Edgar Filing: Rosetta Resources Inc.

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended June 30, 2009

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

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)


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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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 x	Accelerated filer o

Non-Accelerated filer o	Smaller Reporting Company o
(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 o No x

The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of August 5, 2009 was 52,355,689.

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	16
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	25
	Item 4. Controls and Procedures	25
Part II –
	Other Information	26
	Item 1. Legal Proceedings	26
	Item 1A. Risk Factors	26
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	26
	Item 3. Defaults upon Senior Securities	26
	Item 4. Submission of Matters to a Vote of Security Holders	27
	Item 5. Other Information	27
	Item 6. Exhibits	28
Signatures		29

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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, 2009			December 31, 2008
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	49,520		$	42,855
Restricted cash		-			1,421
Accounts receivable		28,814			41,885
Derivative instruments		41,908			34,742
Prepaid expenses		4,615			5,046
Other current assets		3,483			4,071
Total current assets		128,340			130,020
Oil and natural gas properties, full cost method, of which $22.7 million at June 30, 2009 and $50.3 million at December 31, 2008 were excluded from amortization		1,953,764			1,900,672
Other fixed assets		11,588			9,439
		1,965,352			1,910,111
Accumulated depreciation, depletion, and amortization, including impairment		(1,402,315	)		(935,851	)
Total property and equipment, net		563,037			974,260

Deferred loan fees		5,829			1,168
Deferred tax asset		180,039			42,652
Other assets		5,703			6,278
Total other assets		191,571			50,098
Total assets	$	882,948		$	1,154,378

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	153		$	2,268
Accrued liabilities		14,188			48,824
Royalties payable		16,126			17,388
Derivative instruments		57			985
Prepayment on gas sales		8,795			19,382
Deferred income taxes		15,590			12,575
Total current liabilities		54,909			101,422
Long-term liabilities:
Derivative instruments		38			-
Long-term debt		298,514			300,000
Asset retirement obligation		30,312			26,584
Total liabilities		383,773			428,006

Commitments and contingencies (Note 9)		-			-

Stockholders' equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2009 or 2008		-			-
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 51,163,118 shares and 51,031,481 shares at June 30, 2009 and December 31, 2008, respectively		51			51
Additional paid-in capital		776,502			773,676
Treasury stock, at cost; 181,946 and 155,790 shares at June 30, 2009 and December 31, 2008, respectively		(3,242	)		(2,672	)
Accumulated other comprehensive income		28,725			24,079
Accumulated deficit		(302,861	)		(68,762	)
Total stockholders' equity		499,175			726,372
Total liabilities and stockholders' equity	$	882,948		$	1,154,378

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,
	2009			2008			2009			2008
Revenues:
Natural gas sales	$	67,087		$	136,142		$	141,311		$	248,587
Oil sales		6,463			18,325			11,681			34,213
Total revenues		73,550			154,467			152,992			282,800
Operating Costs and Expenses:
Lease operating expense		16,568			14,174			34,609			27,588
Depreciation, depletion, and amortization		28,499			51,738			72,900			103,152
Impairment of oil and gas properties		-			-			379,462			-
Treating and transportation		1,101			1,539			2,803			2,843
Marketing fees		241			1,016			559			1,764
Production taxes		1,750			5,754			3,074			9,192
General and administrative costs		12,571			13,516			21,944			25,623
Total operating costs and expenses		60,730			87,737			515,351			170,162
Operating income (loss)		12,820			66,730			(362,359	)		112,638

Other (income) expense
Interest expense, net of interest capitalized		6,106			4,470			8,641			8,024
Interest income		(25	)		(317	)		(76	)		(556	)
Other (income) expense, net		310			(89	)		160			(131	)
Total other expense		6,391			4,064			8,725			7,337

Income (loss) before provision for income taxes		6,429			62,666			(371,084	)		105,301
Provision for income taxes		2,394			23,351			(136,983	)		38,497
Net income (loss)	$	4,035		$	39,315		$	(234,101	)	$	66,804

Earnings (loss) per share:
Basic	$	0.08		$	0.78		$	(4.60	)	$	1.32
Diluted	$	0.08		$	0.77		$	(4.60	)	$	1.31

Weighted average shares outstanding:
Basic		50,969			50,585			50,945			50,547
Diluted		51,079			50,961			50,945			50,873

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,
	2009			2008
Cash flows from operating activities
Net income (loss)	$	(234,101	)	$	66,804
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization		72,900			103,152
Impairment of oil and gas properties		379,462			-
Deferred income taxes		(137,131	)		38,262
Amortization of deferred loan fees recorded as interest expense		1,163			590
Amortization of original issue discount recorded as interest expense		114			-
Stock compensation expense		2,826			3,677
Other non-cash items		-			(166	)
Change in operating assets and liabilities:
Accounts receivable		13,071			(32,287	)
Prepaid expenses		431			5,022
Other current assets		588			357
Other assets		(77	)		186
Accounts payable		(2,115	)		4,769
Accrued liabilities		(8,179	)		2,578
Royalties payable		(11,849	)		21,045
Net cash provided by operating activities		77,103			213,989
Cash flows from investing activities
Acquisition of oil and gas properties		(3,844	)		(29,503	)
Purchases of oil and gas assets		(76,167	)		(119,594	)
Disposals of oil and gas properties and assets		16,146			27
Decrease in restricted cash		1,421			-
Net cash used in investing activities		(62,444	)		(149,070	)
Cash flows from financing activities
Borrowings on revolving credit facility		28,400			-
Payments on revolving credit facility		(30,000	)		-
Deferred loan fees		(5,824	)		-
Proceeds from stock options exercised		-			2,898
Purchases of treasury stock		(570	)		(265	)
Net cash (used in) provided by financing activities		(7,994	)		2,633

Net increase in cash		6,665			67,552
Cash and cash equivalents, beginning of period		42,855			3,216
Cash and cash equivalents, end of period	$	49,520		$	70,768

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	1,458		$	19,450

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”) is an independent oil and gas company that is engaged in oil and natural gas exploration, development, production and acquisition activities in the United States. The Company’s main operations are primarily concentrated in the Sacramento Basin of California, the Rockies, 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 Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 ("2008 Annual Report"). In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through August 6, 2009, the date the financial statements were issued, and have concluded that there were no subsequent events.

Certain reclassifications of prior year balances have been made to conform them to the current year presentation. These reclassifications have no impact on net income (loss).

(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, 2008.

Principles of Consolidation. The accompanying consolidated financial statements as of June 30, 2009 and December 31, 2008 and for the three and six months ended June 30, 2009 and 2008 contain the accounts of the Company and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.

Recent Accounting Developments

The following recently issued accounting developments have been applied or may impact the Company in future periods.

Business Combinations. In December 2007, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) broadens the guidance of SFAS No. 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. SFAS No. 141(R) also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases. This could cause us to expense transaction costs for future oil and gas property purchases that we have historically capitalized. Additionally, SFAS No. 141(R) expands the required disclosures to improve the statement users’ abilities to evaluate the nature and financial effects of business combinations. SFAS No. 141(R) is effective for business combinations for which the acquisition date is on or after January 1, 2009. The adoption of SFAS No. 141(R) did not have a significant impact on our consolidated financial position, results of operations or cash flows.

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 adoption of SFAS No. 160 did not have a significant impact on our consolidated financial position, results of operations or cash flows.

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 adopted the disclosure requirements of SFAS No. 161 beginning January 1, 2009. See Note 4 - Commodity Hedging Contracts and Other Derivatives.

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Fair Value Measurements. In February 2008, the FASB issued FASB Staff Position (“FSP”) 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. Beginning January 1, 2009, we implemented FSP No. 157-2 for nonfinancial assets and liabilities. The adoption of FSP No. 157-2 did not have an impact on our consolidated financial position, results or operations or cash flows. In October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP No. 157-3”). This FSP clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. This FSP was effective upon issuance, including prior periods for which financial statements have not been issued. We applied this FSP to financial assets measured at fair value on a recurring basis at September 30, 2008. See Note 5 - Fair Value Measurements. The adoption of FSP No. 157-3 did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In April 2009, the FASB issued three FSPs to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157. FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. These three FSPs are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We applied these FSPs for the period ended June 30, 2009, and the adoption of these FSPs did not have a significant impact on the Company’s consolidated financial position, results of operations or cash flows.

Subsequent Events. In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS No. 165”), to incorporate accounting guidance that originated as auditing standards into the body of authoritative literature issued by the FASB. SFAS No. 165 requires the evaluation of subsequent events through the date the financial statements are issued or are available for issue and the disclosure of the date through which subsequent events were evaluated and the basis for that date. This statement is effective for interim and annual financial periods ending after June 15, 2009. The Company adopted the requirements of SFAS No. 165 for the period ending June 30, 2009. The adoption of SFAS No. 165 did not have a significant impact on our consolidated financial position, results of operations or cash flows. See Note 1 – Organization and Operations of the Company.

FASB Codification. In July 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (“GAAP”) (as amended)” (“SFAS No. 168”), making the FASB Accounting Standards Codification the single source of authoritative nongovernmental U.S. GAAP. The Codification is not intended to change GAAP, however, it will represent a significant change in researching issues and referencing U.S. GAAP in financial statements and accounting policies. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

Oil and Gas Reporting Requirements. In December 2008, the SEC released Release No. 33-8995, “Modernization of Oil and Gas Reporting” (the “Release”). The disclosure requirements under this Release will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in Securities and Exchange Commission ("SEC") filings. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The new disclosure requirements become effective for the Company beginning with our annual report on Form 10-K for the year ending December 31, 2009. The SEC has indicated that it may delay the effective date of the revised reporting requirements if the FASB does not make conforming amendments by December 31, 2009. We are currently evaluating the impact of this Release on our oil and gas accounting disclosures.

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(3) Property, Plant and Equipment

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

	June 30, 2009			December 31, 2008
	(In thousands)
Proved properties	$	1,893,849		$	1,813,527
Unproved/unevaluated properties		22,685			50,252
Gas gathering systems and compressor stations		37,230			36,893
Other		11,588			9,439
Total oil and natural gas properties		1,965,352			1,910,111
Less: Accumulated depreciation, depletion, and amortization		(1,402,315	)		(935,851	)
Total property and equipment, net	$	563,037		$	974,260

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $0.9 million and $1.4 million of internal costs for the three months ended June 30, 2009 and 2008, respectively, and $1.8 million and $2.8 million for the six months ended June 30, 2009 and 2008, respectively.

Included in the Company’s oil and gas properties are asset retirement costs of $24.4 million and $23.2 million at June 30, 2009 and December 31, 2008, respectively.

Oil and gas properties include costs of $22.7 million and $50.3 million at June 30, 2009 and December 31, 2008, 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.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center. The Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at March 31 and June 30, 2009, which were based on a Henry Hub price of $3.63 per MMBtu and $3.89 per MMBtu, respectively, and a West Texas Intermediate oil price of $46.00 per Bbl and $66.25 per Bbl (adjusted for basis and quality differentials), respectively, compared to prices of $5.71 per MMBtu and $41.00 per Bbl at December 31, 2008. Cash flow hedges of natural gas production in place at March 31 and June 30, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax) and $55.3 million (pre-tax), respectively. Based upon these analyses, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009 and the Company did not record a write-down at June 30, 2009. It is possible that another write-down of the Company's oil and gas properties could occur in the future should oil and natural gas prices decline, the Company experiences significant downward adjustments to the estimated proved reserves, and/or the Company's commodity hedges settle and are not replaced.

The Company generated $16.1 million of proceeds from divestitures of oil and gas properties and assets in non-core operating areas during the quarter ended June 30, 2009. Of these divestitures, $15.4 million were recorded as credits to the full cost pool with no gain or loss recognized and $0.7 million related to the sale of compressors which were not included in the pool for which an immaterial loss on sale was recorded.

(4) Commodity Hedging Contracts and Other Derivatives

The following financial fixed price swap and costless collar transactions were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations at June 30, 2009:

Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu		Average Ceiling Prices per MMBtu		Natural Gas Production Hedged (1)			Fair Market Value Asset/(Liability) (In thousands)
2009	Swap	Cash flow		52,141		9,593,944	$	7.65	$	-		37	%	$	33,427
2009	Costless Collar	Cash flow		5,000		920,000		8.00		10.05		4	%		3,584
2010	Swap	Cash flow		10,000		3,650,000		8.31		-		9	%		8,829
						14,163,944								$	45,840

(1)

Estimated based on anticipated future gas production.

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The Company has hedged the interest rates on $100.0 million of its outstanding debt from September 30, 2009 through December 31, 2010. As of June 30, 2009, the Company had the following financial interest rate swap position outstanding:

Settlement Period	Derivative Instrument	Hedge Strategy		Average Fixed Rate				Fair Market Value Asset/(Liability) (In thousands)
September 30, 2009 - December 31, 2010	Swap	Cash Flow			1.24	%		$	(64	)

The Company’s current cash flow hedge positions are with counterparties who are also 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, 2009, the Company made no deposits for collateral.

The following table sets forth the results of hedge transaction settlements for the respective period for the Consolidated Statement of Operations:

	Three Months Ended June 30,					Six Months Ended June 30,
Natural Gas	2009		2008			2009		2008
Quantity settled (MMBtu)		5,199,831		6,636,216			10,342,521		12,792,432
Increase (decrease) in natural gas sales revenue (In thousands)	$	21,802	$	(16,595	)	$	37,159	$	(17,296	)
Interest Rate Swaps
Increase in interest expense (In thousands)	$	522	$	335		$	1,034	$	460

The Company expects to reclassify gains of $41.9 million as of June 30, 2009 to earnings from the balance in accumulated other comprehensive income on the Consolidated Balance Sheet during the next twelve months.

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivative instruments are commodity price risk and interest rate risk. Forward contracts on various commodities are entered into to manage the price risk associated with forecasted sales of the Company’s natural gas and oil production. Interest rate swaps are entered into to manage interest rate risk associated with the Company’s variable-rate borrowings.

SFAS No. 133, as amended, requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the statement of financial position. In accordance with SFAS No. 133, as amended, the Company designates commodity forward contracts as cash flow hedges of forecasted sales of natural gas and oil production and interest rate swaps as cash flow hedges of interest rate payments due under variable-rate borrowings.

Additional Disclosures about Derivative Instruments and Hedging Activities

Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

As of June 30, 2009, the Company had outstanding natural gas commodity forward contracts with a notional volume of 14,163,944 MMBtus that were entered into to hedge forecasted natural gas sales.

As of June 30, 2009, the total notional amount of the Company’s receive-variable/pay-fixed interest rate swaps was $100.0 million. The Company includes the realized gain or loss on the hedged items (that is, interest on variable-rate borrowings) in the same line item – interest expense, net of interest capitalized – as the offsetting gain or loss on the related interest rate swaps.

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Information on the location and amounts of derivative fair values in the statement of financial position and derivative gains and losses in the statement of financial performance as of June 30, 2009 is as follows:

	Fair Values of Derivative Instruments

	Derivative Assets			Derivative Liabilities

	June 30, 2009			June 30, 2009
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133		(in thousands)			(in thousands)

Interest rate swap	Derivative Instruments	$	-	Derivative Instruments	$	57
Interest rate swap	Derivative Instruments		-	Derivative Instruments		38
Interest rate swap	Other assets		31	Derivative Instruments		-
Commodity contracts	Derivative Instruments		41,908	Derivative Instruments		-
Commodity contracts	Other assets		3,932	Derivative Instruments		-

Total derivatives designated as hedging instruments under SFAS No. 133		$	45,871		$	95

Total derivatives not designated as hedging instruments under SFAS No. 133		$	-		$	-


Total derivatives		$	45,871		$	95

Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)			Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)			Location of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)			Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009				Three Months Ended June 30, 2009		Six Months Ended June 30, 2009				Three Months Ended June 30, 2009			Six Months Ended June 30, 2009

Interest rate swap	$	(110	)	$	(144	)	Interest expense, net of interest capitalized	$	-	$	(512	)	Interest expense, net of interest capitalized	$	(522	)	$	(522	)
Commodity contracts		4,540			43,673		Natural gas sales		21,802		37,159		Natural gas sales		-			-

Total	$	4,430		$	43,529			$	21,802	$	36,647			$	(522	)	$	(522	)

(1)

The amount of gain or (loss) recognized in income represents $0.5 million related to the ineffective portion of the hedging relationships. Nothing was excluded from the assessment of hedge effectiveness.

On April 9, 2009, the Company entered into an amended and restated revolving credit agreement replacing the previous revolving credit agreement. At the time of the amended and restated revolving credit agreement, the Company had two outstanding interest rate swaps which established a fixed interest rate for a portion of the previous outstanding revolver that were designated as cash flow hedges and which became ineffective. The Company ceased cash flow hedge accounting for these interest rate swaps which resulted in approximately $0.5 million in interest expense. Because these swaps were to mature during the quarter ended June 30, 2009, the Company did not recognize any unrealized mark to market gains or losses within the Consolidated Statement of Operations related to the swaps during the period. There were no gains or losses recognized in income representing hedge components excluded from the assessment of effectiveness.

(5) Fair Value Measurements

The Company adopted SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) effective January 1, 2008 for financial assets and liabilities and effective January 1, 2009 for non-financial assets and liabilities. 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”). To estimate fair value, 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 the fair value hierarchy 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.

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–

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 money market funds, natural gas swaps, natural gas zero cost collars and interest rate swaps. The Company’s money market funds represent cash equivalents whose investments are limited to United States Government Securities, securities backed by the United States Government, or securities of United States Government agencies. The fair value represents cash held by the fund manager as of June 30, 2009. The Company identified the money market funds as Level 3 instruments due to the fact that quoted prices for the underlying investments cannot be obtained and there is not an active market for the underlying investments. The Company utilizes counterparty and third party broker quotes to determine the valuation of its derivative instruments. Fair values derived from counterparties and brokers are further verified using the closing price as of June 30, 2009 for the relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location.

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, 2009. 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.

	At fair value as of June 30, 2009 (In thousands)
	Level 1		Level 2		Level 3			Total
Assets (Liabilities):
Money market funds		-		-		2,034			2,034
Commodity derivative contracts		-		-		45,840			45,840
Interest rate swap contracts		-		-		(64	)		(64	)
Total		-		-		47,810			47,810

The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements and the impact of the Company’s nonperformance risk on its liabilities. The Company considered credit adjustments for the counterparties using current credit default swap values and default probabilities for each counterparty in determining fair value.

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy during the six months ended June 30, 2009. Level 3 instruments presented in the table consist of net derivatives that, in management’s judgment, reflect the assumptions a marketplace participant would have used at June 30, 2009.

	Derivatives Asset (Liability) (In thousands)			Money Market Funds Asset (Liability) (In thousands)			Total (In thousands)
Balance as of January 1, 2009	$	38,372		$	5,025		$	43,397
Total (gains) losses (realized or unrealized)
included in earnings		-			9			9
included in other comprehensive income		43,529			-			43,529
Purchases, issuances and settlements		(36,125	)		(3,000	)		(39,125	)
Transfers in and out of level 3		-			-			-
Balance as of June 30, 2009	$	45,776		$	2,034		$	47,810

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at June 30, 2009	$	-		$	-		$	-

The carrying amount of long-term debt reported in the consolidated balance sheet at June 30, 2009 is $298.5 million. The Company calculated the fair value of its long-term debt as of June 30, 2009, in accordance with SFAS No. 157 using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality, and risk profile. The Company has determined the carrying value of its debt to approximate fair market value at June 30, 2009 due to the recent redetermination.

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(6) Asset Retirement Obligation

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

	Six Months Ended June 30, 2009
	(In thousands)
ARO as of December 31, 2008	$	27,944
Revision of previous estimates		(394	)
Liabilities incurred during period		1,781
Liabilities settled/divested during period		(235	)
Accretion expense		1,216
ARO as of June 30, 2009	$	30,312

(7) Long-Term Debt

On April 9, 2009, the Company entered into an Amended and Restated Senior Revolving Credit Agreement with BNP Paribas, as Administrative Agent, and the other lenders identified therein (“Restated Revolver”) providing a senior secured revolving line of credit in the amount of up to $600.0 million, replacing the prior revolving credit agreement, and extending its term until July 1, 2012. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements. The borrowing base under the Restated Revolver is currently set at $375.0 million. The next borrowing base review is scheduled for October 2009. Amounts outstanding under the Restated Revolver bear interest, as amended, at specified margins over London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of the Company’s domestic subsidiaries, and a pledge of 100% of the membership interests of domestic subsidiaries. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is 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. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company paid a facility fee on the total commitment of $4.6 million. As of August 6, 2009, the Company has $200.0 million outstanding with $175.0 million available for borrowing under the revolving line of credit.

On April 9, 2009, the Company also entered into an Amended and Restated Second Lien Term Loan Agreement with BNP Paribas, as Administrative Agent, and other lenders identified therein (“Restated Term Loan”) replacing the prior Term Loan extending its term until October 2, 2012. Borrowings under the Restated Term Loan were initially set at $75.0 million and bear interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%. The Restated Term Loan had an option to increase fixed and floating rate borrowings by up to $25.0 million to $100.0 million prior to May 9, 2009. The Company exercised this option on April 21, 2009 and the increased borrowings consisted of $5.0 million of floating rate borrowings and $20.0 million of fixed rate borrowings at 13.75%. The loan is collateralized by second priority liens on substantially all of the Company’s assets. The Company is 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. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company paid an original issue discount of $1.6 million and a facility fee of $0.9 million on the total commitment. As of June 30, 2009, the Company had $80.0 million of variable rate borrowings and $20.0 million of fixed rate borrowings outstanding under the Restated Term Loan.

As of June 30, 2009, the Company had total outstanding borrowings of $298.5 million. At June 30, 2009, the Company’s weighted average borrowing rate was 4.92%. Net borrowing availability under the Revolver was $175.0 million at June 30, 2009. The Company was in compliance with all covenants at June 30, 2009.

As of June 30, 2009, all amounts drawn under the Restated Revolver are due and payable on July 1, 2012. The principal balance associated with the Restated Term Loan is due and payable on October 2, 2012.

(8) Income Taxes

As of June 30, 2009, the Company had no unrecognized tax benefits. The effective tax rate for the three and six months ended June 30, 2009 was 37.2% and 36.9%, respectively. The effective tax rate for the three and six months ended June 30, 2008 was 37.3% and 36.6%, 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. The income tax benefit for the six months ended June 30, 2009 includes a $1.0 million downward adjustment recorded in the three months ended March 31, 2009 related to 2008 state taxes.

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The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. At June 30, 2009, the Company has a deferred tax asset of approximately $180.0 million resulting primarily from the difference between the book basis and tax basis of its oil and natural gas properties. The Company believes that it is more likely than not that this deferred tax asset will be realized through future taxable income generated by the production of its oil and natural gas properties.

(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.

(10) Comprehensive Income (Loss)

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

	Three Months Ended June 30,												Six Months Ended June 30,
	2009						2008						2009					2008
	(In thousands)
Accumulated other comprehensive (loss) income beginning of period				$	39,298					$	(48,539	)				$	24,079				$	(7,225	)
Net income (loss)		4,035						39,315						(234,101	)				66,804

Change in fair value of derivative hedging instruments		4,430						(93,771	)					43,529					(160,435	)
Hedge settlements reclassed to income		(21,280	)					16,930						(36,125	)				17,756
Tax provision related to hedges		6,277						28,624						(2,758	)				53,148
Total other comprehensive (loss) income		(10,573	)		(10,573	)		(48,217	)		(48,217	)		4,646			4,646		(89,531	)		(89,531	)

Comprehensive loss		(6,538	)					(8,902	)					(229,455	)				(22,727	)
Accumulated other comprehensive income (loss)				$	28,725					$	(96,756	)				$	28,725				$	(96,756	)

(11) Earnings (Loss) 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,
	2009		2008		2009		2008
	(In thousands)
Basic weighted average number of shares outstanding		50,969		50,585		50,945		50,547
Dilution effect of stock option and awards at the end of the period		110		376		-		326
Diluted weighted average number of shares outstanding		51,079		50,961		50,945		50,873

Anti-dilutive stock awards and shares		1,952		313		1,947		287

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Because the Company reported a loss from continuing operations for the six months ended June 30, 2009, no unvested stock awards and options were included in computing loss per share because the effect was anti-dilutive. In computing loss per share, no adjustments were made to reported net loss.

(12) Stock-Based Compensation

Performance Share Units

Pursuant to the approved Amended and Restated 2005 Long-Term Incentive Plan, the Company’s Compensation Committee agreed to allocate a portion of the 2009 long-term incentive grants to executives as performance share units (“PSUs”). The PSUs are payable, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock at settlement based on the achievement of certain performance metrics at the end of a three-year performance period. At the end of the three-year performance period, the number of shares vested can range from 0% to 200% of the targeted amount as determined by the Compensation Committee of the Board of Directors. The PSUs have no voting rights. PSUs may be vested solely at the discretion of the Board in the event of a participant’s involuntary termination of employment for reasons other than cause or termination for good reason but will be forfeited in the event of the participant’s voluntary termination or involuntary termination for cause. Any PSUs not vested by the Board at the end of a performance period will expire.

Compensation expense associated with PSUs that continue to vest based on future performance is based on the grant-date fair value of the Company’s common stock. The compensation expense will be re-measured at the end of each reporting period through settlement using the quarter-end closing common stock prices to reflect the current fair value. Compensation expense is to be recognized ratably over the performance period based on the Company’s estimated achievement of the established performance metrics. Compensation expense will only be recognized for those awards for which it is probable that the performance metrics will be achieved and which are expected to vest. The compensation expense will be estimated based upon an assessment of the probability that the performance metrics will be achieved, current and historical forfeitures, and the Board’s anticipated vesting percentage.

The Company granted 350,698 PSUs on March 3, 2009, and at June 30, 2009, no additional PSUs had been granted nor had any vested or forfeited and the fair value per unit was $8.94. For the quarter and six months ended June 30, 2009, the Company did not recognize any compensation expense associated with the PSUs.

(13) 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 six main geographic areas all within the United States or its territorial waters. Geographic revenue and property, plant and equipment information below are based on physical location of the assets at the end of each period.

Oil and Natural Gas Revenue

The table below presents the Company’s gross oil and natural gas revenues by geographic area.

	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
	(In thousands)
California	$	13,582	$	43,816		$	32,761	$	80,587
Rockies		4,791		9,557			11,401		16,407
South Texas		22,999		70,524			46,182		114,756
Texas State Waters		3,142		15,705			7,405		30,737
Other Onshore		4,181		14,122			10,207		25,404
Gulf of Mexico		3,053		17,336			7,877		32,204
Gain (loss) on hedges		21,802		(16,593	)		37,159		(17,295	)
Total revenue	$	73,550	$	154,467		$	152,992	$	282,800

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Oil and Natural Gas Properties

The table below presents the Company’s gross oil and natural gas properties by geographic area and other fixed assets.

	June 30, 2009		December 31, 2008
	(In thousands)
California	$	626,280	$	619,593
Rockies		183,447		175,294
South Texas		750,395		712,464
Texas State Waters		65,976		65,085
Other Onshore		176,188		171,855
Gulf of Mexico		151,478		156,381
Other		11,588		9,439
Total property and equipment	$	1,965,352	$	1,910,111

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking information regarding Rosetta that is intended to be covered by the “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, 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 Part II. of 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:

–	general economic conditions, either internationally, nationally or in jurisdictions affecting our business;

–	conditions in the energy and economic markets;

–	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;

–	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;

–	failure of our joint interest partners to fund any or all of their portion of any capital program;

–	the occurrence of property acquisitions or divestitures;

–	reserve levels;

–	inflation;

–	the supply and demand for natural gas and oil;

–	the price of natural gas and oil;

–	competition in the natural gas and oil industry;

–	the availability and cost of relevant raw materials, goods and services;

–	the availability and cost of processing and transportation;

–	changes or advances in technology;

–	potential reserve revisions;

–	future processing volumes and pipeline throughput;

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

–	drilling and exploration risks;

–

several possible new legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to, national healthcare, cap and trade, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, changes in environmental regulations, environmental risks and liability under federal, state and foreign environmental laws and regulations;

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

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–	present and possible future claims, litigation and enforcement actions;

–	lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;

–	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.

Overview

The following discussion addresses material changes in the results of operations for the three and six months ended June 30, 2009 compared to the three and six months ended June 30, 2008, and the material changes in financial condition since December 31, 2008. It is presumed that readers have read or have access to our 2008 Annual Report, which includes, as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations, disclosures regarding critical accounting policies.

The following summarizes our performance for the first six months of 2009 as compared to the same period for 2008:

Production on an equivalent basis decreased 1%;

Total revenue, including the effects of hedging, decreased $129.8 million or 46%;

Average realized gas prices including hedging decreased $4.14 per Mcf, or 43%, to $5.39 per Mcf at June 30, 2009 from $9.53 per Mcf at June 30, 2008 and average realized oil prices decreased $65.09 per Bbl, or 58%, to $46.76 per Bbl at June 30, 2009 from $111.85 per Bbl at June 30, 2008;

A non-cash impairment of oil and gas properties of $379.5 million pre-tax ($238.1 million net of tax) was recorded during the first quarter due to the continuing decline in natural gas prices;

Net income decreased $300.9 million to a net loss of $234.1 million; net income excluding impairment would have decreased $62.8 million to net income of $4.0 million;

Diluted earnings per share decreased $5.91 to diluted loss per share of $4.60; diluted earnings per share excluding impairment would have decreased $1.23 per share from $1.31 per share to $0.08 per share; and

27 gross (20 net) wells were drilled with a net success rate of 85% compared to 71 gross (61 net) wells drilled with a net success rate of 83% for the comparable period in 2008.

In early 2008, we began a strategic shift toward a business model that we believed could generate more sustainable, predictable performance over time by focusing on positions and programs in unconventional onshore domestic basins. These basins are characterized by having lower hydrocarbon risk project inventory and repeatable programs. Our strategy shift is accompanied by goals to deliver, over time, both acceptable rates of production growth, as well as growth in proved, probable and possible reserves. The timing of and extent to which we can implement this strategy shift will depend on several factors, most notably commodity prices, availability of and access to credit, and ability to capture organic and inorganic opportunities.

Under commodity price scenarios of approximately $6.00 per Mcfe or greater, we believe we can successfully implement our strategy shift because of some inherent strengths. Of note, we believe our core existing onshore assets have upside that has not been fully analyzed through an unconventional resource approach. We think this approach could yield additional inventory for the Company over time. In addition, we have an experienced workforce and management team with background in unconventional resource operations. Finally, we have a financial and capital allocation approach that we believe allows us to adapt to the unpredictable industry cycles and manage through the current economic downturn. These factors do not ensure our success in executing our strategy shift, but we believe they provide a competitive advantage towards executing our strategy shift over the longer term. Under an extended period of commodity prices below $5.00 per Mcfe, our ability to implement our business strategy would likely be constrained. Due to our hedging program, we currently have a market price of greater than $5.00 per Mcfe for a portion of our production which will continue through the end of 2009. Management continuously analyzes and evaluates possible actions that could be taken if a protracted low price environment persists with a focus on preserving an acceptable level of liquidity and cash flow through 2010.

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The current plan for implementing our business strategy is to pursue, over time, both organic and inorganic opportunities that meet the Company’s criteria for funding, particularly inventory potential and attractive financial returns. In 2008, we began several studies to test organic concepts in areas where we currently have assets for the purpose of identifying possible upside and inventory. These studies are continuing in 2009. We also actively study new domestic basins where we believe the Company can compete successfully. While we have a preference for organic opportunities, we have expanded our capability to evaluate and pursue large and small acquisition opportunities that make sense for the Company. We believe this balanced approach is needed for long-term success. Our ability to execute inorganic activities will depend on market conditions, including availability of acquisition opportunities, relative valuations, and access to funding sources that could include proceeds from non-core asset divestitures, as well as proceeds from capital market activities. Thus far in 2009, we have generated $16.1 million of proceeds from non-core divestitures, and we continue to test the market for additional non-core divestitures; however, we are not driven to sell assets unless values are compelling.

We entered 2009 in a position to execute our business plan and effect our desired goals, subject to commodity prices and market factors. During the first half of 2009 these factors have generally weakened. The outlook for commodity prices continues to be uncertain due to a sluggish economic outlook for the year, which has resulted in reduced demand for natural gas and commodity oversupply. Given this outlook, we continue to exercise prudence and caution with our capital spending in order to preserve liquidity and maximize the financial position of the Company. The priority for our 2009 organic spending is to spend less than our internally generated cash flow. We have the discretion to adjust capital spending, either up or down, throughout the year in response to market conditions, the availability of proceeds from possible divestitures, access to attractive acquisitions, and follow-on to success in our organic programs. We expect our organic capital spending level will be significantly reduced compared to our preliminary 2009 budget and 2008 actual spending. At this time, we intend to drill a limited number of Lobo wells in South Texas, continue a recompletion program in the Sacramento Basin, and test two new exploratory play concepts in the Bakken Shale in the Alberta Basin and the Eagle Ford Shale in South Texas. Given the uncertainty in our capital program and possible divestiture results, it is not practical to provide definitive production guidance for 2009. However, with projected organic capital spending in 2009 of $115.0 million, we would expect to achieve between 130 – 140 MMcfe/d of full-year 2009 production, excluding acquisitions and divestitures. Typically, we do not provide detailed guidance on other metrics, such as revenues or costs. Given current uncertainties in the marketplace, it is more likely than usual that trends will be difficult to predict. However, given declining volumes, unit costs are likely to increase.

We are operating in one of the most challenging business environments in recent history. The credit crisis, lower natural gas prices and a weak domestic and global economic outlook are all adversely impacting the business environment. We intend to work continuously with our lenders to effectively stay abreast of market and creditor conditions to ensure prudent and timely decisions should market conditions deteriorate further. With the amendments and restatements of our credit agreements in April 2009, we extended the maturities of our credit facilities to 2012. We believe that we have sufficient liquidity and operational flexibility to carry out a prudent organic capital expenditures program in 2009. Our capital program for 2010 has not yet been determined, but the planning exercise is underway. The level of capital spending will be determined by available cash flows from operating activities, access to liquidity, and proceeds from possible property divestitures. To the extent that capital expenditures or prudent acquisitions require cash flow in excess of available funds, we would consider drawing on our unused capacity under our existing revolving credit facility. As of June 30, 2009, the undrawn credit available to us was $175.0 million. We have not received any indication from our lenders that draws under the credit facility are restricted below current availability at this time, and we are proactively communicating with them on a routine basis. During April 2009, we re-affirmed our borrowing base at $375.0 million reduced from $400.0 million. The next borrowing base review is scheduled for October 2009. Additionally, we amended and restated our second lien term loan, which allowed us to increase our borrowings under the facility from $75.0 million to $100.0 million. We believe these actions provide capacity and time for managing through the current downturn. During the second quarter of 2009, we filed a universal shelf registration statement with the SEC, thereby positioning Rosetta to raise additional funds in the capital markets as deemed appropriate. We currently do not have any stated plans to issue securities but would consider doing so under certain circumstances, notably to fund an attractive acquisition or to fund follow-on development activities in our prospective organic Eagle Ford and/or Bakken plays, should either or both of these plays be successful.

Our capital expenditures are primarily in areas where we are operator and have high working interests. As a result, we do not believe we have significant exposure to joint interest partners who may be unable to fund their portion of any capital program, but we are monitoring partner situations in light of the current economic environment. We are actively working with service companies and suppliers to mitigate costs, and we are examining all cash costs for improved efficiency.

All counterparties to our derivative instruments are participants in our credit facilities, and we have not received any indication that any of these counterparties are unable to perform their required obligations under the terms of the derivative contracts, although we are mindful that this could change and are staying alert for such changes. Similarly, we have not received any indication that any of the banks participating in the existing bank facility are incapable of performing their obligations under the terms of the credit agreement.

Finally, with respect to the current market environment for liquidity and access to credit, we, through banks participating in our credit facility, have invested available cash in interest and non-interest bearing demand deposit accounts and money market accounts and funds whose investments are limited to United States Government Securities, securities backed by the United States Government, or securities of United States Government agencies. We followed this policy prior to the recent changes in credit markets and believe this is an appropriate approach for the investment of Company funds in the current environment.

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Critical Accounting Policies and Estimates

In our 2008 Annual Report 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 accounting method on a quarterly basis 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 was calculated using hedge adjusted market prices of gas and oil at March 31 and June 30, 2009, which were based on a Henry Hub price of $3.63 per MMBtu and $3.89 per MMBtu, respectively, and a West Texas Intermediate oil price of $46.00 per Bbl and $66.25 per Bbl (adjusted for basis and quality differentials), respectively, compared to prices of $5.71 per MMBtu and $41.00 per Bbl at December 31, 2008. Cash flow hedges of natural gas production in place at March 31 and June 30, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax) and $55.3 million (pre-tax), respectively. Based upon these analyses, we recorded a non-cash, pre-tax write-down of $379.5 million at March 31, 2009 and we did not record a non-cash, pre-tax write-down at June 30, 2009. Due to the volatility of commodity prices, should natural gas and oil prices decline in the future, we experience a significant downward adjustment to our estimated proved reserves, and/or our commodity hedges settle and are not replaced, it is possible that another write-down of our oil and gas properties could occur.

We have entered into financial fixed price swaps with prices ranging from $6.81 per MMBtu to $8.58 per MMBtu covering approximately 9.6 million MMBtu, or 37%, of our 2009 production and 3.6 million MMBtu, or 9%, of our 2010 production. We have also entered into costless collar transactions covering approximately 0.9 million MMBtu of our 2009 production. The costless collars have an average floor price of $8.00 per MMBtu and an average ceiling price of $10.05 per MMBtu. Approximately 95% of total hedged transactions represents hedged prices of commodities at the PG&E Citygate and Houston Ship Channel. Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities. This arrangement 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 our hedge related credit obligations. As of June 30, 2009, we 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, 2009. We evaluated non-performance risk using current credit default swap values and default probabilities for each counterparty and recorded a downward adjustment to the fair value of our derivative assets in the amount of $0.3 million at June 30, 2009.

We utilize counterparty and third party broker quotes to determine the valuation of our derivative instruments. Fair values derived from counterparties and brokers are further verified using the settled price as of June 30, 2009 for NYMEX futures contracts and exchange traded contracts for each derivative settlement location. We have used this valuation technique since the adoption of SFAS No. 157 on January 1, 2008, and we have made no changes or adjustments to our technique since then. We mark to market on a quarterly basis.

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 of this Form 10-Q.

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 2009 was $153.0 million, including the effects of hedging, which is a decrease of $129.8 million, or 46%, from the six months ended June 30, 2008. Natural gas sales, excluding the effects of hedging, decreased by $161.7 million. Of this decrease, $162.7 million is attributable to a 61% decrease in natural gas prices partially offset by a $1.0 million increase due to a less than 1% increase in production volumes. Oil sales decreased by $22.5 million of which $16.3 million was attributable to a 58% decrease in the price of oil and of which $6.2 million was attributable to decreased production. Approximately 92% of our revenue was attributable to natural gas sales on total volumes of 27.7 Bcfe in the first half of 2009.

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The following table presents information regarding our revenues (including the effects of hedging) and production volumes:

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		% Change Increase/ (Decrease)			2009		2008		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Natural gas sales	$	67,087	$	136,142		(51	%)	$	141,311	$	248,587		(43	%)
Oil sales		6,463		18,325		(65	%)		11,681		34,213		(66	%)
Total revenues	$	73,550	$	154,467		(52	%)	$	152,992	$	282,800		(46	%)

Production:
Gas (Bcf)		12.6		13.2		(5	%)		26.2		26.1		0	%
Oil (MBbls)		116.0		147.2		(21	%)		249.8		305.9		(18	%)
Total Equivalents (Bcfe)		13.3		14.1		(6	%)		27.7		27.9		(1	%)

$ per unit:
Avg. Gas Price per Mcf	$	5.32	$	10.30		(48	%)	$	5.39	$	9.53		(43	%)
Avg. Gas Price per Mcf excluding hedges	$	3.59		11.56		(69	%)	$	3.98		10.20		(61	%)
Avg. Oil Price per Bbl	$	55.72		124.51		(55	%)	$	46.76		111.85		(58	%)
Avg. Revenue per Mcfe including hedges	$	5.53		10.96		(50	%)	$	5.52		10.13		(46	%)

Natural Gas. For the three months ended June 30, 2009, natural gas revenue decreased by $69.0 million, including the realized impact of derivative instruments, from the comparable period in 2008, to $67.1 million from $136.1 million. This decrease is primarily due to the significant decline in commodity prices. The average gas price, including the effects of hedging, decreased by $4.98 per Mcf from $10.30 per Mcf for the three months ended June 30, 2008 to $5.32 per Mcf for the comparable period in 2009. The effect of gas hedging activities on natural gas revenue for the three months ended June 30, 2009 was a gain of $21.8 million as compared to a loss of $16.6 million for the three months ended June 30, 2008.

For the six months ended June 30, 2009, natural gas revenue decreased by 43%, or $107.3 million, including the realized impact of derivative instruments, from the same period in 2008 to $141.3 million. This decrease was due to a lower average gas price. The average gas price, including the effects of hedging, decreased by 43%, or $4.14, from $9.53 per Mcf for the six months ended June 30, 2008 to $5.39 per Mcf for the same period in 2009. The effect of gas hedging activities on natural gas revenue for the six months ended June 30, 2009 was a gain of $37.2 million as compared to a loss of $17.3 million for the six months ended June 30, 2008.

Crude Oil. For the three months ended June 30, 2009, oil revenue was $6.5 million as compared to $18.3 million for the same period in 2008. This decrease is attributable to the average realized price decrease of $68.79 per Bbl from $124.51 per Bbl for the three months ended June 30, 2008 to $55.72 per Bbl for the three months ended June 30, 2009. The decrease in oil production volumes was primarily due to a decline in well performance at our Sabine Lake property.

For the six months ended June 30, 2009, oil revenue decreased by 66%, or $22.5 million, compared to the same period in 2008. This decrease is primarily attributable to lower average oil prices of $46.76 per Bbl for the six months ended June 30, 2009 compared to $111.85 per Bbl for the same period in 2008. Oil volumes decreased overall by 18% for the six months ended June 30, 2009 compared to the same period in 2008 due to decreases in production in Sabine Lake and the Gulf of Mexico region compared to the same period in 2008.

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Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		% Change Increase/ (Decrease)			2009		2008		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	16,568	$	14,174		17	%	$	34,609	$	27,588		25	%
Production taxes		1,750		5,754		(70	%)		3,074		9,192		(67	%)
Depreciation, depletion and amortization		28,499		51,738		(45	%)		72,900		103,152		(29	%)
Impairment of oil and gas properties		-		-		-			379,462		-		100	%
General and administrative costs		12,571		13,516		(7	%)		21,944		25,623		(14	%)

$ per unit:
Avg. lease operating expense per Mcfe	$	1.25	$	1.01		24	%	$	1.25	$	0.99		26	%
Avg. production taxes per Mcfe	$	0.13		0.41		(68	%)	$	0.11		0.33		(67	%)
Avg. DD&A per Mcfe	$	2.14		3.67		(42	%)	$	2.63		3.70		(29	%)
Avg. G&A per Mcfe	$	0.95		0.96		(1	%)	$	0.79		0.92		(14	%)

Lease Operating Expense. Lease operating expense increased $2.4 million for the three months ended June 30, 2009 as compared to the three months ended June 30, 2008. The overall increase is due primarily to a $3.3 million increase in direct lease operating expense and a $0.9 million increase in ad valorem taxes, partially offset by a $1.5 million decrease in workover expenses. The increase in direct lease operating expense is due to increased operating expenses from newly acquired properties from the Petroflow and Constellation acquisitions, which occurred during the second and fourth quarters of 2008, respectively, as well as non-operated lease operating expense. The increase in ad valorem taxes is primarily due to increased property value assessments in California compared to the prior period. The decrease in workover expenses is due to a decrease in workover activity partially offset by unanticipated workovers in the Texas State Waters and Gulf of Mexico.

Lease operating expense increased $7.0 million for the six months ended June 30, 2009 as compared to the six months ended June 30, 2008. The overall increase is due to a $5.2 million increase in direct lease operating expense primarily related to acquisitions and non-operated lease operating expense and a $2.8 million increase in ad valorem tax expense partially offset by a $0.6 million decrease in insurance expense and a $0.3 million decrease in workover expense. The higher costs are related to the increase in the number of operating wells, particularly in the Rockies and South Texas due to acquisitions and the Lobo drilling program, and the higher ad valorem taxes are due to higher property value assessments in California.

Production Taxes. Production taxes decreased $4.0 million for the three months ended June 30, 2009 as compared to the three months ended June 30, 2008 primarily due to the 68% decrease in realized natural gas and oil prices, excluding hedges, and the 6% decrease in production.

Production taxes decreased $6.1 million for the six months ended June 30, 2009 as compared to the six months ended June 30, 2008 primarily due to the 61% decrease in realized natural gas and oil prices, excluding hedges.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense decreased $23.2 million for the three months ended June 30, 2009 as compared to the three months ended June 30, 2008. The decrease is due to the full cost ceiling test impairment charges recognized during the second half of 2008 and during the first quarter of 2009 which decreased the full cost pool and thus the DD&A rate. The DD&A rate for the second quarter of 2009 was $2.14 per Mcfe while the rate for the second quarter of 2008 was $3.67 per Mcfe. The decrease in the rate was due to a lower full cost asset base over a comparable reserve base in the second quarter of 2009 as compared to the same period in 2008.

DD&A expense decreased $30.3 million for the six months ended June 30, 2009 as compared to the six months ended June 30, 2008. The decrease is due to the full cost ceiling test impairment charges recognized during the second half of 2008 and during the first quarter of 2009 which decreased the full cost pool and thus the DD&A rate. The DD&A rate for the six months ended June 30, 2009 was $2.63 per Mcfe while the rate for the same period of 2008 was $3.70 per Mcfe. The decrease in the rate was due to a lower full cost asset base over a comparable reserve base in the first half of 2009 as compared to the same period in 2008.

Impairment of Oil and Gas Properties. The June 30, 2009, the ceiling test computation was calculated using hedge adjusted market prices of gas and oil, which were based on a Henry Hub price of $3.89 per MMBtu and a West Texas Intermediate oil price of $66.25 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2009 increased the calculated ceiling value by approximately $55.3 million (pre-tax). Based upon this analysis, there was no write-down recorded at June 30, 2009. At June 30, 2008, the ceiling test computation was calculated using hedge adjusted market prices of gas and oil, 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.

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The March 31, 2009 ceiling test computation was calculated using hedge adjusted market prices of gas and oil, which were based on a Henry Hub price of $3.63 per MMBtu and a West Texas Intermediate oil price of $46.00 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax). Based upon this analysis, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009. At March 31, 2008, the ceiling test computation was calculated using hedge adjusted market prices of gas and oil, which were based on a Henry Hub price of $9.37 per MMBtu and a West Texas Intermediate oil price of $105.63 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2008 decreased the calculated ceiling value by approximately $37.7 million (net of tax). There was no write-down required to be recorded at March 31, 2008.

General and Administrative Costs. General and administrative costs decreased by $0.9 million for the three months ended June 30, 2009 as compared to the three months ended June 30, 2008. This decrease is primarily due to the decrease of $1.8 million in legal expenses incurred during the second quarter of 2008 associated with the Calpine litigation, which was settled during the fourth quarter of 2008. This decrease was partially offset by increased salaries, wages and benefits expense due to an increase in headcount of 18 employees for the second quarter of 2009 compared to the second quarter of 2008.

General and administrative costs decreased by $3.7 million for the six months ended June 30, 2009 as compared to the six months ended June 30, 2008. The decrease is primarily due to the decrease of $6.3 million in legal fees associated with the Calpine litigation, which was settled during the fourth quarter of 2008, offset by $2.2 million of higher payroll and benefit costs relating to the increase in employee headcount.

Total Other Expense

Total other expense includes interest expense, interest income and other income/expense, net which increased $2.3 million for the three months ended June 30, 2009 compared to the three months ended June 30, 2008. The interest income is earned on cash balances, which were lower during the quarter ended June 30, 2009 compared to June 30, 2008. Interest expense was higher for the quarter ended June 30, 2009 compared to the same period in 2008 due primarily to a higher long-term debt balance and an increase in interest rates related to the debt refinancing. The quarter to date weighted average interest rate for the second quarter of 2009 were 5.17% compared to 3.39% for the same period in 2008.

For the six months ended June 30, 2009, total other expense increased by $1.4 million as compared to the six months ended June 30, 2008 primarily as a result of increased interest expense due to a higher long-term debt balance and increased interest rates as a result of the debt refinancing during the period.

Provision for Income Taxes

The effective tax rate for the three and six months ended June 30, 2009 was 37.2% and 36.9%, respectively. The effective tax rate for the three and six months ended June 30, 2008 was 37.3% and 36.6%, 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. The income tax benefit for the six months ended June 30, 2009 includes a $1.0 million downward adjustment recorded in the three months ended March 31, 2009 related to 2008 state taxes.

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. At June 30, 2009, we have a deferred tax asset of approximately $180.0 million resulting primarily from the difference between the book basis and tax basis of our oil and natural gas properties. We believe that it is more likely than not that this deferred tax asset will be realized through future taxable income generated by the production of our oil and natural gas properties.

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. Additionally, we filed a universal shelf registration statement with the SEC during the period, which positions us to raise additional funds in the capital markets as deemed appropriate. However, we currently do not have any stated plans to issue securities.

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 a portion 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. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas.” Our current hedge positions are expected to increase revenue by $37.0 million during the next six months. The majority of our capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels. Current economic conditions and lower commodity prices could adversely affect our cash flow and liquidity. We will continue to monitor our cash flow and liquidity and if appropriate, we may consider adjusting our capital expenditure program.

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SeniorSecured Revolving Line of Credit. On April 9, 2009, we entered into the Restated Revolver with BNP Paribas, as Administrative Agent, and the other lenders identified therein providing a senior secured revolving line of credit in the amount of up to $600.0 million, replacing the prior revolving credit agreement, and extending its term until July 1, 2012. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements. Our borrowing base is dependent on a number of factors including our level of reserves as well as the pricing outlook at the time of the redetermination. A reduction in capital spending could result in a reduced level of reserves thus causing a reduction in the borrowing base. The borrowing base under the Restated Revolver is currently set at $375.0 million. The next borrowing base review is scheduled for the fall of 2009. Amounts outstanding under the Restated Revolver bear interest, as amended, at specified margins over London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. Borrowings under the Restated 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 pre-tax SEC PV-10 reserve value, a guaranty by all of our domestic subsidiaries, and a pledge of 100% of the membership interests of domestic subsidiaries. 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, 2009, our current ratio was 6.7 and the leverage ratio was 1.3. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at June 30, 2009. As of August 6, 2009, we have $200.0 million outstanding with $175.0 million available for borrowing under the Restated Revolver. At June 30, 2009, all amounts drawn under the Restated Revolver are due and payable on July 1, 2012.

Second Lien Term Loan. On April 9, 2009, we also entered into Restated Term Loan with BNP Paribas, as Administrative Agent, and other lenders identified therein replacing the prior Term Loan extending its term until October 2, 2012. Borrowings under the Restated Term Loan were initially set at $75.0 million and bear interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%. The Restated Term Loan had an option to increase fixed and floating rate borrowings by up to $25.0 million to $100.0 million prior to May 9, 2009. We exercised this option on April 21, 2009 and the increased borrowings consisted of $5.0 million of floating rate borrowings and $20.0 million of fixed rate borrowings at 13.75%. The loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At June 30, 2009, our asset coverage ratio was 2.8 and the leverage ratio was 1.3. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at June 30, 2009. As of June 30, 2009, we had $80.0 million of variable rate borrowings and $20.0 million of fixed rate borrowings outstanding under the Restated Term Loan. At June 30, 2009, the principal balance of the Restated Term Loan was due and payable on October 2, 2012.

Our current liquidity position is supported by our Restated Revolver. Our ability to raise capital depends on the current state of the capital markets, which are subject to general economic and industry conditions. We will continue to monitor the financial markets as the availability and price of capital in these markets could negatively affect our liquidity position.

Cash Flows

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

	Six Months Ended June 30,
	2009			2008
	(In thousands)
Cash flows provided by operating activities	$	77,103		$	213,989
Cash flows used in investing activities		(62,444	)		(149,070	)
Cash flows (used in) provided by financing activities		(7,994	)		2,633
Net increase in cash and cash equivalents	$	6,665		$	67,552

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 continued to be a primary source of liquidity and capital used to finance our capital program.

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Cash flows provided by operating activities decreased by $136.9 million for the six months ended June 30, 2009 as compared to the same period for 2008. The decrease in 2009 primarily resulted from lower realized average natural gas and oil prices. In addition, at June 30, 2009, we had a working capital surplus of $73.4 million. This surplus was primarily attributable to the increase in derivative instruments and a decrease in accrued liabilities.

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

Cash flows used in investing activities decreased by $86.6 million for the six months ended June 30, 2009 as compared to the same period for 2008. During the six months ended June 30, 2009, we participated in the drilling of 27 gross wells as compared to the drilling of 71 gross wells during the same period in 2008.

Financing Activities. The primary drivers of cash (used in) provided by financing activities are borrowings and repayments on the revolving credit facility and equity transactions associated with the exercise of stock options and vesting of restricted stock.

Cash flows (used in) provided by financing activities decreased by $10.6 million as compared to the same period for 2008. The net decrease is primarily related to a $30.0 million payment on the revolving credit facility in the second quarter of 2009, $5.8 million of loan fees paid in connection with the Restated Revolver and Restated Term Loan during the second quarter of 2009, offset by $28.4 million of borrowings on the revolving credit facility during the first half of 2009.

Capital Expenditures

Our capital expenditures for the six months ended June 30, 2009 decreased by $48.5 million to $54.9 million compared to the same period in 2008. During the six months ended June 30, 2009, we participated in the drilling of 27 gross wells with the majority of these being in the Lobo region. Our positive operating cash flow and cash on hand are sufficient to fund planned capital expenditures for 2009, which are projected to be $115.0 million. We have the discretion to adjust capital spending plans throughout the year in response to market conditions and the availability of proceeds from possible divestitures.

Commodity Price Risk, Interest Rate Risk and Related Hedging Activities

The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management hedges oil and natural gas prices from time to time primarily through the use of certain derivative instruments including fixed price swaps, basis swaps, costless collars and put options. Although not risk free, we believe these activities will reduce our exposure to commodity price fluctuations and thereby achieve a more predictable cash flow. Consistent with this policy, we have entered into a series of natural gas fixed-price swaps, which are intended to establish a fixed price for a portion of our expected natural gas production through 2010. The fixed-price swap agreements we have entered into require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments were based on expected proved production from existing wells at inception of the hedge instruments.

The following table sets forth the results of commodity hedging transaction settlements for the period ended June 30, 2009:

	Three Months Ended June 30,					Six Months Ended June 30,
Natural Gas	2009		2008			2009		2008
Quantity settled (MMBtu)		5,199,831		6,636,216			10,342,521		12,792,432
Increase (decrease) in natural gas sales revenue (In thousands)	$	21,802	$	(16,595	)	$	37,159	$	(17,296	)
Interest Rate Swaps
Increase in interest expense (In thousands)	$	522	$	335		$	1,034	$	460

As of June 30, 2009, borrowings under our Restated Revolver and Restated Term Loan mature on July 1, 2012 and October 2, 2012, respectively, and bear interest at a LIBOR-based rate. This exposes us to risk of earnings loss due to increases in market interest rates. To mitigate this exposure, as of June 30, 2009, we have entered into a series of interest rate swap agreements through December 2010. If we determine the risk may become substantial and the costs are not prohibitive, we may enter into additional interest rate swap agreements in the future.

In accordance with SFAS No. 133, as amended, all derivative instruments, not designated as a normal purchase sale, are recorded on the balance sheet at fair market value and changes in the fair market value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair market value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions on a quarterly basis, consistent with documented risk management strategy for the particular hedging relationship. Changes in the fair market value of the ineffective portion of cash flow hedges, if any, are included in other income (expense).

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Our current commodity and interest rate hedge positions are with counterparties that are participants in our credit facilities. This allows us to secure any margin obligation resulting from a negative change in the fair market value of the derivative contracts in connection with our credit obligations and eliminate the need for independent collateral postings. As of June 30, 2009, we had no deposits for collateral.

Capital Requirements

The historical capital expenditures summary table is included in Item 1. Business in our 2008 Annual Report and is incorporated herein by reference.

Our capital expenditures for the period ended June 30, 2009 were $54.9 million, and we have plans to carefully execute an organic capital program in 2009 that can be funded from internally generated cash flows. We also have the discretion to use available cash, borrowings under our Restated Revolver, and proceeds from divestitures to fund capital expenditures, including acquisitions, that make sense for the Company. However, our main priority for the foreseeable future is to preserve liquidity and maximize the financial position of the Company.

Commitments and Contingencies

As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

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

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 2008 Annual Report and Note 4 included in Part I. Item 1. Financial Statements of this Form 10-Q.

At June 30, 2009, we had open natural gas derivative hedges in an asset position with a fair value of $45.8 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $6.5 million, while a 10 percent decrease in natural gas prices would increase the fair value by approximately $6.3 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2009. 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.

Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities. Based upon communications with these counterparties, the obligations under these transactions are expected to continue to be met. We evaluated non-performance risk using current credit default swap values and default probabilities for each counterparty and recorded a downward adjustment to the fair value of our derivative assets in the amount of $0.3 million at June 30, 2009. We currently know of no circumstances that would limit access to our credit facility or require a change in our debt or hedging structure.

Item 4. Controls and Procedures

(a) 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, 2009. Based on that evaluation, and in light of the material weakness set forth below, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2009, our disclosure controls and procedures were not 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.

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As of June 30, 2009, we identified a material weakness in our internal controls over financial reporting related to the monthly calculation and review of our DD&A expense that existed during the second quarter of 2009. Specifically, a calculation error was made that overstated our DD&A expense for the period and was not identified in the subsequent internal review. The required adjustment was recorded in our financial information for the three months ended June 30, 2009. To address this material weakness, we have changed our review procedures to include a more comprehensive monthly review of the calculation. While we believe that the steps we have taken will sufficiently address this material weakness in internal control over financial reporting, there can be no assurance that the measures that we have taken are adequate.

(b) Other than the material weakness discussed above, 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 reasonably 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 as well as administrative claims related to employment issues. 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.

Item 1A. Risk Factors

As of the date of this filing, there have been no material changes in our risk factors from those previously disclosed in Item 1A of our 2008 Annual Report.

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, 2009

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		881	$	6.33		-		-
May 1 - May 31		426		7.17		-		-
June 1 - June 30		1,554		8.70		-		-
Total		2,861	$	7.74		-		-

(1)

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

Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

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

On May 8, 2009, 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:

	Votes For	Votes Withheld
Randy L. Limbacher	46,979,876	1,212,436
D. Henry Houston	31,584,831	16,607,481
Richard W. Beckler	31,584,090	16,608,222
Donald D. Patteson, Jr.	31,579,858	16,612,454
Josiah O. Low III	31,584,034	16,608,278
Philip L. Frederickson	47,228,192	964,120
Matthew D. Fitzgerald	47,228,217	964,095

With respect to the ratification of the appointment of the Company’s Independent Public Accounting Firm, PricewaterhouseCoopers LLP for 2009, the following is a summary of the votes on this item:

For

48,117,763

Against

53,125

Abstain

21,424

With respect to Proposal No. 3, approval of an amendment to the Company’s Amended and Restated 2005 Long-Term Incentive Plan to allow for the grant of stock options, stock awards, restricted stock, restricted stock units, stock appreciation rights, performance awards and other incentive awards to employees, non-employee directors and other service providers the following is a summary of the votes on this item:

For

41,696,508

Against

2,004,421

Abstain

36,715

Broker Non-votes

4,454,668

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number		Description
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		Amended and Restated Bylaws (incorporated herin by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on December 10, 2008 (Registration No. 000-51801)).
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)).
10.18		Amended and Restated Senior Revolving Credit Agreement (incorporated herin by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.19		Amended and Restated Second Lien Term Loan Agreement (incorporated herin by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
31.1		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Periodic Financial Reports by Chief Executive Officer and Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

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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 6, 2009

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ROSETTA RESOURCES INC.

EXHIBIT INDEX

Exhibit Number		Description
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		Amended and Restated Bylaws (incorporated herin by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on December 10, 2008 (Registration No. 000-51801)).
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)).
10.18		Amended and Restated Senior Revolving Credit Agreement (incorporated herin by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.19		Amended and Restated Second Lien Term Loan Agreement (incorporated herin by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
31.1		Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Periodic Financial Reports by Chief Executive Officer and Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002