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 March 31, 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 May 5, 2010 was 52,709,870.

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Part I –	Financial Information
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	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	26
	Item 3. Defaults upon Senior Securities	26
	Item 4. Removed and Reserved	26
	Item 5. Other Information	26
	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 share amounts)

	March 31, 2010			December 31, 2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	49,907		$	61,256
Accounts receivable		32,443			32,691
Derivative instruments		26,212			8,983
Prepaid expenses		2,194			2,837
Other current assets		5,493			6,415
Total current assets		116,249			112,182
Oil and natural gas properties, full cost method, of which $81.6 million at March 31, 2010 and $42.3 million at December 31, 2009 were excluded from amortization		2,109,877			2,030,433
Other fixed assets		13,384			12,417
		2,123,261			2,042,850
Accumulated depreciation, depletion, and amortization, including impairment		(1,475,504	)		(1,452,248	)
Total property and equipment, net		647,757			590,602

Deferred loan fees		4,440			4,921
Deferred tax asset		160,893			169,732
Derivative instruments		10,588			-
Other assets		2,155			2,147
Total other assets		178,076			176,800
Total assets	$	942,082		$	879,584

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	3,543		$	2,279
Accrued liabilities		41,173			37,107
Royalties payable		14,070			16,064
Derivative instruments		388			236
Prepayment on gas sales		7,642			7,542
Deferred income taxes		9,619			3,258
Total current liabilities		76,435			66,486
Long-term liabilities:
Derivative instruments		-			1,960
Long-term debt		313,856			288,742
Other long-term liabilities		30,564			29,301
Total liabilities		420,855			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 51,556,040 shares and 51,254,709 shares at March 31, 2010 and December 31, 2009, respectively		51			51
Additional paid-in capital		783,726			780,196
Treasury stock, at cost; 260,171 and 199,955 shares at March 31, 2010 and December 31, 2009, respectively		(4,723	)		(3,473	)
Accumulated other comprehensive income		22,848			4,259
Accumulated deficit		(280,675	)		(287,938	)
Total stockholders' equity		521,227			493,095
Total liabilities and stockholders' equity	$	942,082		$	879,584

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 March 31,
	2010			2009
Revenues:
Natural gas sales	$	55,807		$	70,559
Oil sales		6,983			5,218
NGL sales		7,358			3,664
Total revenues		70,148			79,441
Operating costs and expenses:
Lease operating expense		14,677			18,041
Depreciation, depletion, and amortization		23,814			44,400
Impairment of oil and gas properties		-			379,462
Treating, transportation and marketing		1,481			2,019
Production taxes		2,290			1,323
General and administrative costs		11,807			9,373
Total operating costs and expenses		54,069			454,618
Operating income (loss)		16,079			(375,177	)

Other (income) expense:
Interest expense, net of interest capitalized		4,746			2,535
Interest income		(11	)		(51	)
Other (income) expense, net		(203	)		(150	)
Total other expense		4,532			2,334

Income (loss) before provision for income taxes		11,547			(377,511	)
Income tax expense (benefit)		4,284			(139,378	)
Net income (loss)	$	7,263		$	(238,133	)

Earnings (loss) per share:
Basic	$	0.14		$	(4.68	)
Diluted	$	0.14		$	(4.68	)

Weighted average shares outstanding:
Basic		51,219			50,920
Diluted		51,920			50,920

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)

	Three Months Ended March 31,
	2010			2009
Cash flows from operating activities
Net income (loss)	$	7,263		$	(238,133	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		23,814			44,400
Impairment of oil and gas properties		-			379,462
Deferred income taxes		4,164			(138,826	)
Amortization of deferred loan fees recorded as interest expense		481			212
Amortization of original issue discount recorded as interest expense		114			-
Stock compensation expense		2,631			917
Change in operating assets and liabilities:
Accounts receivable		248			12,111
Prepaid expenses		643			635
Other current assets		922			(586	)
Other assets		(8	)		(107	)
Accounts payable		1,264			(471	)
Accrued liabilities		(2,762	)		(6,910	)
Royalties payable		(1,894	)		(13,162	)
Net cash provided by operating activities		36,880			39,542
Cash flows from investing activities
Acquisition of oil and gas properties		-			(3,844	)
Additions of oil and gas assets		(73,591	)		(50,018	)
Disposals of oil and gas properties and assets		21			-
Other		-			(16	)
Net cash used in investing activities		(73,570	)		(53,878	)
Cash flows from financing activities
Borrowings on revolving credit facility		25,000			5,000
Proceeds from stock options exercised		1,591			-
Purchases of treasury stock		(1,250	)		(548	)
Net cash provided by financing activities		25,341			4,452

Net decrease in cash		(11,349	)		(9,884	)
Cash and cash equivalents, beginning of period		61,256			42,855
Cash and cash equivalents, end of period	$	49,907		$	32,971

Supplemental disclosures:
Capital expenditures included in accrued liabilities	$	25,027		$	7,170

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 positions in the State Waters of Texas and the Gulf of Mexico.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments necessary 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 March 31, 2010 and December 31, 2009 and for the three months ended March 31, 2010 and 2009 contain the accounts of the Company and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.

Recent Accounting Developments

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

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 shall be presented separately. These disclosures will be 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 March 31, 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 will not 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 March 31, 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 consist of the following:

	March 31, 2010			December 31, 2009
	(In thousands)
Proved properties	$	1,986,060		$	1,949,515
Unproved/unevaluated properties		81,580			42,344
Gas gathering system and compressor stations		42,237			38,574
Other fixed assets		13,384			12,417
Total property and equipment, gross		2,123,261			2,042,850
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,475,504	)		(1,452,248	)
Total property and equipment, net	$	647,757		$	590,602

In the first quarter of 2010, the Company increased its working interest in certain properties in South Texas from 70% to 100% for $12.5 million. In addition, the Company also purchased a non-producing leasehold in South Texas for $11.3 million.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.7 million and $1.0 million of internal costs for the three months ended March 31, 2010 and 2009, respectively.

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

Oil and gas properties include costs of $81.6 million and $42.3 million at March 31, 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 March 31, 2010 is a result of leasehold acquisitions and the costs associated with unevaluated wells in the Rockies.

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 twelve-month average price using first day of the month prices, adjusted for hedges, of gas and oil at March 31, 2010, which were based on a Henry Hub gas price of $3.98 per MMBtu and a West Texas Intermediate oil price of $66.13 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 March 31, 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.

At March 31, 2009, the Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at March 31, 2009, which were based on a Henry Hub gas price of $3.63 per MMBtu and a West Texas Intermediate oil price of $46.00 per Bbl (adjusted for basis and quality differentials). As of March 31, 2009, the ceiling test calculation dictated that prices and costs in effect as of the last day of the quarter be held constant. Cash flow hedges of natural gas production in place at March 31, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax). Based upon this analysis, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009.

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(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 March 31, 2010:

Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor/Fixed Prices MMBtu		Average Ceiling Prices MMBtu		Natural Gas Production Hedged (1)			Fair Market Value Asset/(Liability) (In thousands)
2010	Swap	Cash flow		21,691		5,965,000	$	6.98	$	-		18	%	$	15,754
2010	Costless Collar	Cash flow		23,382		6,430,000		5.75		7.15		20	%		7,739
2011	Swap	Cash flow		15,000		5,475,000		5.85		-		14	%		3,954
2011	Costless Collar	Cash flow		35,000		12,775,000		5.79		7.27		32	%		7,968
2012	Costless Collar	Cash flow		10,000		3,660,000		5.75		7.15		12	%		1,641
						34,305,000								$	37,056

____________________________________

(1)

Estimated based on anticipated future gas production.

The Company has hedged the interest rates on $100.0 million of its outstanding debt through December 31, 2010. As of March 31, 2010, the Company had the following financial interest rate swap positions outstanding:

Settlement Period	Derivative Instrument	Hedge Strategy		Average Fixed ate				Fair Market Value Asset/(Liability) (In thousands)
April 1 - December 31, 2010	Swap	Cash Flow			1.24	%		$	(644	)

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 March 31, 2010, the Company made no deposits for collateral.

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

	Three Months Ended March 31,
Natural Gas	2010			2009
Quantity settled (MMBtu)		2,250,000			5,142,690
Increase in natural gas sales revenue (In thousands)	$	2,877		$	15,357
Interest Rate Swaps
(Increase) in interest expense (In thousands)	$	(252	)	$	(512	)

As of March 31, 2010, the Company expects to reclassify gains of $25.8 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 March 31, 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 March 31, 2010, the Company had outstanding natural gas commodity forward contracts with a notional volume of 34,305,000 MMBtus that were entered into to hedge forecasted natural gas sales.

As of March 31, 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 statement of financial position as of March 31, 2010 and December 31, 2009 and derivative gains and losses in the statement of operations for the three months ended March 31, 2010 and March 31, 2009 is as follows:

	Fair Values of Derivative Instruments

	Derivative Assets (Liabilities)

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

Interest rate swap	Derivative instruments - current assets	$	(256	)	$	(399	)
Interest rate swap	Derivative instruments - current liabilities		(388	)		(236	)
Commodity contracts	Derivative instruments - current assets		26,468			9,382
Commodity contracts	Derivative instruments - non-current assets		10,588			-
Commodity contracts	Derivative instruments - non-current liabilities		-			(1,960	)

Total derivatives designated as hedging instruments		$	36,412		$	6,787

Total derivatives not designated as hedging instruments		$	-		$	-

Total derivatives		$	36,412		$	6,787

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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							Three Months Ended
	March 31, 2010			March 31, 2009				March 31, 2010			March 31, 2009
	(In thousands)							(In thousands)

							Interest expense, net
Interest rate swap	$	(263	)	$	(33	)	of interest capitalized	$	(252	)	$	(512	)
Commodity contracts		32,513			39,133		Natural gas sales		2,877			15,357

Total	$	32,250		$	39,100		Total	$	2,625		$	14,845

(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 March 31, 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 March 31, 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 (“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.

–

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 March 31, 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 March 31, 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.

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	Fair value as of March 31, 2010
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (liabilities):
Money market funds	$	-	$	-	$	2,035		$	2,035
Commodity derivative contracts		-		-		37,056			37,056
Interest rate swap contracts		-		-		(644	)		(644	)
Total	$	-	$	-	$	38,447		$	38,447

	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 $0.2 million at March 31, 2010.

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2010. Level 3 instruments presented in the table consist of net derivatives that, in management’s judgment, reflect the assumptions a marketplace participant would have used at March 31, 2010.

	For the Three Months Ended March 31, 2010
	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)		Total
	(In thousands)

Balance at January 1, 2010	$	6,787		$	2,035	$	8,822
Total (gains) losses (realized or unrealized)
included in earnings		-			-		-
Included in other comprehensive income		32,250			-		32,250
Purchases, issuances and settlements		(2,625	)		-		(2,625	)
Transfers in and out of Level 3		-			-		-
Balance at March 31, 2010	$	36,412		$	2,035	$	38,447

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at March 31, 2010	$	-		$	-	$	-

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	For the Three Months Ended March 31, 2009
	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)		Total
	(In thousands)

Balance at January 1, 2009	$	38,372		$	5,025	$	43,397
Total (gains) losses (realized or unrealized)
included in earnings		-			7		7
included in other comprehensive income		39,100			-		39,100
Purchases, issuances and settlements		(14,845	)		-		(14,845	)
Transfers in and out of Level 3		-			-		-
Balance at March 31, 2009	$	62,627		$	5,032	$	67,659

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at March 31, 2009	$	-		$	-	$	-

At March 31, 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 March 31, 2010 is $313.9 million. The Company calculated the fair value of its long-term debt as of March 31, 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 $328.3 million at March 31, 2010.

(6) Asset Retirement Obligation

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

	Three Months Ended March 31, 2010
	(In thousands)

ARO as of December 31, 2009	$	28,920
Revision of previous estimates		(1	)
Liabilities incurred during period		11
Liabilities settled during period		(14	)
Accretion expense		575
ARO as of March 31, 2010	$	29,491

At March 31, 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 $28.5 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 Senior Notes, 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 limiting 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 March 31, 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 and had a total of $215.0 million outstanding with $135.0 million available for borrowing under the Restated Revolver as of March 31, 2010. 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 May 5, 2010.

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Second Lien Term Loan. The Company’s amended and restated term loan (the “Restated Term Loan”) matures on October 2, 2012. As of March 31, 2010, the Company had $80.0 million in 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%. 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. 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 limiting 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 March 31, 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. The Company has the right to prepay the floating portion of $80.0 million of the Restated Term Loan at any time on or after the first anniversary of the effective date (April 10, 2010), in whole or in part, from April 10, 2010 to April 10, 2011 with a premium equal to 2% of such amount prepaid or subsequent to April 10, 2011 without premium or penalty provided that each prepayment is in an amount that is an integral multiple of $1.0 million and not less than $1.0 million, or if such amount is less than $1.0 million, the outstanding principal amount. The Company also has 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.

As of March 31, 2010, the Company had total outstanding borrowings of $313.9 million and the Company’s weighted average borrowing rate was 6.18%.

(8) Income Taxes

The effective tax rate for the three months ended March 31, 2010 and 2009 was 37.1% 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 March 31, 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 its 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 March 31, 2010, the Company has a deferred tax asset of approximately $160.9 million resulting primarily from the difference between the book basis and tax basis of its oil and natural gas properties. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income from the production of its oil and natural gas properties prior to expiration of loss carryforwards. 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. 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.

(9) Commitments and Contingencies

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

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(10) Comprehensive Income (Loss)

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

	Three Months Ended March 31,
	2010					2009
	(In thousands)
Accumulated other comprehensive income, beginning of period				$	4,259				$	24,079
Net income (loss)	$	7,263				$	(238,133	)

Change in fair value of derivative hedging instruments		32,250					39,100
Hedge settlements reclassed to income		(2,625	)				(14,845	)
Tax provision related to hedges		(11,036	)				(9,036	)
Total other comprehensive income		18,589			18,589		15,219			15,219

Comprehensive income (loss)	$	25,852				$	(222,914	)
Accumulated other comprehensive income, end of period				$	22,848				$	39,298

(11) Earnings (Loss) Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if outstanding common stock awards and stock options were exercised at the end of the period.

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

	Three Months Ended March 31,
	2010		2009
	(In thousands)
Basic weighted average number of shares outstanding		51,219		50,920
Dilution effect of stock option and awards at the end of the period (1)		701		-
Diluted weighted average number of shares outstanding		51,920		50,920

Anti-dilutive stock awards and shares		111		1,441

___________________________________

(1)

Because the Company recognized a net loss for the quarter ended March 31, 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).

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(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 U.S., 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.

	Three Months Ended March 31,
	2010 (1)		2009(1)
Natural gas, oil and NGL Revenue	(In thousands)
California	$	21,397	$	19,180
Rockies		8,517		6,610
South Texas		28,682		23,182
Texas State Waters		2,204		4,262
Other Onshore		4,525		6,026
Gulf of Mexico		1,946		4,824
Total revenue, excluding gain on hedges	$	67,271	$	64,084

	March 31, 2010		December 31, 2009
Oil and Natural Gas Properties and Other Fixed Assets	(In thousands)
California	$	625,454	$	624,765
Rockies		207,987		202,502
South Texas		855,511		791,934
Texas State Waters		73,792		70,667
Other Onshore		193,445		186,912
Gulf of Mexico		153,688		153,653
Other		13,384		12,417
Total oil and natural gas properties and other fixed assets	$	2,123,261	$	2,042,850

__________________________________

(1)

Excludes the effects of hedging gains of $2.9 million and $15.4 million for the three months ended March 31, 2010 and 2009, respectively.

(13)	Subsequent Events

On April 13, 2010, the Company divested its Texas State Waters Sabine Lake asset which was a non-core property for $10.2 million. The proceeds will be recorded as an adjustment to the full cost pool with no gain or loss recognized.

On April 15, 2010, the Company issued $200.0 million in aggregate principal amount of 9.500% Senior Notes due in 2018. The Notes were issued under an indenture (the “Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the Indenture limit the Company’s ability to, among other things, incur additional indebtedness; pay dividends on the Company's capital stock or purchase, repurchase, redeem, defease or retire the Company’s capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The Indenture also contains customary events of default. The Company used the proceeds from the Notes offering to repay $80.0 million of variable rate borrowings under its Restated Term Loan, to repay $114.0 million under its Restated Revolver and to pay fees and expenses associated with the offering. Interest is payable on the Notes semi-annually on April 15 and October 15. As a result of the offering, the borrowing base under the Restated Revolver was reduced by $30.0 million to $345.0 million.

On April 15, 2010, the Company purchased the remaining 30% working interest and obtained operatorship in the Catarina Field for approximately $5.9 million in cash from St. Mary Land & Exploration Company. The purchase is effective as of January 1, 2010 and subject to any applicable purchase price adjustments.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding Rosetta 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.

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:

–	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;

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–

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;

–	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; and

–	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.

Overview

The following discussion addresses material changes in our results of operations for the three months ended March 31, 2010 compared to the three months ended March 31, 2009, and material changes in financial condition since December 31, 2009. It is presumed that readers have read or have access to 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 three months ended March 31, 2010 as compared to the same period for 2009:

Production on an equivalent basis decreased 22%;

Total revenue, including the effects of hedging, decreased $9.3 million or 12%;

Average realized gas prices including hedging increased $0.27 per Mcf, or 5%, to $5.81 per Mcf for the three months ended March 31, 2010 from $5.54 per Mcf for the three months ended March 31, 2009, average realized NGL prices increased $18.11 per Bbl, or 69%, to $44.49 per Bbl for the three months ended March 31, 2010 from $26.38 per Bbl for the three months ended March 31, 2009 and average realized oil prices increased $37.24 per Bbl, or 96%, to $76.23 per Bbl for the three months ended March 31, 2010 from $38.99 per Bbl for the three months ended March 31, 2009;

Diluted earnings per share increased $4.82 to diluted earnings per share of $0.14 for the three months ended March 31, 2010 from diluted loss per share of $4.68 for the three months ended March 31, 2009; and

36 gross (35 net) wells were drilled with a net success rate of 97.1% for the period ended March 31, 2010 compared to 21 gross (16 net) wells drilled with a net success rate of 88% for the same period in 2009.

During the past two years, Rosetta significantly transformed itself as a company. We believe that our 2009 performance offers tangible evidence that our strategy shift is yielding success. Of significance, we note the progress we made in establishing a presence in and testing two new shale plays, namely the Eagle Ford Shale in South Texas and the Alberta Basin Bakken Shale in Montana. Our progress in these plays, as well as in our legacy core area properties, is continuing in 2010.

In the Eagle Ford shale, we grew our acreage position and drilled four wells in the play during 2009. We completed two wells, both of which were discoveries, which set up the potential for a significant future development effort that is now underway in 2010. During the first quarter of 2010, we continued to add to our Eagle Ford shale acreage position, which grew to roughly 61,000 net acres by the end of the first quarter. We are focusing our 2010 drilling and operational efforts on the portion of our position that we believe is liquids-prone. Most notably, we are running a multi-rig program in the Gates Ranch area of the Eagle Ford shale where we now hold 29,500 net acres. During the first quarter of 2010, we drilled or spud nine Eagle Ford shale wells, all but one of which was in the Gates Ranch area. In general, we are extending lateral lengths by approximately 20 percent compared to the 2009 wells. Fracture stimulations in these longer laterals are averaging 12-15 stages. Results from our 2010 wells are generally exceeding our expectations and we expect to drill 25-30 Eagle Ford shale wells this year. In addition, we continue to look for opportunities to build our acreage position; however, we are only willing to do so at leasehold acquisition costs that we believe are attractive.

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In the less mature Alberta Basin Bakken Shale play, we drilled or spud three wells across a large portion of our exploratory acreage position during 2009. One of these wells was a horizontal well that was completed and tested. Two of these wells were vertical wells. We acquired core samples and ran extensive log suites in all three wells to obtain important geologic and reservoir data about the play. During the first quarter of 2010, we provided significant disclosure to the marketplace regarding our view of this play. Specifically, we noted that all three 2009 vintage wells encountered expected reservoir sections in the Banff, Bakken, Three Forks, and Nisku formations. We noted that these target reservoirs were oil-saturated in all three well penetrations and that all sections, except the Nisku, were over-pressured. We disclosed that our horizontal completion was only 20 percent effective based on production and tracer logs and that the flow test results we achieved were consistent with the limited stimulation effectiveness. We remain very constructive on the play and continue to acquire acreage in the play. At the end of the first quarter of 2010, our acreage position stood at about 280,000 net acres, up roughly 40,000 since the end of 2009. Our initial plans for 2010 are to conduct several low-cost fracture stimulated completions in the existing vertical well sections of our drilled wells. Following these tests, we expect to pursue the drilling of at least one well in the play during 2010.

The Eagle Ford shale and Alberta Basin Bakken shale plays have the potential to contribute significant performance improvement going forward. While the Eagle Ford shale is further along in development, we are careful to note that we are still in the early stages of de-risking and evaluating our current positions in these plays. Success in either or both of these plays would likely shift our product mix toward a higher percentage of oil, which would provide attractive diversification for us. We also believe the inventory potential from our legacy onshore assets provides a high-value base of production and reserves with relatively low capital intensity. Our legacy assets, in combination with our new shale plays, position us with a unique combination of assets for a company of our size.

Our business goals for 2010 remain predicated on executing an announced 2010 capital program of $280.0 million, subject to program results and timing. The majority of our planned drilling capital is targeted toward the Eagle Ford shale in the liquids-prone area within the Gates Ranch. The balance of our drilling capital is earmarked for a modest Lobo program, a DJ Basin program and the Alberta Basin Bakken shale program. Given our intention to continue building our leasehold positions in our shale plays, we also have some capital allocated to this effort.

We remain broadly committed to a fiscal strategy of internally funding our capital program and preserving liquidity. In approving our 2010 capital budget of $280.0 million, we indicated that the program could be funded from internally generated cash flows plus cash on hand at an average gas price of roughly $6 per Mcf and an average oil price of roughly $70 per Bbl. Given the significantly lower outlook for natural gas, we are closely monitoring cash flows to assess our ability to internally fund our announced program and preserve our liquidity. At this time, we believe our evolving liquids mix and stronger liquids pricing has compensated somewhat for lower natural gas prices and we expect to sell a modest level of non-core properties to generate additional liquidity. However, at this time, we recognize that a draw on our amended and restated revolving credit agreement (the "Restated Revolver") may be required in order to execute our planned program.

In the event that we encounter a situation in which we fall short of having sufficient internal funds to execute our planned capital program, fund incremental organic opportunities or pursue attractive acquisitions, we would consider additional draws on the unused capacity under our Restated Revolver or accessing capital markets. As of March 31, 2010, we had $135.0 million of available borrowing capacity under our revolving credit facility. 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 due 2018. We used the proceeds from the 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 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 in excess of $240.0 million as of May 5, 2010.

We recognize that the operating environment for our industry continues to be somewhat uncertain and our success in 2010 or beyond is not assured. Commodity prices, particularly for natural gas, continue to be impacted by weak demand and the lack of a supply response to lower prices in 2009. Access to some categories of oilfield services is starting to tighten. Attractive acquisition or leasing opportunities remain extremely competitive. Finally, given the early stage of the Eagle Ford shale and Alberta Basin Bakken shale plays, there is still significant risk to those programs. We attempt to manage these risks 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. Nevertheless, regardless of how effectively we manage these risks, they represent threats to our ability to achieve our growth goals and build 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, but we monitor partner situations routinely.

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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 March 31, 2010 was $70.1 million, which is a decrease of $9.3 million, or 12%, from the three months ended March 31, 2009. Natural gas sales, excluding the effects of hedging, decreased by $2.3 million for the three months ended March 31, 2010 as compared to the three months ended March 31, 2009. We experienced an $11.2 million increase in natural gas sales due to a 27% increase in natural gas prices, which was offset by $13.5 million in lower natural gas sales due to a 24% decrease in production volumes. Oil sales increased by $1.8 million of which $3.4 million was attributable to a 96% increase in the price of oil offset by a $1.6 million decrease in production. NGL sales increased by $3.7 million for the three months ended March 31, 2010 as compared to the three months ended March 31, 2009, of which $3.0 million was attributable to a 69% increase in the price of NGLs and $0.7 million was attributable to increased production. Approximately 80% of our revenue in the first quarter of 2010 was attributable to natural gas sales as compared to 89% in the first Quarter of 2009.

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

	Three Months Ended March 31,
	2010		2009		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)

Natural gas sales	$	55,807	$	70,559		(21	%)
Oil sales		6,983		5,218		34	%
NGL sales		7,358		3,664		101	%
Total revenues	$	70,148	$	79,441		(12	%)

Production:
Gas (Bcf)		9.6		12.7		(24	%)
Oil (MBbls)		91.6		133.8		(32	%)
NGLs (MBbls)		165.4		138.9		19	%
Total Equivalents (Bcfe)		11.2		14.4		(22	%)

$ per unit:
Avg. gas price per Mcf	$	5.81	$	5.54		5	%
Avg. gas price per Mcf excluding hedging		5.51		4.34		27	%
Avg. oil price per Bbl		76.23		38.99		96	%
Avg. NGL price per Bbl		44.49		26.38		69	%
Avg. revenue per Mcfe		6.26		5.52		13	%

Natural Gas. For the three months ended March 31, 2010, natural gas revenue, including the realized impact of derivative instruments, decreased by $14.8 million, or 21%, from the same period in 2009, to $55.8 million from $70.6 million. This decrease is primarily due the decrease in production as a result of the curtailed capital drilling program in 2009. The average gas price, including the effects of hedging, increased by $0.27 per Mcf from $5.54 per Mcf for the three months ended March 31, 2009 to $5.81 per Mcf for the same period in 2010. The effect of natural gas hedging activities on natural gas revenue for the three months ended March 31, 2010 was a gain of $2.9 million as compared to a gain of $15.4 million for the three months ended March 31, 2009.

Crude Oil. For the three months ended March 31, 2010, oil revenue increased by $1.8 million, or 34%, to $7.0 million compared to $5.2 million for the same period in 2009. This increase is attributable to an increase in the average realized price from $38.99 per Bbl for the three months ended March 31, 2009 to $76.23 per Bbl for the three months ended March 31, 2010. As price for oil increased, production for oil decreased in the first quarter of 2010 as compared to the same period for 2009 due to workover and wellbore issues in Texas State Waters properties.

NGLs. For the three months ended March 31, 2010, NGL revenue increased by $3.7 million, or 101%, to $7.4 million compared to $3.7 million for the same period in 2009. This increase is attributable to an increase in the average realized price from $26.38 per Bbl for the three months ended March 31, 2009 to $44.49 per Bbl for the three months ended March 31, 2010. Production for natural gas liquids also increased by 19%, or 26.5 MBbls, to 165.4 MBbls for the first quarter of 2010 from 138.9 MBbls due to new wells in South Texas that flowed to sales in the first quarter of 2010.

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Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended March 31,
	2010		2009		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	14,677	$	18,041		(19	%)
Production taxes		2,290		1,323		73	%
Depreciation, depletion and amortization		23,814		44,400		(46	%)
Impairment of oil and gas properties		-		379,462		(100	%)
General and administrative costs		11,807		9,373		26	%

$ per unit:
Avg. lease operating expense per Mcfe	$	1.31	$	1.25		5	%
Avg. production taxes per Mcfe		0.20		0.09		122	%
Avg. DD&A per Mcfe		2.13		3.08		(31	%)
Avg. production costs per Mcfe (1)		3.44		4.34		(21	%)
Avg. G&A per Mcfe		1.05		0.65		62	%

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(1)

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

Lease Operating Expense. Lease operating expense decreased $3.4 million to $14.7 million from $18.0 million for the three months ended March 31, 2010 as compared to the three months ended March 31, 2009. The overall decrease is due primarily to a $1.7 million decrease in ad valorem tax, and a $1.4 million decrease in workover expenses.

Production Taxes. Production taxes as a percentage of oil and natural gas sales were 3.3% for the three months ended March 31, 2010 as compared to 1.7% for the three months ended March 31, 2009. This increase in rate was primarily due to the expiration of certain high cost credits in the State of Texas.

Depreciation, Depletion and Amortization. DD&A expense decreased to $23.8 million for the three months ended March 31, 2010 as compared to $44.4 million for the three months ended March 31, 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 first quarter of 2010 was $2.13 per Mcfe while the rate for the first quarter of 2009 was $3.08 per Mcfe. The decrease in the rate was due to a lower full cost asset base in the first quarter of 2010 as compared to the same period in 2009 due to the impairment charges.

Impairment of Oil and Gas Properties. Based upon quarterly ceiling test computations using a 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 March 31, 2010. Based upon the quarterly ceiling test computations using hedge adjusted market prices at March 31, 2009, the net capitalized costs of oil and natural gas properties exceeded the cost center ceiling and a pre-tax, non-cash impairment expense of $379.5 million was recorded.

General and Administrative Costs. General and administrative costs increased by $2.4 million for the three months ended March 31, 2010 as compared to the three months ended March 31, 2009. This increase is primarily due to the increase in stock compensation expense of $1.6 million associated with the performance stock units.

Total Other Expense

Total other expense includes interest expense, interest income and other income/expense, net, which increased $2.2 million for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. The increase in other expense was due to an increase in interest expense. Long-term debt outstanding as of March 31, 2010 was $8.9 million higher as compared to March 31, 2009. The weighted average interest rate for the first quarter of 2010 was 6.22% compared to 2.71% 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.

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Provision for Income Taxes

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with 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 March 31, 2010, we have a deferred tax asset of approximately $160.9 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.

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 March 31, 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 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. As of May 5, 2010, we had $101 million outstanding, which is due and payable on July 1, 2012, with $244 million available for borrowing under the Restated Revolver.

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 March 31, 2010. On April 15, 2010, in connection with our issuance of $200.0 million of 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 due 2018. The 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 Notes offering to repay $80.0 million of variable rate borrowings under our Restated Term Loan, to repay $114.0 million under its Restated Revolver and to pay for fees and expenses associated with the offering. Interest is payable on the Notes semi-annually on April 15 and October 15.

Cash Flows

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

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash flows provided by operating activities	$	36,880		$	39,542
Cash flows used in investing activities		(73,570	)		(53,878	)
Cash flows provided by financing activities		25,341			4,452
Net decrease in cash and cash equivalents	$	(11,349	)	$	(9,884	)

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 decreased by $2.7 million for the three months ended March 31, 2010 as compared to the same period for 2009. The decrease primarily resulted from a decrease in production of 22% as of March 31, 2010 compared to the same period for 2009. In addition, at March 31, 2010, we had a working capital surplus of $39.8 million. This surplus for the first quarter of 2010 was primarily attributable to the cash and cash equivalents balance and the fair value of derivative instruments.

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

Cash flows used in investing activities increased by $19.7 million for the three months ended March 31, 2010 as compared to the same period for 2009. During the three months ended March 31, 2010, we participated in the drilling of 36 gross wells as compared to the drilling of 21 gross wells during the same period in 2009.

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

Cash flows provided by financing activities increased by $20.9 million for the three months ended March 31, 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.

Capital Expenditures

Our capital expenditures for the three months ended March 31, 2010 increased by $45.9 million to $80.4 million, from $34.5 million compared to the same period in 2009. During the three months ended March 31, 2010, we participated in the drilling of 36 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 fund planned capital expenditures for 2010, which are projected to be $280.0 million. We have the discretion to adjust capital spending plans throughout the remainder of the year in response to market conditions and the availability of proceeds from possible divestitures. In adition, we may make a draw on our Restated Revolver if required.

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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 22% of our expected natural gas production 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 production 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 bear interest at a LIBOR-based rate; provided however, that $20.0 million of our Restated Term Loan bears interest at a fixed rate of 13.75%. This 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. After April 15, 2010, there is no ongoing interest rate risk under our Restated Term Loan.

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

	Three Months Ended March 31,
Natural Gas	2010			2009
Quantity settled (MMBtu)		2,250,000			5,142,690
Increase in natural gas sales revenue (In thousands)	$	2,877		$	15,337
Interest Rate Swaps
(Increase) in interest expenses (In thousands)	$	(252	)	$	(512	)

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 March 31, 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 March 31, 2010, we had no deposits for collateral.

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.

Our anticipated capital spending for 2010 is unchanged at $280.0 million. We are closely monitoring cash flows to assess our ability to internally fund our announced program and preserve our liquidity. For the three months ended March 31, 2010, our capital expenditures were $80.4 million, including capitalized internal costs directly identified with acquisition, exploration and development activities of $1.7 million, capitalized interest of $1.0 million and corporate and other capital costs of $1.0 million. We also have the discretion to use our available borrowing base and proceeds from divestitures to fund capital expenditures, including acquisitions.

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”). In the Senate, the Boxer-Kerry climate bill has been reported out of the Senate Environment and Public Works Committee. 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. Finally, in September 2009, the EPA proposed a new regulation, subject to public comment and not yet effective, which would impose additional permitting requirements on certain stationary sources. 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 twelve-month average price using first day of the month prices, adjusted for hedges, of gas and oil at March 31, 2010, which were based on a Henry Hub gas price of $3.98 per MMBtu and a West Texas Intermediate oil price of $66.13 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 March 31, 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 production through 2012. As of March 31, 2010, 18% and 20% of our expected natural gas production was hedged using swaps and costless collars, respectively, with settlement in 2010, 14% and 32% of our expected natural gas production was hedged using swaps and costless collars, respectively, with settlement in 2011, and 12% of our expected natural gas production was hedged using costless collars, with settlement in 2012 based on anticipated future gas production. The swaps to settle in 2010 have an average price of $6.98 per MMBtu and the collars have floor and ceiling prices of $5.75 per MMBtu and $7.15 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 84% 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 March 31, 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 March 31, 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 $0.2 million at March 31, 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 March 31, 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 March 31, 2010, we had open natural gas derivative hedges in an asset position with a fair value of $37.0 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $14.6 million, while a 10 percent decrease in natural gas prices would increase the fair value by approximately $15.0 million. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas”. Additionally, at March 31, 2010, we had open interest rate swap hedges in a liability position of $0.6 million. A 10 percent increase in interest rates would increase the fair value by approximately $0.03 million, while a 10 percent decrease in interest rates would decrease the fair value by approximately $0.03 million. These fair value changes assume volatility based on prevailing market parameters at March 31, 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 $0.2 million at March 31, 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 March 31, 2010. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 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 quarter ended March 31, 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 factor below, there have been no material changes in our risk factors from those previously disclosed in Item 1A. of our 2009 Annual Report.

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.

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 March 31, 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
January 1 - January 31		35,825	$	20.19		-		-
February 1 - February 28		3,622		20.94		-		-
March 1 - March 31		20,769		21.69		-		-
Total		60,216	$	20.75		-		-

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(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.

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Item 6. Exhibits

Exhibit Number		Description
3.1		Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the 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 Assocaition, 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 Reosurces 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.

____________________________________

*	Filed herewith

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SIGNATURES

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

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

	(Duly Authorized Officer and Principal Financial Officer)

Date: May 7, 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 Assocaition, 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 Reosurces 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.

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*	Filed herewith