. As of June 30, 2008, the Company made no deposits for collateral. Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of June 30, 2008. We include in our fair value measurement a credit adjustment for our counterparties using Standard and Poors (“S&P”) one year credit and default ratings.

The Company utilizes third party broker quotes to determine the valuation of its derivative instruments and has used this valuation technique since adoption of SFAS 157 on January 1, 2008 and the Company has made no changes or adjustments to our technique since then. We mark to market on a quarterly basis. For every $0.10 increase or decrease in natural gas prices, our earnings will be impacted by approximately $1.6 million, net of income taxes. 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 is discretionary and could be curtailed if our cash flows decline from expected levels.

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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 six months of 2008 was $282.8 million, including the effects of hedging, which is an increase of $120.1 million, or 74%, from the six months ended June 30, 2007. Natural gas sales, excluding the effects of hedging, increased by $126.8 million with $75.1 million attributable to a 23% increase in natural gas prices and $51.7 million attributable to a 37% increase in production volumes. Oil sales increased by $18.1 million with $16.0 million associated with an increase in the price of oil and an increase of $2.1 million associated with increased production. Approximately 88% of revenue was attributable to natural gas sales on total volumes of 27.9 Bcfe.

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		% Change Increase/ (Decrease)			2008		2007		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Total revenues	$	154,467	$	86,874		78	%	$	282,800	$	162,670		74	%

Production:
Gas (Bcf)		13.2		10.0		32	%		26.1		19.0		37	%
Oil (MBbls)		147.2		149.4		(1	%)		305.9		269.3		14	%
Total Equivalents (Bcfe)		14.1		10.9		29	%		27.9		20.6		35	%

$ per unit:
Avg. Gas Price per Mcf	$	10.30	$	7.74		33	%	$	9.53	$	7.72		23	%
Avg. Gas Price per Mcf, excluding Hedging		11.56		7.50		54	%		10.20		7.32		39	%
Avg. Oil Price per Bbl		124.51		63.17		97	%		111.85		59.68		87	%
Avg. Revenue per Mcfe		10.96		7.97		38	%		10.13		7.90		28	%

Natural Gas. For the three months ended June 30, 2008, natural gas revenue increased by 76% or $58.7 million, including the realized impact of derivative instruments, from the comparable period in 2007 to $136.1 million. This is primarily due to an increase of 33% in the average gas price, including the effects of hedging, which increased by $2.56 from $7.74 per Mcf for the three months ended June 30, 2007 to $10.30 per Mcf for the comparable period in 2008. In addition, production volumes increased, overall by 32% or 3.2 Bcfe, in all geographic areas except for the Perdido region. The effect of gas hedging activities on natural gas revenue for the three months ended June 30, 2008 was a loss of $16.6 million or a decrease of $1.26 per Mcf as compared to a gain of $2.4 million for the three months ended June 30, 2007.

For the six months ended June 30, 2008, natural gas revenue increased by 70% or $102.0 million, including the realized impact of derivative instruments, from the comparable period in 2007 to $248.6 million. This increase was due to a higher average gas price and production volumes. The average gas price, including the effects of hedging, increased by 23% or $1.81 from $7.72 per Mcf for the six months ended June 30, 2007 to $9.53 per Mcf for the comparable period in 2008. An increase in the number of wells producing in 2008 provided higher production volumes of 7.1 Bcfe or an increase of 37% in all geographic areas.

Crude Oil. For the three months ended June 30, 2008, oil revenue was $18.3 million for a 95% increase as compared to $9.4 million for the comparable period in 2007. This increase is attributable to the average realized price increase of 97% or $61.34 per Bbl from $63.17 per Bbl for the three months ended June 30, 2007 to $124.51 per Bbl for the three months ended June 30, 2008. Oil production volumes were comparable for the respective periods remaining relatively flat at 147.2 MBbls.

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For the six months ended June 30, 2008, oil revenue increased by 113% or $18.1 million due to the 87% increase in the average realized oil price of $52.17 per Bbl from $59.68 per Bbl to $111.85 per Bbl. Oil production volumes were slightly higher with increases in the Texas State Waters offset by a decline in Offshore.

Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		% Change Increase/ (Decrease)			2008		2007		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	14,174	$	12,566		13	%	$	27,588	$	21,362		29	%
Production taxes		5,754		1,200		380	%		9,192		2,185		321	%
Depreciation, depletion and amortization		51,738		36,342		42	%		103,152		66,893		54	%
General and administrative costs		13,516		9,898		37	%		25,623		17,967		43	%

$ per unit:
Avg. lease operating expense per Mcfe	$	1.01	$	1.15		(12	%)	$	0.99	$	1.04		(5	%)
Avg. production taxes per Mcfe		0.41		0.11		273	%		0.33		0.11		200	%
Avg. DD&A per Mcfe		3.67		3.33		10	%		3.70		3.25		14	%
Avg. G&A per Mcfe		0.96		0.91		5	%		0.92		0.87		6	%

Lease Operating Expense. Lease operating expense increased $1.6 million for the three months ended June 30, 2008 as compared to the three months ended June 30, 2007. The overall increase is due to a $1.4 million increase in direct lease operating expense primarily related to equipment rentals and chemicals of $0.9 million, a $0.9 million increase in workover expense and a $0.1 million in insurance expense. These increases were partially offset by a $0.6 million decrease in ad valorem tax. The higher costs are related to the increase in the number of operating wells, particularly in the Rockies and Lobo with the drilling of 15 and 10 successful wells, respectively, as well as a number of workovers in Lobo and the Gulf of Mexico. A 29% increase in production volumes in all regions, but particularly in Lobo of 13.2 MMcfe per day, in Texas State Waters of 11.9 MMcfe per day, in the Rocky Mountains of 4.7 MMcfe per day and in Other Onshore of 5.2 MMcfe per day, contributed to the increase in lease operating costs.

Lease operating expense increased $6.2 million for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 The overall increase is due to a $4.5 million increase in direct lease operating expense primarily related to equipment rentals and chemicals, a $0.9 million increase in workover expense, a $0.3 million in insurance expense and a $0.6 million increase in ad valorem tax. The higher costs are related to the increase in the number of operating wells, particularly in the Rockies and Lobo with the drilling of 26 and 20 successful wells, respectively, as well as a number of workovers in Lobo and the Gulf of Mexico. A 35% increase in production volumes in all regions, but particularly in Lobo of 7.6 MMcfe per day, in Texas State Waters of 12.7 MMcfe per day, in the Gulf of Mexico of 5.3 MMcfe per day, in the Rocky Mountains of 5.6 MMcfe per day and in Other Onshore of 4.6 MMcfe per day, contributed to the increase in lease operating costs.

Production Taxes. Production taxes increased $4.6 million for the three months ended June 30, 2008 as compared to the three months ended June 30, 2007 primarily due to the 29% increase in production volumes and timing differences related to the State of Texas high cost gas exemptions offset by reduced tax rates.

Production taxes increased $7.0 million for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 primarily due to the 35% increase in production volumes and timing differences related to the State of Texas high cost gas exemptions offset by reduced tax rates.

Depreciation, Depletion, and Amortization. Depreciation, depletion and amortization expense increased $15.4 million for the three months ended June 30, 2008 as compared to the three months ended June 30, 2007. This increase is due to a 29% increase in total production and a higher DD&A rate as compared to 2007. The DD&A rate for the second quarter of 2008 was $3.67 per Mcfe while the rate for the second quarter of 2007 was $3.33 per Mcfe.

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Depreciation, depletion and amortization expense increased $36.3 million for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007. This increase is due to a 35% increase in total production and a higher DD&A rate as compared to 2007. The DD&A rate for the second quarter of 2008 was $3.70 per Mcfe while the rate for the second quarter of 2007 was $3.25 per Mcfe.

General and Administrative Costs. General and administrative costs increased by $3.6 million for the three months ended June 30, 2008 as compared to the three months ended June 30, 2007. The higher cost is primarily due to the increase of $1.3 million in legal fees associated with the Calpine litigation, $1.5 million higher payroll and benefit costs relating to the increase in employees, and $1.5 million increase in stock compensation expense relating to an increase in vesting of options and stock awards. These increases were partially offset by a decrease in contract consulting expense of $0.4 million due to the increase in permanent personnel and a decrease of $0.2 million in expenses related to compliance with Section 404 of the Sarbanes-Oxley Act.

General and administrative costs increased by $7.7 million for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007. The higher cost is primarily due to the increase of $4.8 million in legal fees associated with the Calpine litigation and $3.3 million higher payroll and benefit costs relating to the increase in employees, offset by a decrease in contract consulting expense of $0.4 million due to the increase in permanent personnel.

Total Other Expense

For the three months ended June 30, 2008, total other expense decreased by $0.2 million as compared to the three months ended June 30, 2007 primarily as a result of a reduction of interest expense of $0.3 million on debt due to lower LIBOR rates during the period offset by a decrease in capitalized interest of $0.1 million. Interest income remained relatively flat period over period.

For the six months ended June 30, 2008, total other expense decreased by $0.3 million as compared to the six months ended June 30, 2007 primarily as a result of a reduction of interest expense of $1.3 million on debt due to lower LIBOR rates during the period offset by a decrease in capitalized interest of $0.3 million and a reduction in interest income of $0.7 million also as a result of lower rates.

Provision for Income Taxes

The effective tax rate for the three and six months ended June 30, 2008 was 37.3% and 36.6%, respectively. The effective tax rate for the three and six months ended June 30, 2007 was 37.8 % and 37.9%, respectively. 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.

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 in conjunction with the syndication. 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. Accordingly, in May 2007, the borrowing base was adjusted to $350.0 million and in June 2008 was increased to $400.0 million. Amounts outstanding under the Revolver bear interest, at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.125% to 1.875%. Such margins will fluctuate based on the utilization of the facility. Borrowings under the Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the SEC PV-10 pretax reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock of domestic subsidiaries and a lien on cash securing the Calpine gas purchase and sale contract. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At June 30, 2008, our current ratio was 3.0 to 1.0, as adjusted per current agreements, and our leverage ratio was 0.7 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 June 30, 2008. All amounts drawn under the Revolver are due and payable on April 5, 2010. Availability under the Revolver was $229.0 million at June 30, 2008. At June 30, 2008, our weighted average borrowing rate was 4.45%.

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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 bear interest at 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 arising out of Calpine’s institution of Calpine’s fraudulent conveyance action against us and were in compliance with all covenants at June 30, 2008. The revised principal balance of the Term Loan is due and payable on July 7, 2010.

Cash Flows

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

	Six Months Ended June 30,
	2008			2007
	(In thousands)
Cash flows provided by operating activities	$	213,989		$	114,295
Cash flows used in investing activities		(149,070	)		(165,764	)
Cash flows provided by financing activities		2,633			458
Net increase (decrease) in cash and cash equivalents	$	67,552		$	(51,011	)

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 program.

Cash flows provided by operating activities increased by $99.7 million for the six months ended June 30, 2008 as compared to the same period for 2007. The increase in 2008 primarily resulted from higher oil and gas production volumes and prices in 2008. Our working capital deficit decreased by $15.2 million and our cash balance increased $59 million over the same period in 2007 due to a decrease in capital spending of $39.9 million to $132.9 million, an increase in production of 7.3 Bcfe to 27.9 Bcfe and an increase in the average price per Mcfe of $2.23 to $10.13.

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

Cash flows used in investing activities decreased by $16.7 million for the six months ended June 30, 2007 as compared to the same period for 2007. During the six months ended June 30, 2008, we participated in the drilling of 71gross wells as compared to the drilling of 94 gross wells in 2007. Our capital spending in the six months ended June 30, 2008 was approximately $103.4 million, primarily in our Lobo and California regions and we acquired non-operating properties in the San Juan Basin for approximately $29.5 million. Our capital spending during the same period in 2007 was $172.8 million, primarily in the Rocky Mountain and Lobo regions and an acquisition of properties located in the Sacramento Basin of approximately $39 million.

Financing Activities. The primary driver of cash provided by financing activities are equity transactions associated with the exercise of stock options and vesting of restricted 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.

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Capital Expenditures

Our capital expenditures for the six months ended June 30, 2008 decreased by $39.9 million to $132.9 million, versus the comparable period in 2007. During the six months ended June 30, 2008, we participated in the drilling of 71 gross wells, spending approximately $103.4 million, with the majority of these being in the Lobo and California regions and acquired non-operating properties in the San Juan Basin for approximately $29.5 million.

Our positive Operating Cash Flow, along with the availability under our Revolver, is projected to be sufficient to fund our budgeted capital expenditures for 2008, which are currently projected to be approximately $290 million.

Calpine Matters

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 litigation.

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 Risk” in our annual report filed on Form 10-K for the year ended December 31, 2007 and Note 4 included in Part I. Item 1. Financial Statements of this Form 10-Q. There have been no material changes in our exposure to market risk since December 31, 2007.

Item 4.

Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of June 30, 2008. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2008, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

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

PART II. Other Information

Item 1.

Legal Proceedings

We are party to various oil and natural gas litigation matters arising out of the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the consolidated financial statements.

Calpine Bankruptcy

Calpine’s Lawsuit Against Us

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. Through the Lawsuit, Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for these Assets which it estimates to be at least 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 without merit, 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 the Lawsuit, or if necessary, in the appellate courts. The Official Committee of Equity Security Holders and the Official Committee of the Unsecured Creditors both intervened in the Lawsuit for the stated purpose of monitoring the proceedings because the committees claimed to have an interest in the Lawsuit, which we dispute because we believe creditors may 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. Under Calpine’s Plan of Reorganization approved by the Bankruptcy Court on December 19, 2007, the Official Committee of Equity Security Holders was dissolved as of the Plan Effective Date and no longer has any interest in the Lawsuit. While the Unsecured Creditors Committee also was officially dissolved as of the Plan Effective Date, there are provisions under the approved Plan of Reorganization that will allow it to remain involved in lawsuits to which it is a party, which may include this Lawsuit.

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On September 10, 2007, we filed a motion to dismiss the Lawsuit or in the alternative, to stay the Lawsuit. 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. On November 5, 2007, we filed our answer, affirmative defenses and counterclaims with respect to the Lawsuit, denying the allegations set forth in both counts of the Lawsuit, and asserting affirmative defenses to Calpine’s claims as well as affirmative counterclaims against Calpine related to the Acquisition for (i) breach of its covenant of solvency contained in the Purchase and Sale Agreement with respect to the Acquisition and interrelated agreements concurrently executed therewith, dated July 7, 2005, by and among Calpine, us, and various other signatories thereto (collectively, the “Purchase Agreement”), (ii) fraud and fraud in a real estate transaction, (iii) breach of contract, (iv) conversion, (v) civil theft and (vi) setoff.

On July 7, 2008, Rosetta filed a letter with the Bankruptcy Court requesting the required conference with the Court prior to filing a motion for summary judgment. The basis for the motion for summary judgment is that (i) Calpine is not the proper plaintiff because subsidiaries of Calpine, not Calpine, conveyed the oil and gas business to the Company; (ii) to the extent Calpine owned certain oil and gas leases prior to the transaction, the Company. is not the proper defendant because those leases were conveyed to affiliated entities; and (iii) the Company qualifies for safe harbor protection under section 546(e) of the bankruptcy code from and against any fraudulent conveyance claims of Calpine. The Bankruptcy Court has not yet scheduled a conference; therefore, the Company is unable to state for certain when the actual motion for summary judgment will be filed with the Bankruptcy Court. On July 11, 2008, the Company filed a motion to disqualify Calpine’s valuation experts, PA Consulting, due to their conflicts of interest, including without limitation their agreement to receive a success fee as compensation, a violation of the New York ethical rules. A hearing on this motion has been scheduled for August 27, 2008.

Remaining Issues with Respect to the Acquisition

Separate from the Calpine lawsuit, Calpine has taken the position that the Purchase Agreement (and its constituent parts) 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 may 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 may argue 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 would normally have been the date on which Calpine’s Plan of Reorganization was confirmed; however, in order to address certain issues, we and Calpine have agreed to extend this deadline until fifteen days following the entry of a final, unappealable order in the Lawsuit, and the parties set forth this agreement in the Plan of Reorganization approved by the Bankruptcy Court on December 19, 2007.

Open Issues Regarding Legal Title to Certain Properties

Under the Purchase Agreement, Calpine is required to resolve the open issues regarding legal title to interests in certain properties. At the closing of the Acquisition on July 7, 2005, we retained approximately $75 million of the purchase price in respect to leases and wells 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”). The interests in the Non-Consent Properties were not included in the conveyances delivered at the closing of the Acquisition. 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.

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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 have been prepared to conclude the remaining aspects of the Acquisition. We have not included in our statement of operations for the three months ended March 31, 2008 and 2007, estimated net revenues and related estimated production from interests in certain leases and wells being a portion 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. We entered into a new Marketing and Services Agreement (“MSA”) with Calpine Producer Services, L.P. (“CPS”) for a two-year period commencing on July 1, 2007 but which is subject to earlier termination by us on the occurrence of certain events. 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 (collectively, 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 without prejudice to our rights and legal arguments in relation thereto, including our various counterclaims. The PTRA did not otherwise address or resolve open issues with respect to the Non-Consent Properties and certain other properties.

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 and resolved open issues under an audit the State of California had conducted as to these PTRA Properties. We have received the ministerial approval by the MMS for the assignment of Calpine’s interests in MMS Federal Offshore leases for South Pelto 17 and South Timbalier 252 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 experience a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to us, an outcome our management considers to be unlikely upon ultimate disposition, including appeals, if any, then we could experience losses which could have a material adverse effect on our business, financial condition, statement of operations or cash flows.

Sale of Natural Gas to Calpine

In addition to the issues involving legal title to certain properties, we executed, as part of the interrelated agreements that constitute the Purchase Agreement, certain natural gas sales 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 sales agreements. Although Calpine indicated in conjunction with the Plan of Reorganization that it intended to assume the CES natural gas sales agreements with us separate from the Purchase Agreement, we disagree that Calpine may assume anything less than the entire Purchase Agreement and the parties agreed to postpone any dispute on this issue until resolution of the Lawsuit.

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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. In July 2008, the Company notified Calpine it would not be renewing the MSA and, unless it expired sooner by its terms, the MSA would conclude on June 30, 2009.

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 certain oil and natural gas leases 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. Certain of these properties have been subsequently addressed under the PTRA discussed above.

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 (i) 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, as applicable, operator of all of these Federal offshore leases excepting two of them which expired before we received such recognition by MMS, and (ii) any order entered by the Bankruptcy Court be without prejudice to, and fully preserve our rights, claims and legal arguments regarding the characterization and ultimate disposition of the remaining described oil and natural gas properties. In our objection, we also urged the Bankruptcy Court to require the parties to promptly address and resolve any remaining issues under the pre-bankruptcy definitive agreements with Calpine and proposed to the Bankruptcy Court that the parties could seek mediation to complete the following:

Calpine’s conveyance of its retained interests in the Non-Consent Properties to us;

Resolution of the final amounts 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 (excluding the properties subject to third party’s preferential right).

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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 rights to offset any of our damages against any funds we possess that may be owed to Calpine. Until the allowed amount of our claims are finally established and the Bankruptcy Court issues its rulings with respect to Calpine’s approved Plan of Reorganization, we cannot 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 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, 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 the Bankruptcy Court, among other things, resolves open issues in regard to our 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 our 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 had indicated in its filings with the Bankruptcy Court that it believed substantial payments in the form of cash or newly issued stock, or some combination thereof, would 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 amount of allowed claims that remain following the objection process. The Bankruptcy Court approved Calpine’s Plan of Reorganization on December 19, 2007, overruling our objection to the releases granted by this plan to prior and current directors and officers of Calpine and certain of its law firms and other professional advisors. The effective date of the Plan was January 31, 2008.

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:

We extended certain marketing services by executing a new MSA with CPS through and until June 30, 2009, effective as of July 1, 2007. This agreement is subject to earlier termination rights by us upon the occurrence of certain events;

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

We assume all Calpine's rights and obligations for an audit by the CSLC on part of the PTRA Properties; and

We assume all rights and obligations for the PTRA 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) Calpine’s remaining performance under the Purchase Agreement and the amounts that will be payable in connection therewith, (ii) whether or not Calpine and its affiliated debtors will, in fact, perform their remaining obligations in connection with the Purchase Agreement and PTRA; and (iii) the issues pertaining to the Non-Consent Properties.

Arbitration between Calpine/Rosetta 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. With Rosetta’s assistance, 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 had earlier declined to accept the Company’s tender of defense and indemnity when Pogo filed for arbitration against us. We 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. We intend to cooperate with Calpine in defending against Pogo’s claim should it resume; however, it is too early for management to determine whether this matter will affect us, and if so, in what amount. This is due, but not limited to uncertainty concerning (i) whether or not Pogo’s proofs of claim will be fully satisfied by Calpine under its approved Plan of Reorganization; and (ii) whether and if so, the extent to which, Calpine may reimburse us for our claim for our defense costs and any arbitration award regarding the Pogo claim. We have entered into a joint defense agreement with Calpine whereby Calpine has taken over the defense of Pogo’s claims and is indemnifying us.

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Item 1A.

Risk Factors

There have been no material changes in our risk factors from those disclosed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended June 30, 2008

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
April 1 - April 30		441	$	20.16		-		-
May 1 - May 31		1,220		23.84		-		-
June 1 - June 30		1,707		27.82		-		-
Total		3,368	$	25.37		-		-

(1)

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

Issuance of Unregistered Securities

None.

Item3.

Defaults Upon Senior Securities

None.

Item 4.

Submission of Matters to a Vote of Security Holders

On May 9, 2008, we held our Annual Meeting of Shareholders. At the meeting, shareholders voted on election of all of our current directors to serve until the next annual meeting of shareholders. The following is a summary of the votes on this item:

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	Votes For		Votes Withheld
Randy L. Limbacher		48,612,384		275,257
Josiah O. Low, III		48,528,225		359,416
Richard W. Beckler		48,528,098		359,543
D. Henry Houston		48,526,948		360,693
Donald D. Patteson, Jr.		48,520,631		367,010

With respect to the ratification of the appointment of the Company’s Independent Public Accounting Firm, PricewaterhouseCoopers LLP for 2008, the following is a summary of the votes on this item:

For

48,836,340

Against

38,095

Abstain

13,203

With respect to Proposal No. 3, approval of an amendment to the Company’s 2005 Long-Term Incentive Plan to increase the number of shares of the Company’s common stock available for awards from 3, 000,000 to 4,950,000 the following is the summary of the votes on this item:

For

41,325,142

Against

3,102,025

Abstain

16,160

Item 5.

Other Information

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

(b)

There have been no material changes to the procedures by which securities holders may recommend nominees to our board of directors since our most recent disclosure of such procedures contained in our Annual Report on Form 10-K for the year ended December 31, 2007 and our definitive proxy statement filed with respect to our 2008 annual meeting.

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Item 6. Exhibits

3.1		Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).

3.2		Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).

4.1		Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).

10.40†*		Non-Executive Employee Change of Control Plan attached hereto as Exhibit 10.40.

10.41†*		Non-Executive Employee Severance Plan attached hereto as Exhibit 10.41.

10.42*		Fourth Amendment to Senior Revolving Credit Agreement attached hereto as Exhibit 10.42.

10.43*		Fourth Amendment to Second Lien Term Loan Agreement attached hereto as Exhibit 10.43.

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

____________________________________

*	Filed herewith

†	Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

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SIGNATURES

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

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

	(Duly Authorized Officer and Principal Financial Officer)

Date: August 8, 2008

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ROSETTA RESOURCES INC.

EXHIBIT INDEX

Exhibit Number		Description
10.40		Non-Executive Employee Change of Control Plan
10.41		Non-Executive Employee Severance Plan
10.42		Fourth Amendment to Senior Revolving Credit Agreement
10.43		Fourth Amendment to Second Lien Term Loan Agreement
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