Edgar Filing: Rosetta Resources Inc.

form10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended June 30, 2010

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 o	Accelerated filer x

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, 2010 was 52,746,286.

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	14
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	25
	Item 4. Controls and Procedures	25
Part II –	Other Information
	Item 1. Legal Proceedings	25
	Item 1A. Risk Factors	26
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	27
	Item 3. Defaults upon Senior Securities	27
	Item 4. Removed and Reserved	27
	Item 5. Other Information	27
	Item 6. Exhibits	27
Signatures		28

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except par value and share amounts)

	June 30, 2010			December 31, 2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	16,858		$	61,256
Accounts receivable		29,690			32,691
Derivative instruments		24,012			8,983
Prepaid expenses		4,372			2,837
Other current assets		6,424			6,415
Total current assets		81,356			112,182

Oil and natural gas properties (1)		2,112,160			2,030,433
Other fixed assets		13,887			12,417
		2,126,047			2,042,850
Accumulated depreciation, depletion, and amortization, including impairment		(1,431,200	)		(1,452,248	)
Total property and equipment, net		694,847			590,602

Deferred loan fees		8,676			4,921
Deferred tax asset		158,926			169,732
Derivative instruments		8,211			-
Other assets		2,440			2,147
Total other assets		178,253			176,800
Total assets	$	954,456		$	879,584

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	4,183		$	2,279
Accrued liabilities		48,594			37,107
Royalties payable		9,658			16,064
Derivative instruments		232			236
Prepayment on gas sales		7,859			7,542
Deferred income taxes		8,822			3,258
Total current liabilities		79,348			66,486
Long-term liabilities:
Derivative instruments		-			1,960
Long-term debt		321,000			288,742
Other long-term liabilities		29,859			29,301
Total liabilities		430,207			386,489

Commitments and Contingencies (Note 9)

Stockholders' equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2010 or 2009		-			-
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 51,690,198 shares and 51,254,709 shares at June 30, 2010 and December 31, 2009, respectively		51			51
Additional paid-in capital		785,857			780,196
Treasury stock, at cost; 291,798 and 199,955 shares at June 30, 2010 and December 31, 2009, respectively		(5,419	)		(3,473	)
Accumulated other comprehensive income		20,123			4,259
Accumulated deficit		(276,363	)		(287,938	)
Total stockholders' equity		524,249			493,095
Total liabilities and stockholders' equity	$	954,456		$	879,584

(1)	Based upon the full cost method, $70.9 million at June 30, 2010 and $42.3 million at December 31, 2009 were excluded from amortization.

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,
	2010			2009			2010			2009
Revenues:
Natural gas sales	$	47,491		$	62,471		$	103,298		$	133,031
Oil sales		10,773			6,463			17,756			11,681
NGL sales		10,358			4,616			17,716			8,280
Total revenues		68,622			73,550			138,770			152,992
Operating costs and expenses:
Lease operating expense		13,310			16,568			27,987			34,609
Depreciation, depletion, and amortization		25,719			28,499			49,533			72,900
Impairment of oil and gas properties		-			-			-			379,462
Treating, transportation and marketing		1,406			1,342			2,887			3,362
Production taxes		1,085			1,750			3,375			3,074
General and administrative costs		11,326			12,571			23,133			21,944
Total operating costs and expenses		52,846			60,730			106,915			515,351
Operating income (loss)		15,776			12,820			31,855			(362,359	)

Other (income) expense:
Interest expense, net of interest capitalized		9,100			6,106			13,846			8,641
Interest income		(8	)		(25	)		(19	)		(76	)
Other (income) expense, net		(595	)		310			(798	)		160
Total other expense		8,497			6,391			13,029			8,725

Income (loss) before provision for income taxes		7,279			6,429			18,826			(371,084	)
Income tax expense (benefit)		2,967			2,394			7,251			(136,983	)
Net income (loss)	$	4,312		$	4,035		$	11,575		$	(234,101	)

Earnings (loss) per share:
Basic	$	0.08		$	0.08		$	0.23		$	(4.60	)
Diluted	$	0.08		$	0.08		$	0.22		$	(4.60	)

Weighted average shares outstanding:
Basic		51,355			50,969			51,287			50,945
Diluted		52,056			51,079			52,013			50,945

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,
	2010			2009
Cash flows from operating activities
Net income (loss)	$	11,575		$	(234,101	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		49,533			72,900
Impairment of oil and gas properties		-			379,462
Deferred income taxes		7,030			(137,131	)
Amortization of deferred loan fees recorded as interest expense		2,296			1,163
Amortization of original issue discount recorded as interest expense		1,258			114
Stock compensation expense		4,628			2,826
Change in operating assets and liabilities:
Accounts receivable		3,001			13,071
Prepaid expenses		(1,535	)		431
Other current assets		(9	)		588
Other assets		(293	)		(77	)
Accounts payable		1,904			(2,115	)
Accrued liabilities		2,516			(8,179	)
Royalties payable		(6,089	)		(11,849	)
Net cash provided by operating activities		75,815			77,103
Cash flows from investing activities
Acquisition of oil and gas properties		(5,850	)		(3,844	)
Additions of oil and gas assets		(151,037	)		(76,167	)
Disposals of oil and gas properties and assets		11,885			16,146
Decrease in restricted cash		-			1,421
Net cash used in investing activities		(145,002	)		(62,444	)
Cash flows from financing activities
Payments on Restated Term Loan		(80,000	)		-
Borrowings on Restated Revolver		25,000			28,400
Payments on Restated Revolver		(114,000	)		(30,000	)
Issuance of Senior Notes		200,000			-
Deferred loan fees		(6,051	)		(5,824	)
Proceeds from stock options exercised		1,786			-
Purchases of treasury stock		(1,946	)		(570	)
Net cash provided by (used in) financing activities		24,789			(7,994	)

Net (decrease) increase in cash		(44,398	)		6,665
Cash and cash equivalents, beginning of period		61,256			42,855
Cash and cash equivalents, end of period	$	16,858		$	49,520

Supplemental disclosures:
Capital expenditures included in accrued liabilities	$	27,170		$	1,458

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 operations are concentrated in the core areas of the Sacramento Basin of California, the Rockies and South Texas. Additionally, the Company has non-core, non-operated positions in the Gulf of Mexico located in shallow waters.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments necessary to fairly state 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, 2009 ("2009 Annual Report").

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 2009 Annual Report.

Principles of Consolidation. The accompanying consolidated financial statements as of June 30, 2010 and December 31, 2009 and for the three and six months ended June 30, 2010 and 2009 contain the accounts of Rosetta Resources Inc. and its wholly 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.

Fair Value Measurements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements must be presented separately. These disclosures are required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The application of this guidance for the period ended June 30, 2010 for Level 1 and Level 2 fair value measurements did not have an impact on the Company’s fair value disclosures or the consolidated financial position, results of operations or cash flows. The guidance for Level 3 fair value measurements will require additional disclosures in future periods but is not expected to impact the Company’s consolidated financial position, results of operations or cash flows.

Subsequent Events. In May 2009, the FASB issued authoritative guidance on subsequent events to incorporate accounting guidance that originated as auditing standards into the body of authoritative literature issued by the FASB. This guidance 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 guidance is effective for interim and annual financial periods ending after June 15, 2009. The Company adopted the requirements of this guidance for the period ended June 30, 2009 and the adoption did not have a significant impact on the Company’s consolidated financial position, results of operations or cash flows. On February 25, 2010, the FASB amended this guidance to remove the requirement to disclose the date through which an entity has evaluated subsequent events.

Variable Interest Entities. In June 2009, the FASB issued authoritative guidance related to variable interest entities which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting rights should be consolidated and modifies the approach for determining the primary beneficiary of a variable interest entity. This guidance will require a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. The guidance related to variable interest entities is effective on January 1, 2010. The Company applied this guidance for the period ended June 30, 2010 and it did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

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(3) Property and Equipment

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

	June 30, 2010			December 31, 2009
	(In thousands)
Proved properties	$	1,995,088		$	1,949,515
Unproved/unevaluated properties		70,867			42,344
Gas gathering system and compressor stations		46,205			38,574
Other fixed assets		13,887			12,417
Total property and equipment, gross		2,126,047			2,042,850
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,431,200	)		(1,452,248	)
Total property and equipment, net	$	694,847		$	590,602

In the second quarter of 2010, the Company completed various acquisitions and divestitures. On April 13, 2010, the Company divested its Gulf Coast Texas State Waters Sabine Lake asset, a non-core property, for $10.2 million. The proceeds were recorded as an adjustment to the full cost pool with no gain or loss recognized. On April 8, 2010, the Company purchased the remaining 30% working interest and obtained operatorship in the Catarina Field for $5.9 million from St. Mary Land & Exploration Company. The purchase is effective as of January 1, 2010 and subject to any applicable purchase price adjustments. Also during the second quarter of 2010, the Company purchased an additional 315 acres and 5,000 acres in the Eagle Ford and Bakken plays, respectively, for approximately $946,000 and $200,000, respectively.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $2.2 million and $0.9 million of internal costs for the three months ended June 30, 2010 and 2009, respectively, and $3.9 million and $1.8 million for the six months ended June 30, 2010 and 2009, respectively.

Included in the Company’s oil and gas properties are asset retirement costs of $20.5 million and $21.9 million at June 30, 2010 and December 31, 2009, respectively.

Oil and gas properties include costs of $70.9 million and $42.3 million at June 30, 2010 and December 31, 2009, respectively, that were excluded from capitalized costs being amortized. These amounts primarily represent acquisition costs of unproved properties and unevaluated exploration projects in which the Company owns a direct interest. The increase from December 31, 2009 to June 30, 2010 is a result of leasehold acquisitions and the costs associated with unevaluated wells in the Rockies and Eagle Ford.

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 a trailing twelve-month average price using first day of the month prices, adjusted for hedges, of gas and oil at June 30, 2010, which were based on a Henry Hub gas price of $4.10 per MMBtu and a West Texas Intermediate oil price of $72.25 per Bbl (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and gas properties. As a result, no write-down was recorded at June 30, 2010. It is possible that a 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 its estimated proved reserves, and/or the Company's commodity hedges settle and are not replaced.

In 2009, 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. 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.

(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, 2010:

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Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor/Fixed Prices MMBtu		Average Ceiling Prices MMBtu		Fair Market Value Asset/(Liability) (In thousands)
2010	Swap	Cash flow		25,000		4,600,000	$	6.83	$	-	$	10,516
2010	Costless Collar	Cash flow		30,000		5,520,000		5.75		7.12		6,124
2011	Swap	Cash flow		15,000		5,475,000		5.85		-		4,528
2011	Costless Collar	Cash flow		35,000		12,775,000		5.79		7.27		9,091
2012	Costless Collar	Cash flow		10,000		3,660,000		5.75		7.15		2,122
						32,030,000					$	32,381

The Company has hedged the interest rates on $100.0 million of its outstanding debt through December 31, 2010. As of June 30, 2010, 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)
July 1 - December 31, 2010	Swap	Cash Flow			1.24	%		$	(390	)

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, 2010, the Company had made no deposits for collateral.

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

	Three Months Ended June 30,						Six Months Ended June 30,
Natural Gas	2010			2009			2010			2009
Quantity settled (MMBtu)		2,275,000			5,199,831			4,525,000			10,342,521
Increase in natural gas sales revenue (In thousands)	$	5,721		$	21,802		$	8,598		$	37,159
Interest Rate Swaps
(Increase) in interest expense (In thousands)	$	(238	)	$	(522	)	$	(490	)	$	(1,034	)

As of June 30, 2010, the Company expects to reclassify gains of $23.8 million to earnings from the balance in Accumulated other comprehensive income on the Consolidated Balance Sheet during the next twelve months based on current forward prices as of June 30, 2010.

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.

Authoritative guidance for derivatives requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the statement of financial position. In accordance with this guidance, 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.

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As of June 30, 2010, the Company had outstanding natural gas commodity forward contracts with a notional volume of 32,030,000 MMBtus that were entered into to hedge forecasted natural gas sales.

As of June 30, 2010, 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.

Information on the location and amounts of derivative fair values in the Consolidated Balance Sheet as of June 30, 2010 and December 31, 2009 and derivative gains and losses in the Consolidated Statement of Operations for the three and six months ended June 30, 2010 and June 30, 2009 is as follows:

	Fair Values of Derivative Instruments

	Derivative Assets (Liabilities)

	Balance Sheet Location	Fair Value
		June 30, 2010			December 31, 2009
Derivatives designated as hedging instruments		(In thousands)

Interest rate swap	Derivative instruments - current assets	$	(158	)	$	(399	)
Interest rate swap	Derivative instruments - current liabilities		(232	)		(236	)
Commodity contracts	Derivative instruments - current assets		24,170			9,382
Commodity contracts	Derivative instruments - non-current assets		8,211			-
Commodity contracts	Derivative instruments - non-current liabilities		-			(1,960	)

Total derivatives designated as hedging instruments		$	31,991		$	6,787

Total derivatives not designated as hedging instruments		$	-		$	-

Total derivatives		$	31,991		$	6,787

Derivatives in Cash Flow Hedging Relationships	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)

	Three Months Ended					Six Months Ended							Three Months Ended					Six Months Ended
	June 30, 2010		June 30, 2009			June 30, 2010			June 30, 2009				June 30, 2010			June 30, 2009		June 30, 2010			June 30, 2009
	(In thousands)												(In thousands)

Interest rate swap	$	15	$	(110	)	$	(248	)	$	(144	)	Interest expense, net of interest capitalized	$	(238	)	$	-	$	(490	)	$	(512	)
Commodity contracts		1,047		4,540			33,560			43,673		Natural gas sales		5,721			21,802		8,598			37,159

Total	$	1,062	$	4,430		$	33,312		$	43,529		Total	$	5,483		$	21,802	$	8,108		$	36,647

(5) Fair Value Measurements

The Company adopted the authoritative guidance for fair value measurements effective January 1, 2008 for financial assets and liabilities and effective January 1, 2009 for non-financial assets and liabilities. The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. As none of the Company’s non-financial assets and liabilities are impaired during the period ended June 30, 2010, and the Company had no other material assets or liabilities that are reported at fair value on a non-recurring basis, no additional disclosures are provided at June 30, 2010.

As defined in the guidance, 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 (an 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. The guidance 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, 2010. 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 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, 2010. As required, 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.

	Fair value as of June 30, 2010
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (liabilities):
Money market funds	$	-	$	-	$	2,035		$	2,035
Commodity derivative contracts		-		-		32,381			32,381
Interest rate swap contracts		-		-		(390	)		(390	)
Total	$	-	$	-	$	34,026		$	34,026

	Fair value as of December 31, 2009
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (liabilities):
Money market funds	$	-	$	-	$	2,035		$	2,035
Commodity derivative contracts		-		-		7,422			7,422
Interest rate swap contracts		-		-		(635	)		(635	)
Total	$	-	$	-	$	8,822		$	8,822

The determination of the fair values above incorporates various factors. 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 and recorded a downward adjustment to the fair value of its derivative assets in the amount of $0.3 million at June 30, 2010.

The following table sets forth a reconciliation of changes for the three and six months ended June 30, 2010 and 2009 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)

Balance at beginning of period	$	38,447		$	67,659		$	8,822		$	43,397
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings (1)		-			2			-			9
Included in Other Comprehensive Income		1,062			4,429			33,312			43,529
Purchases, Issuances and Settlements		(5,483	)		(24,280	)		(8,108	)		(39,125	)
Transfers in and out of Level 3		-			-			-			-
Balance at end of period	$	34,026		$	47,810		$	34,026		$	47,810

(1) No gains or losses were included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period.

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At June 30, 2010, the carrying value of cash and cash equivalents, accounts receivable, other current assets and current liabilities reported in the consolidated balance sheet approximate fair value because of their short-term nature. The carrying amount of long-term debt reported in the consolidated balance sheet at June 30, 2010 is $321.0 million. The Company calculated the fair value of its long-term debt as of June 30, 2010, in accordance with the authoritative guidance for fair value measurements using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality, and risk profile. Based on this calculation, the Company has determined the fair market value of its debt to be $325.3 million at June 30, 2010.

(6) Asset Retirement Obligation

The following table provides a rollforward of the asset retirement obligations. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation (“ARO”) is as follows:

	Six Months Ended June 30, 2010
	(In thousands)

ARO as of December 31, 2009	$	28,920
Revision of previous estimates		(1	)
Liabilities incurred during period		625
Liabilities settled during period		(1,965	)
Accretion expense		1,146
ARO as of June 30, 2010	$	28,725

At June 30, 2010, the current portion of the total ARO is approximately $1.0 million and is included in Accrued liabilities and the long-term portion of ARO is approximately $27.7 million and is included in Other long-term liabilities on the Consolidated Balance Sheet.

(7) Long-Term Debt

Senior Secured Revolving Line of Credit. The Company’s amended and restated revolving credit agreement (the “Restated Revolver”) provides for a senior secured revolving line of credit of up to $600.0 million and matures on 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 Company’s semi-annual borrowing base review was completed April 1, 2010, and the borrowing base under the Restated Revolver was set at $375.0 million as compared to $350.0 million at December 31, 2009. On April 15, 2010, the Company issued 9.500% Senior Notes due 2018 (discussed below), and as a result, the borrowing base under the Company's Restated Revolver was reduced to $345.0 million. Amounts outstanding under the Restated Revolver bear interest at specified margins over LIBOR of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by liens on substantially all of the Company’s assets, liens 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 equity 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. In addition, the Company is subject to covenants, including limitations on dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company was in compliance with all covenants at June 30, 2010. The Company paid a facility fee on the total commitment of $4.6 million in April 2009. The Company took additional borrowings of $25.0 million on the Restated Revolver during the first quarter of 2010 and, as a result of the Company's Senior Notes offering on April 15, 2010, the Company repaid $114.0 million on the Restated Revolver and had $101.0 million outstanding with $244.0 million available for borrowing under the Restated Revolver as of June 30, 2010. The Company also took additional borrowings of $19.0 million on the Restated Revolver in July 2010.

Second Lien Term Loan. The Company’s amended and restated term loan (the “Restated Term Loan”) matures on October 2, 2012. As a result of the Company’s Senior Notes offering on April 15, 2010 (discussed below), the Company repaid the $80.0 million of variable rate borrowings under the Restated Term Loan which bore interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%. In accordance with authoritative guidance for derivative instruments and hedging activities, the Company evaluated the LIBOR floor as an embedded derivative and concluded that because the terms are clearly and closely related to the debt instrument, it does not represent an embedded derivative that must be accounted for separately. As of June 30, 2010, the Company had $20.0 million of fixed rate borrowings bearing interest at 13.75% under the Restated Term Loan. 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. In addition, the Company is subject to covenants, including limitations on dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company was in compliance with all covenants at June 30, 2010. The Company paid an original issue discount of $1.6 million and a facility fee of $0.9 million on the total commitment in April 2009. On April 15, 2010, Company paid an early termination premium of $1.3 million related to the early extinguishment of the outstanding $80.0 million variable rate borrowings. The Company also has the right to prepay the fixed portion of $20.0 million outstanding under the Restated Term Loan with a make-whole amount at a discount factor equal to 1% plus the U.S. Treasury yield security having a maturity closest to the remaining life of the loan.

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Senior Notes. On April 15, 2010, the Company issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes (“Senior Notes”) due 2018. The Senior Notes were issued under an indenture (the “Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the Indenture limit our ability to, among other things, incur additional indebtedness; pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire our capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The Indenture also contains customary events of default. Proceeds from the Senior Notes offering were used to repay $114.0 million on the Restated Revolver, $80.0 million of variable rate borrowings under our Restated Term Loan, and to pay for fees and expenses associated with the offering. Interest is payable on the Senior Notes semi-annually on April 15 and October 15.

As of June 30, 2010, the Company had total outstanding borrowings of $321.0 million and the Company’s weighted average borrowing rate was 7.70%.

(8) Income Taxes

The effective tax rate for the three and six months ended June 30, 2010 was 40.8% and 38.5%, respectively. The effective tax rate for the three and six months ended June 30, 2009 was 37.2% and 36.9%, respectively. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes. As of June 30, 2010, the Company had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2009. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations within the next twelve months.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for 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, 2010, the Company has a deferred tax asset of approximately $158.9 million resulting primarily from the difference between the book basis and tax basis of oil and natural gas properties. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income from the production of oil and natural gas properties prior to the expiration of loss carryforwards. There is no valuation allowance recorded on the deferred tax asset as the Company believes it is more likely than not that the asset will be utilized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

(9) Commitments and Contingencies

The Company is party to various legal proceedings arising in 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 is shown below:

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	Three Months Ended June 30,												Six Months Ended June 30,
	2010						2009						2010					2009
	(In thousands)
Accumulated other comprehensive income, beginning of period				$	22,848					$	39,298					$	4,259				$	24,079
Net income (loss)	$	4,312					$	4,035					$	11,575				$	(234,101	)

Change in fair value of derivative hedging instruments	$	1,062					$	4,430					$	33,312				$	43,529
Hedge settlements reclassed to income (loss)		(5,483	)					(21,280	)					(8,108	)				(36,125	)
Tax provision related to hedges		1,696						6,277						(9,340	)				(2,758	)
Total other comprehensive income	$	(2,725	)	$	(2,725	)	$	(10,573	)	$	(10,573	)	$	15,864		$	15,864	$	4,646		$	4,646

Comprehensive income (loss)	$	1,587					$	(6,538	)				$	27,439				$	(229,455	)
Accumulated other comprehensive income, end of period				$	20,123					$	28,725					$	20,123				$	28,725

(11) Earnings (Loss) Per Share

Basic earnings (loss) 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,
	2010		2009		2010		2009
	(In thousands)
Basic weighted average number of shares outstanding		51,355		50,969		51,287		50,945
Dilution effect of stock option and awards at the end of the period (1)		701		110		726		-
Diluted weighted average number of shares outstanding		52,056		51,079		52,013		50,945

Anti-dilutive stock awards and shares		45		1,952		64		1,947

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

(12) Geographic Area Information

The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with authoritative guidance regarding disclosure about segments of an enterprise and related information. Also, as all of the Company’s operations are located in the United States, all of the Company’s costs are included in one cost pool.

Geographic Area 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 and equipment information below are based on physical location of the assets at the end of each period. Certain amounts in prior periods have been reclassified to conform to the current presentation.

	Three Months Ended June 30,				Six Months Ended June 30,
	2010 (1)		2009 (1)		2010 (1)		2009 (1)
Natural gas, Oil and NGL Revenue	(In thousands)				(In thousands)
California	$	17,090	$	13,582	$	38,487	$	32,761
Rockies		6,496		4,791		15,014		11,401
South Texas		18,308		24,298		44,661		50,811
Eagle Ford		17,693		39		22,015		68
Gulf Coast		1,350		6,196		5,500		15,288
Other Onshore		1,964		2,842		4,495		5,504
Total revenue, excluding gains on hedges	$	62,901	$	51,748	$	130,172	$	115,833

(1) Excludes the effects of hedging gains of $5.7 million and $8.6 million for the three and six months ended June 30, 2010, respectively, and $21.8 million and $37.2 million for the three and six months ended June 30, 2009, respectively.

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	June 30, 2010		December 31, 2009
Oil and natural gas properties and Other fixed assets	(In thousands)
California	$	630,004	$	627,736
Rockies		227,786		204,357
South Texas		812,615		801,158
Eagle Ford		162,378		40,825
Gulf Coast		170,738		228,369
Other Onshore		108,639		127,988
Other fixed assets		13,887		12,417
Total Oil and natural gas properties and Other fixed assets	$	2,126,047	$	2,042,850

(13) Guarantor Subsidiaries

The Company’s Senior Notes are guaranteed by its wholly owned subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several, and subsidiaries of Rosetta Resources Inc. other than the subsidiary guarantors are minor. In addition, there are no restrictions on the ability of Rosetta Resources Inc. to obtain funds from its subsidiaries by dividend or loan. Finally, none of Rosetta Resources Inc.’s subsidiaries has restricted assets that exceed 25% of net assets as of the most recent fiscal year which may not be transferred to the parent company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

(14) Subsequent Events

The Company took additional borrowings of $19.0 million under the Restated Revolver in July 2010 to invest in capital expenditures and as a result, the unused Restated Revolver availability decreased to $225.0 million.

The Company filed a registration statement on Form S-4 with the SEC in July 2010 under which the Company intends to offer to exchange the Senior Notes for registered notes with substantially similar terms. The registration statement has not become effective.

On July 28, 2010, the Company purchased an additional 3,000 acres in the Eagle Ford play. As a result of this leasehold acquisition, the Company’s acreage within the Eagle Ford play increased to approximately 64,000 acres as of the close of this transaction.

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 statements regarding the Company within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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. Unless the context clearly indicates otherwise, references in this report to “Rosetta,” “we,” “our,” “us” or like terms refer to Rosetta Resources Inc. and its subsidiaries.

The forward-looking statements contained in this report reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. “Risk Factors” in our 2009 Annual 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:

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–	supply and demand for oil and natural gas;

–	changes in the price of oil and natural gas;

–	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;

–	oil and natural gas reserve levels;

–	the effect of inflation;

–	competition in the oil and natural gas 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 that could adversely impact 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 local environmental laws and regulations;

–	effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof and increased enforcement activities over the industry;

–	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;

–

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;

–	factors that could impact the pace of our capital program execution, including but not limited to, access to oilfield services, access to water for hydraulic fracture stimulations and permitting delays; and

–

factors that could impact the cost, extent and pace of our capital program execution, including but not limited to, access to oilfield services, access to water for hydraulic fracture stimulations and permitting delays, unavailability of required permits, lease suspensions, drilling, exploration and production moratoriums and other legislative, executive or judicial actions by federal, state and local authorities, as well as actions by private citizens, environmental groups or other interested persons.

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Overview

The following discussion addresses material changes in our results of operations for the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009, and material changes in financial condition since December 31, 2009. It should be read in conjunction with our 2009 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 six months ended June 30, 2010 as compared to the same period for 2009:

various acquisitions and divestitures were completed, including the divestiture of the Gulf Coast Texas State Waters Sabine Lake asset, a non-core property, for $10.2 million, and the acquisition of the remaining 30% working interest in the Catarina Field;

$200.0 million of 9.500% Senior Notes due in 2018 were issued;

diluted earnings per share increased $4.82 to diluted earnings per share of $0.22 for the six months ended June 30, 2010 from diluted loss per share of $4.60 for the six months ended June 30, 2009;

average realized gas prices, including hedging, decreased $0.17 per Mcf, or 3%, to $5.30 per Mcf for the six months ended June 30, 2010 from $5.47 per Mcf for the six months ended June 30, 2009;

average realized NGL prices increased $15.69 per Bbl, or 58%, to $42.76 per Bbl for the six months ended June 30, 2010 from $27.07 per Bbl for the six months ended June 30, 2009;

average realized oil prices increased $27.66 per Bbl, or 59%, to $74.42 per Bbl for the six months ended June 30, 2010 from $46.76 per Bbl for the six months ended June 30, 2009;

total revenue, including the effects of hedging, decreased $14.2 million or 9%;

94 gross (92 net) wells were drilled with a net success rate of 99% for the six months ended June 30, 2010 compared to 27 gross (20 net) wells drilled with a net success rate of 85% for the same period in 2009; and

production on a Bcfe basis decreased 16%.

During 2008 and 2009, Rosetta transformed itself as a company. The driving theme of our strategy shift was to establish a portfolio of resource plays that could offer predictable, sustainable, and profitable growth. The first priority of this shift was to gain access to repeatable resources in order to generate an inventory of future drilling opportunities. We made notable progress by establishing low cost positions in and testing two new shale plays, namely the Eagle Ford shale in South Texas and the Alberta Basin Bakken shale in Montana. Our general practice has been to deploy cash flows from legacy onshore assets into these prospective areas, which continues in 2010.

In the Eagle Ford shale, our acreage position currently stands at roughly 64,000 net acres. Of this, approximately 44,000 acres has been delineated and is under development. Of the 64,000 net acres, roughly 49,500 net acres is located in the liquids-rich area of the play. During the first six months of 2010, we ran at least a two-rig program in the Eagle Ford and expect to continue at that pace or greater for the remainder of the year. Results from our 2010 wells are exceeding expectations and we have already begun to identify a significant level of future inventory from the play. In the second quarter of 2010, we added additional firm long-term gas transportation and processing agreements in the Gates Ranch area to our existing firm long-term and short-term gas transportation capacity rights. This infrastructure expansion should be complete by December 1, 2010 and will relieve current constraints on takeaway from the Gates Ranch area. We believe these additions are sufficient to accommodate the expected additional gas production from the Gates Ranch property for the near future. Negotiations are also underway for additional gas processing capacity rights for portions of this production.

In addition to the area of the Eagle Ford play that we have tested, we have approximately 20,000 net acres that are untested, but that we believe are also located in the liquids-prone window. We expect to drill some of this untested acreage during 2010. In total, we expect to drill 30-35 Eagle Ford shale wells this year and complete up to 25. We continue to evaluate opportunities to build our acreage position in the Eagle Ford, but we are only willing to do so at leasehold acquisition costs that we believe are attractive.

Our progress in the Eagle Ford positions the Company to deliver on the next priority of our strategy shift; namely, to profitably grow production and reserves. The Eagle Ford shale play has the potential to contribute significant performance improvement going forward. With ongoing success in this play, the Company has the potential to accelerate value creation by effectively capitalizing growth from this asset. As an additional benefit, this growth would inherently shift our product mix toward a higher percentage of liquids. Accordingly, we believe the program economics of this play is superior to other inventory in our portfolio today and could represent some of the strongest among U.S. onshore basins. We believe it is in the best interest of our shareholders to drill and delineate the Eagle Ford.

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In the less mature Alberta Basin Bakken shale play, we currently hold about 291,000 net acres. During 2009, we drilled or spud three wells across a large portion of our exploratory acreage position. Two of those wells were vertical wells and the third well was drilled and completed as a horizontal well. During the second quarter of 2010, we conducted low-cost fracture stimulated completions in the existing vertical well sections of our 2009 drilled wells. Based on the results of these vertical tests, we expect to re-initiate drilling operations in the field during the third quarter. Our plan is now to execute an eight well vertical program that we believe represents the most cost effective way to delineate our extensive acreage position and establish commerciality in the play. Although the Bakken is still very exploratory in nature, we continue to be encouraged about the potential of this opportunity.

With success in the Eagle Ford and encouragement in the Bakken, we are significantly curtailing capital from our legacy gas-prone assets given the relative economics and inventory upside from the shale plays. Initially, we announced a 2010 capital program of $280.0 million. We now expect to invest approximately $310.0 million, primarily reflecting completion design changes and service cost increases in the Eagle Ford play, as well as additional leasehold purchases in the Eagle Ford and Bakken plays. Although we are broadly committed to a fiscal strategy of internally funding our capital program, persistently weak gas prices have eroded cash flows from our legacy assets and hence our ability to achieve this objective at the current time. We are willing to draw on our amended and restated revolving credit agreement (the “Restated Revolver”) to the extent additional investments are required; however, we are also willing to consider other options for funding our capital program in 2010 and beyond, including additional asset sales and/or accessing the capital markets. Additional assets will be marketed beginning in the third quarter of 2010.

We increased our borrowing base on April 1, 2010 to $375.0 million as a result of the semi-annual redetermination. On April 15, 2010, we issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes ("Senior Notes") due 2018. We used the proceeds from the Senior Notes offering to repay $80.0 million of variable rate borrowings under our amended and restated term loan (the “Restated Term Loan”), to repay $114.0 million under our Restated Revolver and to pay for fees and expenses associated with the offering. Interest is payable on the Senior Notes semi-annually on April 15 and October 15. As a result of the offering, the borrowing base under our Restated Revolver was reduced by $30.0 million to $345.0 million and our unused Restated Revolver availability was $244.0 million as of June 30, 2010 with total liquidity of over $260.0 million as of that date. We took additional borrowings of $19.0 million under the Restated Revolver in July 2010 and as a result, our unused Restated Revolver availability decreased to $225.0 million.

While we are encouraged about having the inventory to achieve profitable growth in production and reserves, the operating environment for our industry continues to be very challenging and our success in 2010 or beyond is not assured. The outlook for natural gas continues to be weak. Access to some oilfield services is tight, especially for fracture stimulation services. This could impede our ability to execute programs on a timely basis. Our new plays require infrastructure, most notably in the Eagle Ford, which could also result in production delays. Finally, given the early stage of the Alberta Basin Bakken shale play, there is still significant risk to that program. These factors, in addition to planned divestitures, make it difficult to estimate 2010 volumes with certainty. However, we currently expect full year volumes to average 135-145 MMcfe/d. This revised estimate reflects takeaway constraints, first quarter drilling delays, and the impact of known divestitures through the second quarter of 2010. We expect to exit 2010 at an average rate of 160-170 MMcfe/d, excluding additional divestitures and assuming infrastructure expansions are achieved by December 1, 2010.

We attempt to manage risk in our business by carefully monitoring the environment, working closely with our suppliers and vendors, staying abreast of the marketplace, and moving at a deliberative pace in our new play programs so that we do not overcapitalize them. Nevertheless, regardless of how effectively we manage these risks, they represent threats to our ability to achieve our growth goals. As to building our asset base, we prefer organic opportunities, but we are also expanding our capability to evaluate and pursue acquisition opportunities that fit our business model. We believe this balanced approach is appropriate for long-term success; however, it is not our intention or desire to pursue acquisitions solely for the sake of growth, but rather that fit our strategic and economic objectives.

In order to ensure that we preserve the necessary financial flexibility, we work closely with our lenders to stay abreast of market and creditor conditions. Of note, our capital expenditures are primarily in areas where we act as 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 and we monitor partner situations routinely.

Results of Operations

Revenues. Our revenues are derived from the sale of our natural gas, oil and NGL production, which includes the effects of contracts that qualify for hedge accounting. Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold.

Total revenue, including the effects of hedging, for the three months ended June 30, 2010 was $68.6 million, which is a decrease of $5.0 million, or 7%, from $73.6 million for the three months ended June 30, 2009. Total revenue, excluding the effects of hedging, for the three months ended June 30, 2010 was $62.9 million, which is an increase of $11.2 million, or 22%, from $51.7 million for the three months ended June 30, 2009. Approximately 69% of our revenue for the three months ended June 30, 2010 was attributable to natural gas sales as compared to 85% for the same period in 2009.

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Total revenue, including the effects of hedging, for the six months ended June 30, 2010 was $138.8 million, which is a decrease of $14.2 million, or 9%, from $153.0 million for the six months ended June 30, 2009. Total revenue, excluding the effects of hedging, for the six months ended June 30, 2010 was $130.2 million, which is an increase of $14.4 million, or 12%, from $115.8 million for the six months ended June 30, 2009. Approximately 74% of our revenue in the first six months of 2010 was attributable to natural gas sales as compared to 87% for the same period in 2009.

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2010		2009		% Change Increase/ (Decrease)			2010		2009		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Natural gas sales	$	47,491	$	62,471		(24	%)	$	103,298	$	133,031		(22	%)
Oil sales		10,773		6,463		67	%		17,756		11,681		52	%
NGL sales		10,358		4,616		124	%		17,716		8,280		114	%
Total revenues	$	68,622	$	73,550		(7	%)	$	138,770	$	152,992		(9	%)

Production:
Gas (Bcf)		9.9		11.6		(15	%)		19.5		24.3		(20	%)
Oil (MBbls)		147.0		116.0		27	%		238.6		249.8		(4	%)
NGLs (MBbls)		248.8		167.2		49	%		414.3		305.9		35	%
Total Equivalents (Bcfe)		12.2		13.3		(8	%)		23.4		27.7		(16	%)

$ per unit:
Avg. natural gas price per Mcf	$	4.80	$	5.39		(11	%)	$	5.30	$	5.47		(3	%)
Avg. natural gas price per Mcf, excluding hedging		4.22		3.51		20	%		4.86		3.95		23	%
Avg. oil price per Bbl		73.29		55.72		32	%		74.42		46.76		59	%
Avg. NGL price per Bbl		41.63		27.61		51	%		42.76		27.07		58	%
Avg. revenue per Mcfe		5.62		5.53		2	%		5.93		5.52		7	%

Natural Gas. For the three months ended June 30, 2010, natural gas revenue, including the realized impact of derivative instruments, decreased by $15.0 million, or 24%, from the same period in 2009, to $47.5 million from $62.5 million. This decrease is primarily due to the decrease in production as a result of the curtailed capital drilling program in 2009. The average gas price, including the effects of hedging, decreased by $0.59 per Mcf from $5.39 per Mcf for the three months ended June 30, 2009 to $4.80 per Mcf for the same period in 2010. The effect of natural gas hedging activities on natural gas revenue for the three months ended June 30, 2010 was a gain of $5.7 million as compared to a gain of $21.8 million for the three months ended June 30, 2009.

For the six months ended June 30, 2010, natural gas revenue, including the realized impact of derivative instruments, decreased by $29.7 million, or 22%, from the same period in 2009, to $103.3 million from $133.0 million. This decrease is primarily due to the decrease in production as a result of the curtailed capital drilling program in 2009. The average gas price, including the effects of hedging, decreased by $0.17 per Mcf from $5.47 per Mcf for the six months ended June 30, 2009 to $5.30 per Mcf for the same period in 2010. The effect of natural gas hedging activities on natural gas revenue for the six months ended June 30, 2010 was a gain of $8.6 million as compared to a gain of $37.2 million for the six months ended June 30, 2009.

Crude Oil. For the three months ended June 30, 2010, oil revenue increased by $4.3 million, or 67%, to $10.8 million compared to $6.5 million for the same period in 2009. This increase is attributable to an increase in the average realized price from $55.72 per Bbl for the three months ended June 30, 2009 to $73.29 per Bbl for the three months ended June 30, 2010. Oil production also increased by 27%, or 31.0 MBbls, to 147.0 MBbls for the three months ended June 30, 2010 from 116.0 MBbls for the three months ended June 30, 2009 due to new wells in Eagle Ford that flowed to sales in the second quarter of 2010.

For the six months ended June 30, 2010, oil revenue increased by $6.1 million, or 52%, to $17.8 million compared to $11.7 million for the same period in 2009. This increase is attributable to an increase in the average realized price from $46.76 per Bbl for the six months ended June 30, 2009 to $74.42 per Bbl for the six months ended June 30, 2010. The increase in oil revenue is partially offset by a decline in oil production which decreased by 4%, or 11.2 MBbls, to 238.6 MBbls for the six months ended June 30, 2010 from 249.8 MBbls for the six months ended June 30, 2009.

NGLs. For the three months ended June 30, 2010, NGL revenue increased by $5.8 million, or 124%, to $10.4 million compared to $4.6 million for the same period in 2009. This increase is attributable to an increase in the average realized price from $27.61 per Bbl for the three months ended June 30, 2009 to $41.63 per Bbl for the three months ended June 30, 2010. Production for natural gas liquids also increased by 49%, or 81.6 MBbls, to 248.8 MBbls for the three months ended June 30, 2010 from 167.2 MBbls for the three months ended June 30, 2009 due to new wells in Eagle Ford that flowed to sales in the second quarter of 2010.

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For the six months ended June 30, 2010, NGL revenue increased by $9.4 million, or 114%, to $17.7 million compared to $8.3 million for the same period in 2009. This increase is attributable to an increase in the average realized price from $27.07 per Bbl for the six months ended June 30, 2009 to $42.76 per Bbl for the six months ended June 30, 2010. Production for natural gas liquids also increased by 35%, or 108.4 MBbls, to 414.3 MBbls for the six months ended June 30, 2010 from 305.9 MBbls for the same period in 2009 due to new wells in Eagle Ford that flowed to sales in the first six months of 2010.

Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended June 30,							Six Months Ended June 30,
	2010		2009		% Change Increase/ (Decrease)			2010		2009		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	13,310	$	16,568		(20	%)	$	27,987	$	34,609		(19	%)
Production taxes		1,085		1,750		(38	%)		3,375		3,074		10	%
Depreciation, depletion and amortization		25,719		28,499		(10	%)		49,533		72,900		(32	%)
Impairment of oil and gas properties		-		-		-			-		379,462		(100	%)
General and administrative costs		11,326		12,571		(10	%)		23,133		21,944		5	%

$ per unit:
Avg. lease operating expense per Mcfe	$	1.09	$	1.25		(12	%)	$	1.20	$	1.25		(4	%)
Avg. production taxes per Mcfe		0.09		0.13		(31	%)		0.14		0.11		27	%
Avg. DD&A per Mcfe		2.11		2.14		(1	%)		2.12		2.63		(19	%)
Avg. production costs per Mcfe (1)		3.20		3.39		(6	%)		3.31		3.88		(15	%)
Avg. G&A per Mcfe		0.93		0.95		(2	%)		0.99		0.79		25	%

(1)	Average production costs per Mcfe include lease operating expense and depreciation, depletion and amortization (“DD&A”).

Lease Operating Expense. Lease operating expense decreased $3.3 million to $13.3 million from $16.6 million for the three months ended June 30, 2010 as compared to the three months ended June 30, 2009. The overall decrease is due primarily to the divestiture of the Sabine Lake asset and overall lease operating expense reduction efforts.

Lease operating expense decreased $6.6 million to $28.0 million from $34.6 million for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. The overall decrease is due primarily to the divestiture of the Sabine Lake asset and overall lease operating expense reduction efforts.

Production Taxes. Production taxes as a percentage of unhedged natural gas, oil and NGL sales were 1.7% for the three months ended June 30, 2010 as compared to 3.4% for the three months ended June 30, 2009. This decrease in rate was primarily due to certain production tax credits in the state of Texas.

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Production taxes as a percentage of unhedged natural gas, oil and NGL sales were 2.6% for the six months ended June 30, 2010 as compared to 2.7% for the six months ended June 30, 2009.

Depreciation, Depletion and Amortization. DD&A expense decreased $2.8 million to $25.7 million for the three months ended June 30, 2010 as compared to $28.5 million for the three months ended June 30, 2009. The decrease is due to a decline in production from the three months ended June 30, 2009 to the three months ended June 30, 2010. The DD&A rate for the second quarter of 2010 was $2.11 per Mcfe and was comparable with the rate for the second quarter of 2009 of $2.14 per Mcfe.

DD&A expense decreased $23.4 million to $49.5 million for the six months ended June 30, 2010 as compared to $72.9 million for the six months ended June 30, 2009. The decrease is due to the full cost ceiling test impairment charges recognized 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, 2010 was $2.12 per Mcfe while the rate for the six months ended June 30, 2009 was $2.63 per Mcfe. The decrease in the rate was due to the lower full cost asset base during 2010, which resulted from a first quarter 2009 impairment charge.

Impairment of Oil and Gas Properties. Based upon quarterly ceiling test computations using a trailing twelve-month average price using first day of the month prices, adjusted for hedges, of oil and gas, there was no write-down required to be recorded at June 30, 2010.

Based upon the quarterly ceiling test computations using hedge adjusted market prices, the net capitalized costs of oil and natural gas properties exceeded the cost center ceiling at March 31, 2009. As such, a pre-tax, non-cash impairment expense of $379.5 million was recorded at March 31, 2009. Net capitalized costs of oil and natural gas properties did not exceed the cost center ceiling at June 30, 2009 and as such, the Company did not record a write-down at June 30, 2009.

General and Administrative Costs. General and administrative costs decreased $1.3 million to $11.3 million for the three months ended June 30, 2010 as compared to $12.6 million for the three months ended June 30, 2009. This decrease is primarily due to a $0.8 million decrease in contract services, a $0.7 million decrease due to the capitalization of geological and geophysical costs, a $0.3 million decrease in general and administrative expenses allocated to joint venture partners and a decrease of $0.6 million of other general and administrative costs. These decreases are partially offset by an increase of $0.9 million in salaries, wages and benefits expense due to an increase in headcount of employees as well as an increase of $0.2 million in bonus accrual for the three months ended June 30, 2010 as compared to the three months ended June 30, 2009.

General and administrative costs increased $1.2 million to $23.1 million for the six months ended June 30, 2010 as compared to $21.9 million for the six months ended June 30, 2009. This increase is primarily due to a $2.2 million increase in salaries, wages and benefits expense due to an increase in headcount of employees, a $1.6 million increase in stock based compensation expense, and a $0.9 million increase in bonus accrual. These increases are partially offset by a $1.4 million decrease due to the capitalization of geological and geophysical costs, a $1.3 million decrease in contract services, a $0.6 million decrease in general and administrative expenses allocated to joint venture partners and a decrease of $0.2 million of other general and administrative costs for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009.

Total Other Expense

Total other expense includes Interest expense, net of interest capitalized; Interest income; and Other income/expense, net, which increased $2.1 million to $8.5 million for the three months ended June 30, 2010 from $6.4 million for the three months ended June 30, 2009. The increase in other expense was due to an increase in interest expense. Long-term debt outstanding as of June 30, 2010 was $22.5 million higher as compared to June 30, 2009. The weighted average interest rate for the second quarter of 2010 was 7.41% compared to 6.06% for the same period in 2009. This increase in the weighted average interest rate was primarily due to higher interest rates associated with the Restated Term Loan and the Senior Notes.

Total other expense includes Interest expense, net of interest capitalized; Interest income; and Other income/expense, net, which increased $4.3 million to $13.0 million for the six months ended June 30, 2010 from $8.7 million for the six months ended June 30, 2009. The increase in other expense was due to an increase in interest expense. Long-term debt outstanding as of June 30, 2010 was $22.5 million higher as compared to June 30, 2009. The weighted average interest rate for the six months ended June 30, 2010 was 6.82% compared to 4.12% for the same period in 2009. This increase in the weighted average interest rate was primarily due to higher interest rates associated with the Restated Term Loan and the Senior Notes.

Provision for Income Taxes

The effective tax rate for the three and six months ended June 30, 2010 was 40.76% and 38.5%, respectively. This increase in rate was due to the non-deductibility of certain executive compensation. The effective tax rate for the three and six months ended June 30, 2009 was 37.2% and 36.9%, respectively. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes.

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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 authoritative guidance for 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, 2010, we have a deferred tax asset of approximately $158.9 million resulting primarily from the difference between the book basis and tax basis of our oil and natural gas properties. We have concluded 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.

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 may 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.” The majority of our capital expenditures is 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 or conduct additional asset sales to generate liquidity.

Senior Secured Revolving Line of Credit. Our Restated Revolver provides for a senior secured revolving line of credit of up to $600.0 million and matures on 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. Amounts outstanding under the Restated Revolver bear interest at specified margins over the 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 equity 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 after giving pro forma effect to acquisitions and divestitures. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at June 30, 2010. Our semi-annual borrowing base review was completed April 1, 2010, and the borrowing base under the Restated Revolver was redetermined to be $375.0 million, subject to certain mandatory adjustments, including adjustments upon the issuance of the Senior Notes. As a result of our Senior Notes offering on April 15, 2010, the borrowing base under our Restated Revolver was reduced by $30.0 million to $345.0 million. We took additional borrowings of $25.0 million on the Restated Revolver during the first quarter of 2010 and, as a result of the Senior Notes offering on April 15, 2010, we repaid $114.0 million on the Restated Revolver and had $101.0 million outstanding, with $244.0 million available for borrowing under the Restated Revolver as of June 30, 2010. We took additional borrowings of $19.0 million under the Restated Revolver in July 2010 and as a result, the amount outstanding increased from $101.0 million to $120.0 million under the Restated Revolver as of July 31, 2010 and the available borrowing capacity decreased $19.0 million from $244.0 million to $225.0 million under the Restated Revolver as of July 31, 2010.

Second Lien Term Loan. Our Restated Term Loan matures on October 2, 2012. Under the Restated Term Loan, as of March 31, 2010 we had $80.0 million of variable rate borrowings, bearing interest at LIBOR plus 8.5% with a LIBOR floor of 3.5% and $20.0 million of fixed rate borrowings bearing interest 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 after giving pro forma effect to acquisitions and divestitures. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at June 30, 2010. On April 15, 2010, in connection with our issuance of the 9.500% Senior Notes, we repaid all $80.0 million of variable rate borrowings under the Restated Term Loan together with accrued interest and a prepayment premium. We also have the right to prepay the fixed portion of $20.0 million of the Restated Term Loan with a make-whole amount at a discount factor equal to 1% plus the U.S. Treasury yield security having a maturity closest to the remaining life of the loan.

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Senior Notes. On April 15, 2010, we issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes (“Senior Notes”) due 2018. The Senior Notes were issued under an indenture (the “Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the Indenture limit our ability to, among other things, incur additional indebtedness; pay dividends on the Company’s capital stock or purchase, repurchase, redeem, defease or retire our capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The Indenture also contains customary events of default. We used the proceeds from the Senior Notes offering to repay $80.0 million of variable rate borrowings under our Restated Term Loan, to repay $114.0 million under our Restated Revolver and to pay for fees and expenses associated with the offering. Interest is payable on the Senior Notes semi-annually on April 15 and October 15.

Cash Flows

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

	Six Months Ended June 30,
		2010			2009
		(In thousands)
Cash flows provided by operating activities	$	75,815		$	77,103
Cash flows used in investing activities		(145,002	)		(62,444	)
Cash flows provided by (used in) financing activities		24,789			(7,994	)
Net (decrease)/increase in cash and cash equivalents	$	(44,398	)	$	6,665

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.

Cash flows provided by operating activities were flat for the six months ended June 30, 2010 as compared to the same period for 2009.

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

Cash flows used in investing activities increased by $82.6 million for the six months ended June 30, 2010 as compared to the same period for 2009. During the six months ended June 30, 2010, we participated in the drilling of 94 gross wells as compared to the drilling of 27 gross wells during the same period in 2009.

Financing Activities. The primary drivers of cash provided by (used in) 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 provided by financing activities increased by $32.8 million for the six months ended June 30, 2010 as compared to the same period for 2009. The net increase is primarily related to the borrowings on the revolving credit facility of $25.0 million during the first quarter of 2010 and the net impact of the $200.0 million issuance of the Senior Notes and repayment of $80.0 million under the Restated Term Loan and $114.0 under the Restated Revolver.

Capital Expenditures

Our capital expenditures for the six months ended June 30, 2010 increased by $111.1 million to $166.0 million, from $54.9 million compared to the same period in 2009. During the six months ended June 30, 2010, we participated in the drilling of 94 gross wells with the majority of these being in the Rockies region. Our positive operating cash flow and cash on hand may not be sufficient to invest in planned capital expenditures for 2010, which are now projected to be $310.0 million, an increase of $30.0 million from the announced 2010 capital program. We have the discretion to adjust capital investment plans throughout the remainder of the year in response to market conditions and the availability of proceeds from possible divestitures. In addition, we may draw on our Restated Revolver, if required, and/or access the capital markets.

Capital Requirements

The historical capital expenditures summary table is included in Items 1 and 2. Business and Properties in our 2009 Annual Report and is incorporated herein by reference.

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Initially, we announced a 2010 capital program of $280.0 million. We now expect to spend approximately $310.0 million, primarily reflecting leasehold purchases and services cost increases in the Eagle Ford where the vast majority of our planned drilling capital is allocated. For the six months ended June 30, 2010, our capital expenditures were $166.0 million. At current commodity prices, the anticipated capital spending is expected to exceed internally generated cash flows. We have the discretion to use our available borrowing base, proceeds from divestitures to fund capital expenditures, including acquisitions, and/or accessing the capital markets.

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 and costless collars, which are intended to establish a fixed price or an average floor and ceiling price for 11% to 23% of our expected proved net reserves through 2012. Our fixed-price swap agreements 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 net reserves from existing wells at inception of the hedge instruments.

Borrowings under our Restated Revolver and Restated Term Loan mature on July 1, 2012 and October 2, 2012, respectively, and with respect to the Restated Revolver bear interest at a LIBOR-based rate while the $20.0 million outstanding under our Restated Term Loan bears interest at a fixed rate of 13.75%. After April 15, 2010, there was no ongoing interest rate risk under our Restated Term Loan due to the repayment of the $80.0 million variable rate borrowings. The exposure to LIBOR under the Restated Revolver exposes us to risk of earnings loss due to increases in market interest rates. To mitigate this exposure, 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.

The following table sets forth the results of commodity and interest rate swap hedging transaction settlements:

	Three Months Ended June 30,						Six Months Ended June 30,
Natural Gas	2010			2009			2010			2009
Quantity settled (MMBtu)		2,275,000			5,199,831			4,525,000			10,342,521
Increase in natural gas sales revenue (In thousands)	$	5,721		$	21,802		$	8,598		$	37,159
Interest Rate Swaps
(Increase) in interest expense (In thousands)	$	(238	)	$	(522	)	$	(490	)	$	(1,034	)

In accordance with the authoritative guidance for derivatives, 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).

As of June 30, 2010, our commodity and interest rate hedge positions were with counterparties that were also lenders 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, 2010, we had no deposits for collateral.

Governmental Regulation

Climate Change. Current and future regulatory initiatives directed at climate change may increase our operating costs and may, in the future, reduce the demand for some of our produced materials. The United States Congress is currently considering legislation on climate change. In June 2009, the U.S. House of Representatives passed a comprehensive clean energy and climate bill (H.R. 2454, also known as “Waxman-Markey”). The U.S. Senate is working on a variety of proposed climate bills, including the American Power Act of 2010 (proposed by Senators Kerry and Lieberman). These bills have a variety of provisions and differences, but in substance they both propose a “cap and trade” approach to greenhouse gas regulation. Under such an approach, companies would be required to hold sufficient emission allowances to cover their greenhouse gas emissions. Over time, the total number of allowances would be reduced or expire, thereby relying on market-based incentives to allocate investment in emission reductions across the economy. As the number of available allowances declines, the cost would presumably increase. In addition to the prospect of federal legislation, several states have adopted or are in the process of adopting greenhouse gas reporting or cap-and-trade programs. Therefore, while the outcome of the federal and state legislative processes is currently uncertain, if such an approach were adopted (either by domestic legislation, international treaty obligation or domestic regulation), we would expect our operating costs to increase as we buy additional allowances or embark on emission reduction programs.

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Even without further federal legislation, the United States Environmental Protection Agency (EPA) may act to regulate greenhouse gas emissions. In April 2007, the United States Supreme Court concluded that greenhouse gas emissions from automobiles were “air pollutants” within the meaning of the applicable provisions of the federal Clean Air Act. Relying in part on that precedent, in December 2009, the EPA released an Endangerment and Cause or Contribute Findings for Greenhouse Gases, which became effective in January 2010. This regulatory finding sets the foundation for future EPA greenhouse gas regulation under the Clean Air Act. The EPA also promulgated a new greenhouse gas reporting rule, which became effective in December 2009, and which requires facilities that emit more than 25,000 tons per year of carbon dioxide-equivalent emissions to prepare and file certain emission reports. The portion of the rule pertaining to fugitive and vented methane emissions from the oil and gas sector has not yet been incorporated into the final rule and remains proposed. If this portion of the proposed rule is ultimately promulgated, some of our facilities may be subject to the reporting requirements. On May 12, 2010, the EPA issued a new “tailoring” rule, which proposed a imposes additional permitting requirements on certain stationary sources emitting over 75,000 tons per year of carbon dioxide equivalent emissions. The EPA is considering additional rulemaking to apply these requirements to broader classes of emission sources by 2012, which may apply to some of our facilities. Finally, on April 12, 2010, the EPA proposed rules to expand the industries subject to greenhouse gas reporting to include certain petroleum and natural gas facilities. If adopted, these rules would require data collection beginning in 2011 and reporting beginning in 2012. Depending on the final outcome of these rulemakings, some of our facilities may be subject to these rules. As a result of these regulatory initiatives, our operating costs may increase in compliance with these programs, although we are not situated differently in this respect from our competitors in the industry.

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 we 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 our financial position, results of operations or cash flows.

Critical Accounting Policies and Estimates

In our 2009 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 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 a trailing twelve-month average price using first day of the month prices, adjusted for hedges, of gas and oil at June 30, 2010, which were based on a Henry Hub gas price of $4.10 per MMBtu and a West Texas Intermediate oil price of $72.25 per Bbl (adjusted for basis and quality differentials). Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and gas properties. As a result, no write-down was recorded at June 30, 2010. It is possible that a write-down of our oil and gas properties could occur in the future should oil and natural gas prices decline, we experience significant downward adjustments to the estimated proved reserves, and/or our commodity hedges settle and are not replaced.

We have entered into natural gas price hedging arrangements with respect to a portion of our expected proved net reserves through 2012. As of June 30, 2010, 4,600,000 MMBtu and 5,520,000 MMBtu of our expected proved net reserves was hedged using swaps and costless collars, respectively, with settlement in 2010, 5,475,000 MMBtu and 12,775,000 MMBtu of our expected proved net reserves was hedged using swaps and costless collars, respectively, with settlement in 2011, and 3,660,000 MMBtu of our expected proved net reserves was hedged using costless collars, with settlement in 2012. The swaps to settle in 2010 have an average price of $6.83 per MMBtu and the collars have floor and ceiling prices of $5.75 per MMBtu and $7.12 per MMBtu, respectively. The swaps to settle in 2011 have an average price of $5.85 per MMBtu and the collars have floor and ceiling prices of $5.79 per MMBtu and $7.27 per MMBtu, respectively. The collars to settle in 2012 have floor and ceiling prices of $5.75 per MMBtu and $7.15 per MMBtu, respectively. Approximately 83% 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, 2010, 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, 2010. 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, 2010.

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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, 2010 for NYMEX futures contracts and exchange traded contracts for each derivative settlement location. We have used this valuation technique since the adoption of the authoritative guidance for fair value measurements 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.

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 and our interest rate risk caused by fluctuating interest rates. 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 2009 Annual Report and Note 4 - Commodity Hedging Contracts and Other Derivatives included in Part I. Item 1. Financial Statements of this Form 10-Q.

At June 30, 2010, we had open natural gas derivative hedges in an asset position with a fair value of $32.4 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $13.8 million, while a 10 percent decrease in natural gas prices would increase the fair value by approximately $14.3 million. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas”. Additionally, at June 30, 2010, we had open interest rate swap hedges in a liability position of $0.4 million. A 10 percent increase in interest rates would increase the fair value by approximately $0.02 million, while a 10 percent decrease in interest rates would decrease the fair value by approximately $0.02 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2010.

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 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, 2010. 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

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 Exchange Act, as of June 30, 2010. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2010, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2010 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 legal proceedings in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the consolidated financial statements.

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Item 1A. Risk Factors

Other than with respect to the risk factors below, there have been no material changes in our risk factors from those previously disclosed in Item 1A. of our 2009 Annual Report and in Item 1A of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010.

Possible regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be contributing to the warming of the Earth's atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. The U.S. Congress is considering climate-related legislation to reduce emissions of greenhouse gases. In addition, at least 20 states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. The EPA has adopted regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as "air pollutants" under the existing federal Clean Air Act. On April 12, 2010, the EPA proposed rules to expand the industries subject to greenhouse gas reporting to include certain petroleum and natural gas facilities. If adopted, these rules would require data collection beginning in 2011 and reporting beginning in 2012. Depending on the final outcome of pending rulemakings, some of our facilities may be subject to these rules. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of other regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.

Government laws and regulations can change.

Our activities are subject to federal, state, regional and local laws and regulations. Extensive laws, regulations and rules relate to activities and operations in the oil and gas industry. Some of the laws, regulations and rules contain provisions for significant fines and penalties for non-compliance. Changes in laws and regulations could affect our costs of operations, production levels, royalty obligations, price levels, environmental requirements, and other matters affecting our business, including our general profitability. We are unable to predict changes to existing laws and regulations or additions to laws and regulations. For example, in response to the April 2010 fire and explosion onboard the semisubmersible drilling rig Deepwater Horizon, leading to the oil spill currently affecting the Gulf of Mexico, the Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or “BOE”) of the U.S. Department of the Interior has limited certain drilling activities in the U.S. Gulf of Mexico. The BOE may also issue new safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico, and potentially in other geographic regions, and may take other steps that could increase the costs of exploration and production. This incident could also result in drilling suspensions or other regulatory initiatives in other areas of the U.S. and abroad. Furthermore, the U.S. Environmental Protection Agency has recently focused on public concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities. This renewed focus could lead to additional federal and state regulations affecting the oil and gas industry. Additional regulations or other changes to existing laws and regulations could significantly impact our business, results of operations, cash flows, financial position and future growth.

Market conditions or transportation impediments may hinder our access to oil and natural gas and natural gas liquids markets or delay our production.

Market conditions, the unavailability of satisfactory oil, natural gas, and natural gas liquids handling, treating, processing and transportation infrastructure or the remote location of certain of our drilling operations may hinder our access to oil, natural gas and natural gas liquids markets or delay our production. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for and supply of oil, natural gas and natural gas liquids and the proximity of reserves to pipelines or trucking and terminal facilities. Under interruptible or short term transportation agreements, the transportation of our natural gas and natural gas liquids may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons specified by the particular agreements. We may be required to shut in natural gas wells or delay initial production for lack of a market or because of inadequacy or unavailability of natural gas pipelines or gathering system capacity and natural gas liquids handling capacity. When that occurs, we are unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil, natural gas and natural gas liquids and realization of revenues.

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Competition and permitting for hydraulic fracturing services could impede our ability to develop our shale plays.

The unavailability or high cost of high pressure pumping services (or hydraulic fracturing services), chemicals, proppant, water, and related services and equipment could adversely limit our ability to execute our exploration and development plans on a timely basis and within our budget. Our industry is experiencing a growing emphasis on the exploitation and development of shale gas and shale oil resource plays which are dependent on hydraulic fracturing for economically successful development. Hydraulic fracturing in shale plays requires high pressure pumping service crews to pump large quantities of proppant, chemicals, and water into the shale formation. A shortage of service crews or proppant, chemical, or water, especially if this shortage occurred in South Texas or the Rockies, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget. There is significant regulatory uncertainty as the United States Environmental Protection Agency and United States Congress are investigating the impact of hydraulic fracturing on drinking water sources which could affect the current regulatory jurisdiction of the states and increase the cycle times and costs to receive permits, delay or possibly preclude receipt of permits in certain areas, impact water usage and waste water disposal and require chemical additives disclosures.

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, 2010:

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 Be Purchased Under the Plans or Programs
April 1 - April 30		1,016	$	23.89		-		-
May 1 - May 31		28,327		21.99		-		-
June 1 - June 30		2,284		21.44		-		-
Total		31,627	$	22.01		-		-

___________________________________

(1)	All of the shares were surrendered by our employees to pay tax withholding upon the vesting of restricted stock awards.

Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Removed and Reserved

None.

Item 5. Other Information

None.

Item 6. Exhibits

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Exhibit Number		Description
3.1		Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Registration Statement on Form S-1 of Rosetta Resources Inc. (the "Company") filed on October 7, 2005 (Registration No. 333-128888)).
3.2		Amended and Restated Bylaws (incorporated herein 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		Indenture, dated April 15, 2010 amoung the Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K filed April 19, 2010 (Registration No. 000-51801)).
4.2		Form of 9.500% Senior Note due 2018 (included as Exhibit A to Exhibit 4.1 above).
4.3		Registration Rights Agreement, dated April 15, 2010, among the Company, the Subsidiary Guarantors and J.P. Morgan Securities Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 of the Company's Current Report on Form 8-K filed April 19, 2010 (Registration No. 000-51801)).
10.1		Second Amendment to Amended and Restated Senior Revolving Credit Agreement, effective as of April 5, 2010, among Rosetta Resources Inc., as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.2		Second Amendment to Amended and Restated Second Lien Term Loan Agreement, effective as of April 5, 2010, among Rosetta Resources Inc., as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.3		Purchase Agreement among Rosetta Resources Inc., the subsidiaries of Rosetta Resources Inc., and JP Morgan Securities Inc., (incorporated herein by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed on April 13, 2010 (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.

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 9, 2010

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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 Registration Statement on Form S-1 of Rosetta Resources Inc. (the "Company") filed on October 7, 2005 (Registration No. 333-128888)).
3.2		Amended and Restated Bylaws (incorporated herein 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		Indenture, dated April 15, 2010 amoung the Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K filed April 19, 2010 (Registration No. 000-51801)).
4.2		Form of 9.500% Senior Note due 2018 (included as Exhibit A to Exhibit 4.1 above).
4.3		Registration Rights Agreement, dated April 15, 2010, among the Company, the Subsidiary Guarantors and J.P. Morgan Securities Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 of the Company's Current Report on Form 8-K filed April 19, 2010 (Registration No. 000-51801)).
10.1		Second Amendment to Amended and Restated Senior Revolving Credit Agreement, effective as of April 5, 2010, among Rosetta Resources Inc., as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.2		Second Amendment to Amended and Restated Second Lien Term Loan Agreement, effective as of April 5, 2010, among Rosetta Resources Inc., as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.3		Purchase Agreement among Rosetta Resources Inc., the subsidiaries of Rosetta Resources Inc., and JP Morgan Securities Inc., (incorporated herein by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed on April 13, 2010 (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.