Edgar Filing: Rosetta Resources Inc.

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended September 30, 2009

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

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

Large accelerated filer x	Accelerated filer o

Non-Accelerated filer o	Smaller Reporting Company o
(Do not check if smaller reporting company)

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

The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of November 4, 2009 was 52,366,529.

Table of Contents

Part I –
	Financial Information
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	27
	Item 4. Controls and Procedures	28
Part II –
	Other Information	29
	Item 1. Legal Proceedings	29
	Item 1A. Risk Factors	29
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	29
	Item 3. Defaults upon Senior Securities	29
	Item 4. Submission of Matters to a Vote of Security Holders	29
	Item 5. Other Information	29
	Item 6. Exhibits	30
Signatures		31

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except share amounts)

	September 30, 2009			December 31, 2008
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	65,698		$	42,855
Restricted cash		-			1,421
Accounts receivable		18,946			41,885
Derivative instruments		20,305			34,742
Prepaid expenses		3,816			5,046
Other current assets		5,282			4,071
Total current assets		114,047			130,020
Oil and natural gas properties, full cost method, of which $24.8 million at September 30, 2009 and $50.3 million at December 31, 2008 were excluded from amortization		1,983,514			1,900,672
Other fixed assets		11,915			9,439
		1,995,429			1,910,111
Accumulated depreciation, depletion, and amortization, including impairment		(1,427,711	)		(935,851	)
Total property and equipment, net		567,718			974,260

Deferred loan fees		5,401			1,168
Deferred tax asset		175,964			42,652
Other assets		2,138			6,278
Total other assets		183,503			50,098
Total assets	$	865,268		$	1,154,378

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	2,046		$	2,268
Accrued liabilities		27,710			48,824
Royalties payable		12,979			17,388
Derivative instruments		258			985
Prepayment on gas sales		7,203			19,382
Deferred income taxes		7,467			12,575
Total current liabilities		57,663			101,422
Long-term liabilities:
Derivative instruments		1,479			-
Long-term debt		288,628			300,000
Other long-term liabilities		27,769			26,584
Total liabilities		375,539			428,006

Commitments and contingencies (Note 9)		-			-

Stockholders' equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2009 or 2008		-			-
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 51,187,734 shares and 51,031,481 shares at September 30, 2009 and December 31, 2008, respectively		51			51
Additional paid-in capital		778,427			773,676
Treasury stock, at cost; 186,861 and 155,790 shares at September 30, 2009 and December 31, 2008, respectively		(3,290	)		(2,672	)
Accumulated other comprehensive income		11,671			24,079
Accumulated deficit		(297,130	)		(68,762	)
Total stockholders' equity		489,729			726,372
Total liabilities and stockholders' equity	$	865,268		$	1,154,378

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

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Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Revenues:
Natural gas sales	$	60,049		$	114,308		$	201,360		$	362,894
Oil sales		4,435			15,728			16,116			49,941
Total revenues		64,484			130,036			217,476			412,835
Operating Costs and Expenses:
Lease operating expense		13,312			12,857			47,921			40,445
Depreciation, depletion, and amortization		23,029			46,951			95,928			150,103
Impairment of oil and gas properties		-			205,659			379,462			205,659
Treating and transportation		1,805			1,780			4,608			4,624
Marketing fees		27			840			585			2,602
Production taxes		1,109			2,336			4,183			11,528
General and administrative costs		10,414			15,419			32,358			41,042
Total operating costs and expenses		49,696			285,842			565,045			456,003
Operating income (loss)		14,788			(155,806	)		(347,569	)		(43,168	)

Other (income) expense
Interest expense, net of interest capitalized		5,239			3,186			13,880			11,209
Interest income		(16	)		(586	)		(93	)		(1,141	)
Other (income) expense, net		(11	)		(40	)		149			(170	)
Total other expense		5,212			2,560			13,936			9,898

Income (loss) before provision for income taxes		9,576			(158,366	)		(361,505	)		(53,066	)
Provision for income taxes		3,845			(58,991	)		(133,138	)		(20,495	)
Net income (loss)	$	5,731		$	(99,375	)	$	(228,367	)	$	(32,571	)

Earnings (loss) per share:
Basic	$	0.11		$	(1.96	)	$	(4.48	)	$	(0.64	)
Diluted	$	0.11		$	(1.96	)	$	(4.48	)	$	(0.64	)

Weighted average shares outstanding:
Basic		50,994			50,813			50,961			50,636
Diluted		51,291			50,813			50,961			50,636

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

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Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
Cash flows from operating activities
Net income (loss)	$	(228,367	)	$	(32,571	)
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization		95,928			150,103
Impairment of oil and gas properties		379,462			205,659
Deferred income taxes		(131,056	)		(24,939	)
Amortization of deferred loan fees recorded as interest expense		1,621			885
Amortization of original issue discount recorded as interest expense		228			-
Stock compensation expense		4,951			4,975
Other non-cash items		-			(418	)
Change in operating assets and liabilities:
Accounts receivable		22,939			1,544
Prepaid expenses		1,230			4,863
Other current assets		(1,211	)		181
Other assets		(444	)		192
Accounts payable		(222	)		3,046
Accrued liabilities		(5,546	)		4,516
Royalties payable		(16,589	)		8,265
Net cash provided by operating activities		122,924			326,301
Cash flows from investing activities
Acquisition of oil and gas properties		(3,721	)		(29,570	)
Purchases of oil and gas assets		(99,191	)		(167,629	)
Disposals of oil and gas properties and assets		19,483			27
Decrease in restricted cash		1,421			-
Net cash used in investing activities		(82,008	)		(197,172	)
Cash flows from financing activities
Borrowings on revolving credit facility		28,400			-
Payments on revolving credit facility		(40,000	)		-
Deferred loan fees		(5,855	)		-
Proceeds from stock options exercised		-			3,669
Purchases of treasury stock		(618	)		(831	)
Net cash (used in) provided by financing activities		(18,073	)		2,838

Net increase in cash		22,843			131,967
Cash and cash equivalents, beginning of period		42,855			3,216
Cash and cash equivalents, end of period	$	65,698		$	135,183

Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	9,489		$	23,316

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

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Rosetta Resources Inc.

Notes to Consolidated Financial Statements (unaudited)

(1) Organization and Operations of the Company

Nature of Operations. Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) is an independent oil and gas company that is engaged in oil and natural gas exploration, development, production and acquisition activities in the United States. The Company’s main operations are primarily concentrated in the Sacramento Basin of California, the Rockies, the Lobo and Perdido Trends in South Texas, the State Waters of Texas and the Gulf of Mexico.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments necessary for a fair presentation of the financial statements have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America. These financial statements and notes should be read in conjunction with the Company’s audited Consolidated Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 ("2008 Annual Report"). In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through November 6, 2009, the date the financial statements were issued, and have concluded that there were no subsequent events.

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

(2) Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2008 Annual Report.

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

Recent Accounting Developments

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

Business Combinations. In December 2007, the Financial Accounting Standards Board (“FASB”) revised the authoritative guidance for business combinations, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. The revised guidance broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. The revised guidance also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases. This could cause us to expense transaction costs for future oil and gas property purchases that we have historically capitalized. Additionally, this guidance expands the required disclosures to improve the financial statement users’ abilities to evaluate the nature and financial effects of business combinations. This guidance is effective for business combinations for which the acquisition date is on or after January 1, 2009. The adoption of the revised guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Non-controlling Interests in Consolidated Financial Statements. In December 2007, the FASB issued authoritative guidance which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. This guidance is effective for fiscal years beginning after December 15, 2008. The adoption of this guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB issued authoritative guidance related to disclosures about derivative instruments and hedging activities, which is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures. This guidance is effective for fiscal years beginning after November 15, 2008. The Company adopted the disclosure requirements beginning January 1, 2009. See Note 4 - Commodity Hedging Contracts and Other Derivatives.

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Fair Value Measurements. In February 2008, the FASB issued authoritative guidance which delayed the effective date of fair value accounting for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Beginning January 1, 2009, we implemented the guidance for nonfinancial assets and liabilities. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows. In October 2008, the FASB issued guidance on determining the fair value of a financial asset when the market for that asset is not active. This guidance clarifies the application of fair value accounting in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. This guidance was effective upon issuance, including prior periods for which financial statements have not been issued. We applied this guidance to financial assets measured at fair value on a recurring basis at September 30, 2009. See Note 5 - Fair Value Measurements. The adoption of this guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In April 2009, the FASB issued authoritative guidance to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. This guidance provides guidelines for making fair value measurements for assets and liabilities for which the volume and level of activity for the asset or liability have significantly decreased or for transactions that are not orderly more consistent with the principles presented in earlier guidance, enhances consistency in financial reporting by increasing the frequency of fair value disclosures, and provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities for other-than-temporary impairments. This guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We applied 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.

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 our consolidated financial position, results of operations or cash flows. See Note 1 – Organization and Operations of the Company.

FASB Codification. In July 2009, the FASB issued guidance making the FASB Accounting Standards Codification the single source of authoritative nongovernmental U.S. GAAP. The Codification is not intended to change GAAP, however, it will represent a significant change in researching issues and referencing U.S. GAAP in financial statements and accounting policies. This guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We applied this guidance for the period ended September 30, 2009.

Oil and Gas Reporting Requirements. In December 2008, the Securities and Exchange Commission (“SEC”) released Release No. 33-8995, “Modernization of Oil and Gas Reporting” (the “Release”). The disclosure requirements under this Release will require reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed, but not required, to disclose probable and possible reserves in SEC filings. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The new disclosure requirements become effective for the Company beginning with our annual report on Form 10-K for the year ending December 31, 2009. In September 2009, the FASB issued its proposed guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. In October 2009, the SEC issued Staff Accounting Bulletin (“SAB”) No. 113 to bring existing SEC guidance into conformity with the Release. The principle revisions of the guidance include changing the price used in determining quantities of oil and gas reserves, as noted above; eliminating the option to use post-quarter-end prices to evaluate write-offs of excess capitalized costs under the full cost method of accounting; removing the exclusion of unconventional methods used in extracting oil and gas from oil sands or shale as an oil and gas producing activity; and removing certain questions and interpretative guidance which are no longer necessary. We are currently evaluating the impact of this guidance on our financial statements and oil and gas accounting disclosures.

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(3) Property, Plant and Equipment

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

	September 30, 2009			December 31, 2008
	(In thousands)
Proved properties	$	1,920,891		$	1,813,527
Unproved/unevaluated properties		24,793			50,252
Gas gathering systems and compressor stations		37,830			36,893
Total oil and natural gas properties		1,983,514			1,900,672
Other fixed assets		11,915			9,439
Total property and equipment, gross		1,995,429			1,910,111
Less: Accumulated depreciation, depletion, and amortization		(1,427,711	)		(935,851	)
Total property and equipment, net	$	567,718		$	974,260

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.3 million and $1.5 million of internal costs for the three months ended September 30, 2009 and 2008, respectively, and $3.1 million and $4.3 million for the nine months ended September 30, 2009 and 2008, respectively.

Included in the Company’s oil and gas properties are asset retirement costs of $22.1 million and $23.2 million as of September 30, 2009 and December 31, 2008, respectively.

Oil and gas properties include costs of $24.8 million and $50.3 million at September 30, 2009 and December 31, 2008, respectively, that were excluded from capitalized costs being amortized. These amounts primarily represent unproved properties and unevaluated exploration projects in which the Company owns a direct interest.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center. The Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at September 30, 2009, which were based on a Henry Hub price of $3.30 per MMBtu and a West Texas Intermediate oil price of $67.00 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at September 30, 2009 increased the calculated ceiling value by approximately $50.7 million (pre-tax). The use of these prices would have resulted in a pre-tax write-down of $18.8 million at September 30, 2009. As allowed under the full cost accounting rules, the Company re-evaluated its ceiling test on October 29, 2009 using the market price for Henry Hub of $4.59 per MMBtu and West Texas Intermediate of $76.25 per Bbl (adjusted for basis and quality differentials). At these prices, cash flow hedges of natural gas production in place increased the calculated ceiling value by approximately $29.3 million (pre-tax). 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 for the quarter ended September 30, 2009. It is possible that another write-down of the Company's oil and gas properties could occur in the future should oil and natural gas prices decline, the Company experiences significant downward adjustments to the estimated proved reserves, and/or the Company's commodity hedges settle and are not replaced.

The Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at March 31 and June 30, 2009, which were based on a Henry Hub price of $3.63 per MMBtu and $3.89 per MMBtu, respectively, and a West Texas Intermediate oil price of $46.00 per Bbl and $66.25 per Bbl (adjusted for basis and quality differentials), respectively, compared to prices of $5.71 per MMBtu and $41.00 per Bbl at December 31, 2008. Cash flow hedges of natural gas production in place at March 31 and June 30, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax) and $55.3 million (pre-tax), respectively. Based upon these analyses, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009 and the Company did not record a write-down at June 30, 2009.

The Company generated $19.5 million of proceeds from divestitures of oil and gas properties and assets in non-core operating areas during the nine months ended September 30, 2009. Of these divestitures, $18.0 million were recorded as credits to the full cost pool with no gain or loss recognized, $0.8 million was recorded as a reimbursement of costs previously paid for gathering facilities associated with divested properties, and $0.7 million related to the sale of compressors that were not included in the pool for which an immaterial loss on sale was recorded.

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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 September 30, 2009:

Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu		Total of Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu		Average Ceiling Prices per MMBtu		Natural Gas Production Hedged (1)			Fair Market Value Asset/(Liability) (In thousands)
2009	Swap	Cash flow		52,141		4,796,972	$	7.64	$	-		49	%	$	13,338
2009	Costless Collar	Cash flow		5,000		460,000		8.00		10.05		5	%		1,315
2010	Swap	Cash flow		12,521		4,570,000		7.79		-		11	%		7,352
2010	Costless Collar	Cash flow		5,041		1,840,000		5.75		7.55		4	%		(299	)
2011	Swap	Cash flow		5,000		1,825,000		5.72				5	%		(976	)
2011	Costless Collar	Cash flow		10,000		3,650,000		5.75		7.55		10	%		(1,488	)
						17,141,972								$	19,242

(1)

Estimated based on anticipated future gas production.

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

Settlement Period	Derivative Instrument	Hedge Strategy		Average Fixed Rate				Fair Market Value Asset/(Liability) (In thousands)
October 1, 2009 - December 31, 2010	Swap	Cash Flow			1.24	%		$	(642	)

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 September 30, 2009, the Company made no deposits for collateral.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
Natural Gas	2009		2008			2009		2008
Quantity settled (MMBtu)		5,256,972		6,706,092			15,599,493		19,498,524
Increase (decrease) in natural gas sales revenue (In thousands)	$	22,918	$	(12,125	)	$	60,077	$	(29,420	)
Interest Rate Swaps
Increase (decrease) in interest expense (In thousands)	$	-	$	(372	)	$	1,034	$	(832	)

As of September 30, 2009, the Company expects to reclassify gains of $20.0 million to earnings from the balance in accumulated other comprehensive income on the Consolidated Balance Sheet during the next twelve months.

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

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.

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Additional Disclosures about Derivative Instruments and Hedging Activities

Cash Flow Hedges

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

As of September 30, 2009, the Company had outstanding natural gas commodity forward contracts with a notional volume of 17,141,972 MMBtus that were entered into to hedge forecasted natural gas sales.

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

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

	Fair Values of Derivative Instruments Derivative Assets (Liabilities)

	September 30, 2009
	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments		(in thousands)

Interest rate swap	Derivative Instruments - current assets	$	(429	)
Interest rate swap	Derivative Instruments - current liabilities		(258	)
Interest rate swap	Derivative Instruments - non-current liabilities		10
Interest rate swap	Other assets - non-current assets		32
Commodity contracts	Derivative Instruments - current assets		20,734
Commodity contracts	Derivative Instruments - non-current liabilities		(1,489	)

Total derivatives designated as hedging instruments		$	18,600

Total derivatives not designated as hedging instruments		$	-


Total derivatives		$	18,600

Derivatives in Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)			Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)			Location of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
Derivatives in Cash Flow Hedging Relationships	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009				Three Months Ended September 30, 2009		Nine Months Ended September 30, 2009				Three Months Ended September 30, 2009		Nine Months Ended September 30, 2009

Interest rate swap	$	(3,709	)	$	40,949		Interest expense, net of interest capitalized	$	-	$	(512	)	Interest expense, net of interest capitalized	$	-	$	(522	)
Commodity contracts		(550	)		(1,679	)	Natural gas sales		22,918		60,077		Natural gas sales		-		-

Total	$	(4,259	)	$	39,270			$	22,918	$	59,565			$	-	$	(522	)

(1)

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

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

(5) Fair Value Measurements

The Company adopted 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 September 30, 2009, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at September 30, 2009.

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 September 30, 2009. The Company identified the money market funds as Level 3 instruments due to the fact that quoted prices for the underlying investments cannot be obtained and there is not an active market for the underlying investments. The Company utilizes counterparty and third party broker quotes to determine the valuation of its derivative instruments. Fair values derived from counterparties and brokers are further verified using the closing price as of September 30, 2009 for the relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009. 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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	At fair value as of September 30, 2009 (In thousands)
	Level 1		Level 2		Level 3			Total
Assets (Liabilities):
Money market funds		-		-		2,035			2,035
Commodity derivative contracts		-		-		19,242			19,242
Interest rate swap contracts		-		-		(642	)		(642	)
Total		-		-		20,635			20,635

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 $0.03 million at September 30, 2009.

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

	Derivatives Asset (Liability) (In thousands)			Money Market Funds Asset (Liability) (In thousands)			Total (In thousands)
Balance as of January 1, 2009	$	38,372		$	5,025		$	43,397
Total (gains) losses (realized or unrealized)
included in earnings		-			10			10
included in other comprehensive income		39,270			-			39,270
Purchases, issuances and settlements		(59,042	)		(3,000	)		(62,042	)
Transfers in and out of level 3		-			-			-
Balance as of September 30, 2009	$	18,600		$	2,035		$	20,635

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 September 30, 2009	$	-		$	-		$	-

At September 30, 2009, 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 September 30, 2009 is $288.6 million. The Company calculated the fair value of its long-term debt as of September 30, 2009, 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 $301.7 million at September 30, 2009.

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(6) Asset Retirement Obligation

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

	Nine Months Ended September 30, 2009
	(In thousands)
ARO as of December 31, 2008	$	27,944
Revision of previous estimates		(1,750	)
Liabilities incurred during period		1,797
Liabilities settled/divested during period		(1,192	)
Accretion expense		1,770
ARO as of September 30, 2009	$	28,569

Of the total ARO, $1.0 million is included in accrued liabilities and $27.6 million is included in Other long-term liabilities on the Consolidated Balance Sheet at September 30, 2009.

(7) Long-Term Debt

On April 9, 2009, the Company entered into an Amended and Restated Senior Revolving Credit Agreement with BNP Paribas, as Administrative Agent, and the other lenders identified therein (“Restated Revolver”) providing a senior secured revolving line of credit in the amount of up to $600.0 million, replacing the prior revolving credit agreement, and extending its term until July 1, 2012. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements. The borrowing base under the Restated Revolver was set at $375.0 million as of September 30, 2009. The semi-annual borrowing base review was completed during October 2009, and the borrowing base under the Restated Revolver was reduced from $375.0 million to $350.0 million. Amounts outstanding under the Restated Revolver bear interest, as amended, at specified margins over London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of the Company’s domestic subsidiaries, and a pledge of 100% of the membership interests of domestic subsidiaries. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. On October 22, 2009, the Company entered into the First Amendment to the Restated Revolver that deletes the “Reference Bank Cost of Funds Rate” option in the definition of Alternate Base Rate, allows the Company to make investments in US government securities, which mature in 15 months rather than one year, provides for certain other modifications to permitted investments, and provides for the release of the Lenders’ lien on a certain deposit account. The Company paid a facility fee on the total commitment of $4.6 million. As of November 6, 2009, the Company has $190.0 million outstanding with $160.0 million available for borrowing under the revolving line of credit.

On April 9, 2009, the Company also entered into an Amended and Restated Second Lien Term Loan Agreement with BNP Paribas, as Administrative Agent, and other lenders identified therein (“Restated Term Loan”) replacing the prior Term Loan extending its term until October 2, 2012. Borrowings under the Restated Term Loan were initially set at $75.0 million and bear interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%. The Restated Term Loan had an option to increase fixed and floating rate borrowings by up to $25.0 million to $100.0 million prior to May 9, 2009. The Company exercised this option on April 21, 2009 and the increased borrowings consisted of $5.0 million of floating rate borrowings and $20.0 million of fixed rate borrowings at 13.75%. The loan is collateralized by second priority liens on substantially all of the Company’s assets. The Company is subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. On October 22, 2009, the Company also entered into the First Amendment to the Restated Term Loan that deletes the “Reference Bank Cost of Funds Rate” option in the definition of Alternate Base Rate, allows the Company to make investments in US government securities, which mature in 15 months rather than one year, provides for certain other modifications to permitted investments, and provides for the release of the Lenders’ lien on a certain deposit account. The Company paid an original issue discount of $1.6 million and a facility fee of $0.9 million on the total commitment. As of September 30, 2009, the Company had $80.0 million of variable rate borrowings and $20.0 million of fixed rate borrowings outstanding under the Restated Term Loan. There were no additional borrowings under the Restated Term Loan subsequent to September 30, 2009 through the date of this Quarterly Report on Form 10-Q.

As of September 30, 2009, the Company had total outstanding borrowings of $288.6 million. At September 30, 2009, the Company’s weighted average borrowing rate was 5.02%. Net borrowing availability under the Revolver was $185.0 million at September 30, 2009. The Company was in compliance with all covenants at September 30, 2009.

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

(8) Income Taxes

As of September 30, 2009, the Company had no unrecognized tax benefits. The effective tax rate for the three and nine months ended September 30, 2009 was 40.2% and 36.8%, respectively. The effective tax rate for the three and nine months ended September 30, 2008 was 37.2% and 38.6%, respectively. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes, tax credits, a shortfall related to stock-based compensation, and other permanent differences. The income tax benefit for the nine months ended September 30, 2009 includes a $1.0 million downward adjustment recorded in the three months ended March 31, 2009 related to 2008 state taxes.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with 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 September 30, 2009, the Company has a deferred tax asset of approximately $176.0 million resulting primarily from the difference between the book basis and tax basis of its oil and natural gas properties. The Company believes that it is more likely than not that this deferred tax asset will be realized through future taxable income generated by the production of its oil and natural gas properties.

(9) Commitments and Contingencies

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

(10) Comprehensive Income (Loss)

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

	Three Months Ended September 30,												Nine Months Ended September 30,
	2009						2008						2009						2008
	(In thousands)
Accumulated other comprehensive (loss) income beginning of period				$	28,725					$	(96,756	)				$	24,079					$	(7,225	)
Net income (loss)		5,731						(99,375	)					(228,367	)					(32,571	)

Change in fair value of derivative hedging instruments		(4,259	)					142,431						39,270						(18,002	)
Hedge settlements reclassed to income		(22,918	)					12,497						(59,043	)					30,251
Tax provision related to hedges		10,123						(57,711	)					7,365						(4,563	)
Total other comprehensive (loss) income		(17,054	)		(17,054	)		97,217			97,217			(12,408	)		(12,408	)		7,686			7,686

Comprehensive loss		(11,323	)					(2,158	)					(240,775	)					(24,885	)
Accumulated other comprehensive income				$	11,671					$	461					$	11,671					$	461

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(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 September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(In thousands)
Basic weighted average number of shares outstanding		50,994		50,813		50,961		50,636
Dilution effect of stock option and awards at the end of the period		297		-		-		-
Diluted weighted average number of shares outstanding		51,291		50,813		50,961		50,636

Anti-dilutive stock awards and shares		1,450		611		1,963		617

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

(12) Stock-Based Compensation

Performance Share Units

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

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

The Company granted 350,698 PSUs on March 3, 2009. No additional PSUs have been granted nor have any vested or forfeited and the fair value per unit at September 30, 2009 was $14.77 for awards with performance conditions and $8.44 for awards with market conditions. For the quarter and nine months ended September 30, 2009, the Company recognized $0.2 million of compensation expense associated with the PSUs.

(13) Geographic Area Information

The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with authoritative guidance for disclosures about segments.

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

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Oil and Natural Gas Revenue

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
	(In thousands)
California	$	12,393	$	38,310		$	45,154	$	118,898
Rockies		4,498		6,993			15,900		23,400
South Texas		17,706		59,941			63,888		174,697
Texas State Waters		1,413		13,555			8,819		44,292
Other Onshore		3,662		12,039			13,869		37,442
Gulf of Mexico		1,892		11,323			9,769		43,527
Gain (loss) on hedges		22,920		(12,125	)		60,077		(29,421	)
Total revenue	$	64,484	$	130,036		$	217,476	$	412,835

Oil and Natural Gas Properties

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

	September 30, 2009		December 31, 2008
	(In thousands)
California	$	623,034	$	619,593
Rockies		184,996		175,294
South Texas		772,822		712,464
Texas State Waters		66,952		65,085
Other Onshore		182,154		171,855
Gulf of Mexico		153,556		156,381
Other		11,915		9,439
Total property and equipment	$	1,995,429	$	1,910,111

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking information regarding Rosetta that is intended to be covered by the “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology.

The forward-looking statements contained in this report are largely based on our expectations for the future, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. Risk Factors in Part II. of this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances, or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

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

–	conditions in the energy and economic markets;

–	our ability to access the capital markets on favorable terms or at all;

–	our ability to obtain credit and/or capital in desired amounts and/or on favorable terms;

–	the ability and willingness of our current or potential counterparties or vendors to enter into transactions with us and/or to fulfill their obligations to us;

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

–	the occurrence of property acquisitions or divestitures;

–	reserve levels;

–	inflation;

–	the supply and demand for natural gas and oil;

–	the price of natural gas and oil;

–	competition in the natural gas and oil industry;

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

–	the availability and cost of processing and transportation;

–	changes or advances in technology;

–	potential reserve revisions;

–	future processing volumes and pipeline throughput;

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

–	drilling and exploration risks;

–

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

–

any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.

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Overview

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

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

Production on an equivalent basis decreased 5%;

Total revenue, including the effects of hedging, decreased $195.4 million or 47%;

Average realized gas prices including hedging decreased $4.05 per Mcf, or 43%, to $5.46 per Mcf at September 30, 2009 from $9.51 per Mcf at September 30, 2008 and average realized oil prices decreased $63.93 per Bbl, or 56%, to $50.55 per Bbl at September 30, 2009 from $114.48 per Bbl at September 30, 2008;

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

Net loss increased $195.8 million to a net loss of $228.4 million; net income excluding impairments would have been $9.7 million;

Diluted loss per share increased $3.84 to diluted loss per share of $4.48; diluted earnings per share excluding impairment would have been $0.19 per share; and

36 gross (29 net) wells were drilled with a net success rate of 83% compared to 112 gross (95 net) wells drilled with a net success rate of 86% for the comparable period in 2008.

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

Under commodity price scenarios of at least $6.00 per Mcf and $70.00 per Bbl, we believe we can successfully implement our strategy shift because of some inherent strengths. Of note, we believe our core existing onshore assets will yield significant inventory upside when analyzed through an unconventional resource approach. Our studies have identified meaningful levels of new inventory for the Company from these assets and we believe that there is additional potential. Furthermore, although we are in the early stages of evaluating our positions in the Eagle Ford play in South Texas and Bakken play in the Alberta Basin of Montana, we believe we have some unique exposure to inventory upside given the encouraging results we have experienced to date. We are further advantaged, in our view, by having an experienced workforce and management team with background in unconventional resource operations. Finally, we have a financial and capital allocation approach that we believe allows us to adapt to the unpredictable industry cycles and manage through the current economic downturn. These factors do not ensure our success in executing our strategy shift, but we believe they provide a competitive advantage towards executing our strategy shift over the longer term. Under an extended period of commodity prices below $5.00 per Mcfe, our ability to implement our business strategy would likely be constrained, particularly given our relatively low level of 2010 and 2011 hedges. Management continuously analyzes and evaluates possible actions that could be taken if a protracted low price environment persists with a focus on preserving an acceptable level of liquidity and cash flow to execute our programs.

The current plan for implementing our business strategy is to pursue, over time, both organic and inorganic opportunities that meet the Company’s criteria for funding, particularly inventory potential and attractive financial returns. Several studies began in 2008 to test organic concepts in areas where we currently have assets for the purpose of identifying possible upside and inventory. These studies are continuing in 2009. We also actively study domestic basins where we believe the Company can enter and/or expand and compete successfully. The Company’s entry into the Eagle Ford and Bakken plays are prime examples of the type of play entry that the Company intends to pursue.

While we have a preference for organic opportunities, we have also expanded our capability to evaluate and pursue large and small acquisition opportunities that make sense for the Company. We believe this balanced approach is needed for long-term success. Our ability to execute inorganic activities will depend on market conditions, including availability of acquisition opportunities, relative valuations, and access to funding sources that could include proceeds from non-core asset divestitures, as well as proceeds from capital market activities. Thus far in 2009, we have generated approximately $20.0 million of proceeds from non-core divestitures, and we continue to test the market for additional non-core divestitures. While we continuously evaluate our portfolio to identify possible divestiture candidates, we are not driven to sell assets unless values are compelling.

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We entered 2009 in a position to execute our business plan and affect our desired goals, subject to commodity prices and market factors, and these factors generally weakened during the year. The outlook for commodity prices continues to be uncertain driven primarily by sluggish demand for natural gas and commodity oversupply. Given this outlook, we continue to exercise prudence and caution with our capital spending in order to preserve liquidity and maximize the financial position of the Company. The priority for our 2009 organic spending remains to spend less than our internally generated cash flow plus cash on hand. We have exercised the discretion to adjust capital spending, either up or down, throughout the year in response to market conditions, the availability of proceeds from possible divestitures, access to attractive acquisitions, and follow-on to success in our organic programs. Our 2009 capital focus has been to drill a limited number of Lobo wells in South Texas, conduct recompletion programs in the Sacramento Basin, and test our two exploratory plays in the Eagle Ford and Bakken. We currently project 2009 organic capital spending to be approximately $125.0 million, up modestly from our prior guidance primarily reflecting additional drilling and leasing in the Eagle Ford and Bakken plays. We believe we are on track to achieve between 130 – 140 MMcfe/d of full-year 2009 production, excluding acquisitions and divestitures, and we also believe that our fourth quarter volumes will improve compared to third quarter.

Our capital program for 2010 has not yet been determined, but the planning exercise is underway. We have identified more projects for capital funding in 2010 than we are willing to fund at current prices. Our capital allocation for 2010 will likely be driven by the following considerations: relative project economics, uplift efficiency, reserve potential, maintaining leasehold, and a desire to accelerate activity in our new plays. We expect to provide 2010 capital and production guidance once our final budget is approved in December. However, we are comfortable indicating at this time that, given our liquidity position, we expect to fund a higher capital program in 2010 and to grow production and reserves next year and beyond. We expect that a significant portion of next year's capital will be directed toward funding our emerging play successes. The ultimate level of 2010 capital spending and growth will be determined by available cash flows from operating activities, access to liquidity, and proceeds from possible property divestitures. To the extent that capital expenditures or prudent acquisitions require cash flow in excess of available funds, we would consider drawing on our unused capacity under our existing revolving credit facility. In addition, we are positioned to raise additional funds in the capital markets as deemed appropriate. We currently do not have any stated plans to issue securities but would consider doing so under certain circumstances, notably to fund an attractive acquisition, accelerate follow-on development activities in our Eagle Ford and/or Bakken plays, or fund entry into new resource plays.

Our industry continues to operate in one of the most challenging business environments in recent history. The credit crisis, lower natural gas prices and a weak domestic and global economic outlook are all adversely impacting the business environment. We work continuously with our lenders to effectively stay abreast of market and creditor conditions to ensure prudent and timely decisions should market conditions deteriorate further. Additionally, during April 2009, we amended and restated our second lien term loan, which allowed us to increase our borrowings under the facility from $75.0 million to $100.0 million. As of November 6, 2009, the undrawn credit available to us was $160.0 million. We have not received any indication from our lenders that draws under the credit facility are restricted below current availability at this time, and we are proactively communicating with them on a routine basis. During October 2009, our borrowing base was set at $350.0 million, which is reduced from the $375.0 million set during April 2009. Despite this reduction, our liquidity position, including cash on hand, is generally unchanged at $225.0 million. The April 2009 amendments and restatements to our credit agreements also extended the maturities of our credit facilities to 2012. We believe these actions provide capacity and time for managing through the current downturn.

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

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

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

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Critical Accounting Policies and Estimates

In our 2008 Annual Report we identified our most critical accounting policies upon which our financial condition depends as those relating to oil and natural gas reserves, full cost method of accounting, derivative transactions and hedging activities, income taxes and stock-based compensation.

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

Our ceiling test was calculated using hedge adjusted market prices of gas and oil at September 30, 2009, which were based on a Henry Hub price of $3.30 per MMBtu and a West Texas Intermediate oil price of $67.00 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at September 30, 2009 increased the calculated ceiling value by approximately $50.7 million (pre-tax). The use of these prices would have resulted in a pre-tax write-down of $18.8 million at September 30, 2009. As allowed under the full cost accounting rules, we re-evaluated our ceiling test on October 29, 2009 using the market price for Henry Hub of $4.59 per MMBtu and West Texas Intermediate of $76.25 per Bbl (adjusted for basis and quality differentials). At these prices, cash flow hedges of natural gas production in place increased the calculated ceiling value by approximately $29.3 million (pre-tax). Utilizing these prices, the calculated ceiling amount exceeded our net capitalized cost of oil and gas properties. As a result, no write-down was recorded for the quarter ended September 30, 2009. Due to the volatility of commodity prices, should natural gas and oil prices decline in the future, we experience a significant downward adjustment to our estimated proved reserves, and/or our commodity hedges settle and are not replaced, it is possible that another write-down of our oil and gas properties could occur.

Our ceiling test was calculated using hedge adjusted market prices of gas and oil at March 31 and June 30, 2009, which were based on a Henry Hub price of $3.63 per MMBtu and $3.89 per MMBtu, respectively, and a West Texas Intermediate oil price of $46.00 per Bbl and $66.25 per Bbl (adjusted for basis and quality differentials), respectively, compared to prices of $5.71 per MMBtu and $41.00 per Bbl at December 31, 2008. Cash flow hedges of natural gas production in place at March 31 and June 30, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax) and $55.3 million (pre-tax), respectively. Based upon these analyses, we recorded a non-cash, pre-tax write-down of $379.5 million at March 31, 2009 and we did not record a non-cash, pre-tax write-down at June 30, 2009.

We have entered into financial fixed price swaps with prices ranging from $5.54 per MMBtu to $8.58 per MMBtu covering approximately 4.8 million MMBtu, or 49%, of our 2009 production, 4.6 million MMBtu, or 11%, of our 2010 production, and 1.8 million MMBtu, or 5%, of our 2011 production. We have also entered into costless collar transactions covering approximately 0.5 million MMBtu of our 2009 production with an average floor price of $8.00 per MMBtu and an average ceiling price of $10.05 per MMBtu and approximately 1.8 million MMBtu of our 2010 production and approximately 3.7 million MMBtu of our 2011 production with an average floor price of $5.75 per MMBtu and an average ceiling price of $7.55 per MMBtu. Approximately 82% 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 September 30, 2009, we made no deposits for collateral. Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of September 30, 2009. We evaluated non-performance risk using current credit default swap values and default probabilities for each counterparty and recorded a downward adjustment to the fair value of our derivative assets in the amount of $0.03 million at September 30, 2009.

We utilize counterparty and third party broker quotes to determine the valuation of our derivative instruments. Fair values derived from counterparties and brokers are further verified using the settled price as of September 30, 2009 for NYMEX futures contracts and exchange traded contracts for each derivative settlement location. We have used this valuation technique since the adoption of 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.

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Results of Operations

Revenues. Our revenues are derived from the sale of our oil and natural gas production, which includes the effects of qualifying hedge contracts. Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold. Total revenue, including the effects of hedging, for the first nine months of 2009 was $217.5 million, which is a decrease of $195.4 million, or 47%, from the nine months ended September 30, 2008. Natural gas sales, excluding the effects of hedging, decreased by $251.1 million. Of this decrease, $237.9 million is attributable to a 63% decrease in natural gas prices and $13.2 million is due to a 3% decrease in production volumes. Oil sales decreased by $33.8 million of which $20.4 million was attributable to a 56% decrease in the price of oil and $13.4 million was attributable to decreased production. Approximately 93% of our revenue was attributable to natural gas sales on total volumes of 38.8 Bcfe in the first nine months of 2009.

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2009		2008		% Change Increase/ (Decrease)			2009		2008		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Natural gas sales	$	60,049	$	114,308		(47	%)	$	201,360	$	362,894		(45	%)
Oil sales		4,435		15,728		(72	%)		16,116		49,941		(68	%)
Total revenues	$	64,484	$	130,036		(50	%)	$	217,476	$	412,835		(47	%)

Production:
Gas (Bcf)		10.7		12.1		(12	%)		36.9		38.1		(3	%)
Oil (MBbls)		69.0		130.3		(47	%)		318.8		436.2		(27	%)
Total Equivalents (Bcfe)		11.1		12.9		(14	%)		38.8		40.8		(5	%)

$ per unit:
Avg. Gas Price per Mcf	$	5.61	$	9.47		(41	%)	$	5.46	$	9.51		(43	%)
Avg. Gas Price per Mcf excluding hedges	$	3.47	$	10.47		(67	%)	$	3.83	$	10.28		(63	%)
Avg. Oil Price per Bbl	$	64.28	$	120.66		(47	%)	$	50.55	$	114.48		(56	%)
Avg. Revenue per Mcfe including hedges	$	5.81	$	10.08		(42	%)	$	5.61	$	10.12		(45	%)

Natural Gas. For the three months ended September 30, 2009, natural gas revenue decreased by $54.3 million, including the realized impact of derivative instruments, from the comparable period in 2008, to $60.0 million from $114.3 million. This decrease is primarily due to the significant decline in commodity prices. The average gas price, including the effects of hedging, decreased by $3.86 per Mcf from $9.47 per Mcf for the three months ended September 30, 2008 to $5.61 per Mcf for the comparable period in 2009. The effect of gas hedging activities on natural gas revenue for the three months ended September 30, 2009 was a gain of $22.9 million as compared to a loss of $12.1 million for the three months ended September 30, 2008.

For the nine months ended September 30, 2009, natural gas revenue decreased by 45%, or $161.5 million, including the realized impact of derivative instruments, from the same period in 2008 to $201.4 million. This decrease was due to a lower average gas price. The average gas price, including the effects of hedging, decreased by 43%, or $4.05 per Mcf, from $9.51 per Mcf for the nine months ended September 30, 2008 to $5.46 per Mcf for the same period in 2009. The effect of gas hedging activities on natural gas revenue for the nine months ended September 30, 2009 was a gain of $60.1 million as compared to a loss of $29.4 million for the nine months ended September 30, 2008.

Crude Oil. For the three months ended September 30, 2009, oil revenue was $4.4 million as compared to $15.7 million for the same period in 2008. This decrease is attributable to the average realized price decrease of $56.38 per Bbl from $120.66 per Bbl for the three months ended September 30, 2008 to $64.28 per Bbl for the three months ended September 30, 2009. The decrease in oil production volumes was primarily due to a decline in well performance at our Sabine Lake property.

For the nine months ended September 30, 2009, oil revenue decreased by 68%, or $33.8 million, compared to the same period in 2008 to $16.1 million. This decrease is primarily attributable to lower average oil prices of $50.55 per Bbl for the nine months ended September 30, 2009 compared to $114.48 per Bbl for the same period in 2008. Oil volumes decreased overall by 27% for the nine months ended September 30, 2009 compared to the same period in 2008 due to decreases in production in Sabine Lake and the Gulf of Mexico region compared to the same period in 2008.

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Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2009		2008		% Change Increase/ (Decrease)			2009		2008		% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Lease operating expense	$	13,312	$	12,857		4	%	$	47,921	$	40,445		18	%
Production taxes		1,109		2,336		(53	%)		4,183		11,528		(64	%)
Depreciation, depletion and amortization		23,029		46,951		(51	%)		95,928		150,103		(36	%)
Impairment of oil and gas properties		-		205,659		(100	%)		379,462		205,659		85	%
General and administrative costs		10,414		15,419		(32	%)		32,358		41,042		(21	%)

$ per unit:
Avg. lease operating expense per Mcfe	$	1.20	$	1.00		20	%	$	1.24	$	0.99		25	%
Avg. production taxes per Mcfe	$	0.10	$	0.18		(44	%)	$	0.11	$	0.28		(61	%)
Avg. DD&A per Mcfe	$	2.07	$	3.64		(43	%)	$	2.47	$	3.68		(33	%)
Avg. G&A per Mcfe	$	0.94	$	1.19		(21	%)	$	0.83	$	1.01		(18	%)

Lease Operating Expense. Lease operating expense increased $0.5 million for the three months ended September 30, 2009 as compared to the three months ended September 30, 2008. The overall increase is due primarily to a $1.3 million increase in direct lease operating expense, a $0.3 million increase in insurance expense, and a $0.2 million increase in ad valorem tax expense partially offset by a $1.3 million decrease in workover expenses. The increase in direct lease operating expense is due to increased operating expenses from newly acquired properties from the Petroflow and Constellation acquisitions, which occurred during the second and fourth quarters of 2008, respectively, as well as non-operated lease operating expense. The increase in insurance expense is primarily due to increased premiums for new policies and the increase in ad valorem tax expense is primarily due to higher property value assessments in California. The decrease in workover expenses is due primarily to the September 2009 receipt of insurance proceeds related to Hurricane Ike, which occurred in September 2008, and to an overall decrease in workover activity.

Lease operating expense increased $7.5 million for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008. The overall increase is due to a $6.5 million increase in direct lease operating expense primarily related to acquisitions and non-operated lease operating expense and a $2.9 million increase in ad valorem tax expense partially offset by a $0.3 million decrease in insurance expense and a $1.6 million decrease in workover expense primarily due to the receipt of insurance proceeds related to Hurrican Ike. The higher costs are related to the increase in the number of operating wells, particularly in the Rockies and South Texas due to acquisitions and the Lobo drilling program, and the higher ad valorem taxes are due to higher property value assessments in California.

Production Taxes. Production taxes decreased $1.2 million for the three months ended September 30, 2009 as compared to the three months ended September 30, 2008 primarily due to the 67% decrease in realized natural gas and oil prices, excluding hedges, and the 14% decrease in production.

Production taxes decreased $7.3 million for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008 primarily due to the 63% decrease in realized natural gas and oil prices, excluding hedges, and the 5% decrease in production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense decreased $23.9 million for the three months ended September 30, 2009 as compared to the three months ended September 30, 2008. The decrease is due to the full cost ceiling test impairment charges recognized during the second half of 2008 and during the first quarter of 2009, which decreased the full cost pool and thus the DD&A rate. The DD&A rate for the third quarter of 2009 was $2.07 per Mcfe while the rate for the third quarter of 2008 was $3.64 per Mcfe. The decrease in the rate was due to a lower full cost asset base over a comparable reserve base in the third quarter of 2009 as compared to the same period in 2008.

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DD&A expense decreased $54.2 million for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008. The decrease is due to the full cost ceiling test impairment charges recognized during the second half of 2008 and during the first quarter of 2009 which decreased the full cost pool and thus the DD&A rate. The DD&A rate for the nine months ended September 30, 2009 was $2.47 per Mcfe while the rate for the same period of 2008 was $3.68 per Mcfe. The decrease in the rate was due to a lower full cost asset base over a comparable reserve base in the first three quarters of 2009 as compared to the same period in 2008.

Impairment of Oil and Gas Properties. The table below sets forth relevant assumptions utilized in our quarterly ceiling test computations for the respective periods noted.

	2009
	Total Impairment		September 30(1)		June 30		March 31
Henry Hub natural gas price (per MMBtu)(2)			$	4.59	$	3.89	$	3.63
West Texas Intermediate oil price (per Bbl)(2)			$	76.25	$	66.25	$	46.00
Increase (decrease) of calculated ceiling value due to cash flow hedges (pre-tax) (in thousands)			$	29,334	$	55,299	$	79,664
Impairment recorded (pre-tax) (in thousands)	$	379,462	$	-	$	-	$	379,462

	2008
	Total Impairment		September 30		June 30			March 31



Henry Hub natural gas price (per MMBtu)(2)			$	7.12	$	13.10		$	9.37
West Texas Intermediate oil price (per Bbl)(2)			$	96.37	$	140.22		$	105.63
Increase (decrease) of calculated ceiling value due to cash flow hedges (pre-tax) (in thousands)			$	37,440	$	(141,123	)	$	(60,043	)
Impairment recorded (pre-tax) (in thousands)	$	205,659	$	205,659	$	-		$	-

(1)

(2)

Adjusted for basis and quality differentials.

Due to the volatility of commodity prices, should natural gas and oil prices decline in the future, we experience a significant downward adjustment to our estimated proved reserves, and/or our commodity hedges settle and are not replaced, it is possible that another write-down of our oil and gas properties could occur.

General and Administrative Costs. General and administrative costs decreased by $5.0 million for the three months ended September 30, 2009 as compared to the three months ended September 30, 2008. This decrease is primarily due to the decrease of $5.7 million in legal expenses incurred during the third quarter of 2008 associated with the Calpine litigation, which was settled during the fourth quarter of 2008, the $0.6 million decrease in contract services, and the decrease of $0.5 million in bonus accrual. These decreases were partially offset by an increase in salaries, wages and benefits expense of $1.4 million due to an increase in headcount of 13 employees for the third quarter of 2009 compared to the third quarter of 2008 as well as an increase in option and stock expense of $0.6 million primarily due to the severance agreement with the former controller.

General and administrative costs decreased by $8.7 million for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008. The decrease is primarily due to the decrease of $11.7 million in legal fees associated with the Calpine litigation, which was settled during the fourth quarter of 2008, and a $1.2 million decrease in the bonus accrual offset by $3.3 million of higher payroll and benefit costs relating to the increase in employee headcount and $1.1 million of increased office rent expense for additional office space in Houston.

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Total Other Expense

Total other expense includes interest expense, interest income and other income/expense, net which increased $2.7 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. The interest income is earned on cash balances, which were lower during the quarter ended September 30, 2009 compared to September 30, 2008. Interest expense was higher for the quarter ended September 30, 2009 compared to the same period in 2008 due primarily to an increase in interest rates related to the debt refinancing. The weighted average interest rate for the third quarter of 2009 was 4.99% compared to 4.14% for the same period in 2008.

For the nine months ended September 30, 2009, total other expense increased by $4.0 million as compared to the nine months ended September 30, 2008 primarily as a result of reduced interest income earned due to lower cash balances for the period ended September 30, 2009 compared to the same period in 2008 and increased interest expense due to increased interest rates as a result of the debt refinancing during the period. The year to date weighted average interest rate for the period ended September 30, 2009 was 4.30% compared to 4.10% for the same period in 2008.

Provision for Income Taxes

The effective tax rate for the three and nine months ended September 30, 2009 was 40.2% and 36.8%, respectively. The effective tax rate for the three and nine months ended September 30, 2008 was 37.2% and 38.6%, respectively. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes, tax credits, a shortfall related to stock-based compensation, and other permanent differences. The income tax benefit for the nine months ended September 30, 2009 includes a $1.0 million downward adjustment recorded in the three months ended March 31, 2009 related to 2008 state taxes.

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with 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 September 30, 2009, we have a deferred tax asset of approximately $176.0 million resulting primarily from the difference between the book basis and tax basis of our oil and natural gas properties. We believe that it is more likely than not that this deferred tax asset will be realized through future taxable income generated by the production of our oil and natural gas properties.

Liquidity and Capital Resources

Our primary source of liquidity and capital is our operating cash flow. We also maintain a revolving line of credit, which can be accessed as needed to supplement operating cash flow. Additionally, we have an effective universal shelf registration statement on file with the SEC, which positions us to raise additional funds in the capital markets as deemed appropriate. However, we currently do not have any stated plans to issue securities.

Operating Cash Flow. Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We have the discretion to manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of a portion of our production, thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising natural gas prices. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas.” Our current hedge positions are expected to increase revenue by $14.7 million during the fourth quarter of 2009. The majority of our capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels. Current economic conditions and lower commodity prices could adversely affect our cash flow and liquidity. We will continue to monitor our cash flow and liquidity and if appropriate, we may consider accessing capital markets or adjusting our capital expenditure program.

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Senior Secured Revolving Line of Credit. On April 9, 2009, we entered into the Restated Revolver with BNP Paribas, as Administrative Agent, and the other lenders identified therein providing a senior secured revolving line of credit in the amount of up to $600.0 million, replacing the prior revolving credit agreement, and extending its term until July 1, 2012. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements. Our borrowing base is dependent on a number of factors including our level of reserves as well as the pricing outlook at the time of the redetermination. A reduction in capital spending could result in a reduced level of reserves thus causing a reduction in the borrowing base. The borrowing base under the Restated Revolver was set at $375.0 million as of September 30, 2009. We completed our borrowing base review during October 2009 and the borrowing base under the Restated Revolver was reduced from $375.0 million to $350.0 million. Amounts outstanding under the Restated Revolver bear interest, as amended, at specified margins over London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of our domestic subsidiaries, and a pledge of 100% of the membership interests of domestic subsidiaries. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At September 30, 2009, our current ratio was 5.7 and the leverage ratio was 1.6. 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 September 30, 2009. On October 22, 2009, we entered into the First Amendment to the Restated Revolver that deletes the “Reference Bank Cost of Funds Rate” option in the definition of Alternate Base Rate, allows the Company to make investments in US government securities, which mature in 15 months rather than one year, provides for certain other modifications to permitted investments, and provides for the release of the Lenders’ lien on a certain deposit account. As of November 6, 2009, we have $190.0 million outstanding, which is due and payable on July 1, 2012, with $160.0 million available for borrowing under the Restated Revolver.

Second Lien Term Loan. On April 9, 2009, we also entered into Restated Term Loan with BNP Paribas, as Administrative Agent, and other lenders identified therein replacing the prior Term Loan extending its term until October 2, 2012. Borrowings under the Restated Term Loan were initially set at $75.0 million and bear interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%. The Restated Term Loan had an option to increase fixed and floating rate borrowings by up to $25.0 million to $100.0 million prior to May 9, 2009. We exercised this option on April 21, 2009 and the increased borrowings consisted of $5.0 million of floating rate borrowings and $20.0 million of fixed rate borrowings at 13.75%. The loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At September 30, 2009, our asset coverage ratio was 3.0 and the leverage ratio was 1.6. 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 September 30, 2009. As of September 30, 2009, we had $80.0 million of variable rate borrowings and $20.0 million of fixed rate borrowings outstanding under the Restated Term Loan. At September 30, 2009, the principal balance of the Restated Term Loan was due and payable on October 2, 2012. On October 22, 2009, we also entered into the First Amendment to the Restated Term Loan that also deletes the “Reference Bank Cost of Funds Rate” option in the definition of Alternate Base Rate, allows the Company to make investments in US government securities, which mature in 15 months rather than one year, provides for certain other modifications to permitted investments, and provides for the release of the Lenders’ lien on a certain deposit account.

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

Cash Flows

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

	Nine Months Ended September 30,
	2009			2008
	(In thousands)
Cash flows provided by operating activities	$	122,924		$	326,301
Cash flows used in investing activities		(82,008	)		(197,172	)
Cash flows (used in) provided by financing activities		(18,073	)		2,838
Net increase in cash and cash equivalents	$	22,843		$	131,967

Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation and general and administrative expenses. Net cash provided by operating activities continued to be a primary source of liquidity and capital used to finance our capital program.

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Cash flows provided by operating activities decreased by $203.4 million for the nine months ended September 30, 2009 as compared to the same period for 2008. The decrease in 2009 primarily resulted from lower realized average natural gas and oil prices. In addition, at September 30, 2009, we had a working capital surplus of $56.4 million. This surplus was primarily attributable to the increase in derivative instruments and a decrease in accrued liabilities and royalties payable.

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

Cash flows used in investing activities decreased by $115.2 million for the nine months ended September 30, 2009 as compared to the same period for 2008. During the nine months ended September 30, 2009, we participated in the drilling of 36 gross wells as compared to the drilling of 112 gross wells during the same period in 2008.

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

Cash flows (used in) provided by financing activities decreased by $20.9 million as compared to the same period for 2008. The net decrease is primarily related to $40.0 million of payments on the revolving credit facility in the second and third quarters of 2009, $5.9 million of loan fees paid in connection with the Restated Revolver and Restated Term Loan during the second quarter of 2009, offset by $28.4 million of borrowings on the revolving credit facility during the first half of 2009.

Capital Expenditures

Our capital expenditures for the nine months ended September 30, 2009 decreased by $99.0 million to $85.9 million compared to the same period in 2008. During the nine months ended September 30, 2009, we participated in the drilling of 36 gross wells with the majority of these being in the Lobo region. Our positive operating cash flow and cash on hand are sufficient to fund planned capital expenditures for 2009, which are projected to be $125.0 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.

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 4 to 11% of our expected natural gas production through 2011. The fixed-price swap agreements we have entered into require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments were based on expected proved production from existing wells at inception of the hedge instruments.

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

The following table sets forth the results of commodity and interest rate swap hedging transaction settlements for the period ended September 30, 2009:

	Three Months Ended September 30,					Nine Months Ended September 30,
Natural Gas	2009		2008			2009		2008
Quantity settled (MMBtu)		5,256,972		6,706,092			15,599,493		19,498,524
Increase (decrease) in natural gas sales revenue (In thousands)	$	22,918	$	(12,125	)	$	60,077	$	(29,420	)
Interest Rate Swaps
Increase (decrease) in interest expense (In thousands)	$	-	$	(372	)	$	1,034	$	(832	)

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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).

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

Capital Requirements

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

Our capital expenditures for the period ended September 30, 2009 were $85.9 million, and we have plans to carefully execute an organic capital program in 2009 that can be funded from internally generated cash flows. We also have the discretion to access capital markets, if appropriate, and use available cash, borrowings under our Restated Revolver, and proceeds from divestitures to fund capital expenditures, including acquisitions, that make sense for the Company. However, our main priority for the foreseeable future is to preserve liquidity and maximize the financial position of the Company.

Commitments and Contingencies

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk primarily related to adverse changes in oil and natural gas prices and interest rates. We use derivative instruments to manage our commodity price risk caused by fluctuating prices 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 2008 Annual Report and Note 4 included in Part I. Item 1. Financial Statements of this Form 10-Q.

At September 30, 2009, we had open natural gas derivative hedges in an asset position with a fair value of $19.2 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $8.3 million, while a 10 percent decrease in natural gas prices would increase the fair value by approximately $8.1 million. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas”. Additionally, at September 30, 2009, 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 $0.09 million, while a 10 percent decrease in interest rates would decrease the fair value by approximately $0.09 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2009. In addition, the majority of our capital expenditures is discretionary and could be curtailed if our cash flows decline from expected levels.

Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities. Based upon communications with these counterparties, the obligations under these transactions are expected to continue to be met. We evaluated non-performance risk using current credit default swap values and default probabilities for each counterparty and recorded a downward adjustment to the fair value of our derivative assets in the amount of $0.03 million at September 30, 2009. We currently know of no circumstances that would limit access to our credit facility or require a change in our debt or hedging structure.

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Item 4. Controls and Procedures

(a) Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2009. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2009, 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.

Other than the remediation measure described below under “Management’s Remediation Efforts” no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Remediation Efforts. In our Quarterly Report on Form 10-Q for the period ended June 30, 2009, management concluded that the Company did not maintain effective controls over the monthly calculation and review of the DD&A expense calculation as of June 30, 2009, which constituted a material weakness. Specifically, effective controls did not exist to ensure that the proper inputs were used in the calculation.

During the third quarter of 2009, management has enhanced the controls over its DD&A expense calculation process to ensure that the proper inputs are used in the calculation. Specifically, management has performed a more comprehensive monthly review of the calculation, including a month to month comparison of variances in financial components of the calculation and quarterly verification by operations personnel that reserve information and associated costs are correct and properly included in the calculation. The enhanced controls have enabled management to ensure that the DD&A expense calculation is performed accurately. These enhanced controls were in place and operating effectively as of September 30, 2009.

(b) Other than as noted above, there were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s budget proposal, released by the White House on February 26, 2009, is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, the Senate Bill version of the Oil Industry Tax Break Repeal Act of 2009, introduced on April 23, 2009, and the Senate Bill version of the Energy Fairness for America Act, introduced on May 20, 2009, include many of the proposals outlined in President Obama’s budget proposal. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, either Senate Bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions within the industry that are currently available with respect to oil and gas exploration and production development, and any such change could negatively affect our financial condition and results of operations.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended September 30, 2009

Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May yet Be Purchased Under the Plans or Programs
July 1 - July 31		3,058	$	8.79		-		-
August 1 - August 31		534		10.44		-		-
September 1 - September 30		1,323		11.94		-		-
Total		4,915	$	9.82		-		-

(1)

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

Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

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

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 Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
3.2		Amended and Restated Bylaws (incorporated herin by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on December 10, 2008 (Registration No. 000-51801)).
4.1		Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
10.18		Amended and Restated Senior Revolving Credit Agreement (incorporated herin by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.19		Amended and Restated Second Lien Term Loan Agreement (incorporated herin by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.44*		First Amendment dated October 22, 2009 to Amended and Restated Senior Revolving Credit Agreement attached hereto as Exhibit 10.44.
10.45*		First Amendment dated October 22, 2009 to Amended and Restated Second Lien Term Loan Agreement attached hereto as Exhibit 10.45.
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: November 6, 2009

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ROSETTA RESOURCES INC.

EXHIBIT INDEX

Exhibit Number		Description
3.1		Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
3.2		Amended and Restated Bylaws (incorporated herin by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on December 10, 2008 (Registration No. 000-51801)).
4.1		Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
10.18		Amended and Restated Senior Revolving Credit Agreement (incorporated herin by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.19		Amended and Restated Second Lien Term Loan Agreement (incorporated herin by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.44*		First Amendment dated October 22, 2009 to Amended and Restated Senior Revolving Credit Agreement attached hereto as Exhibit 10.44.
10.45*		First Amendment dated October 22, 2009 to Amended and Restated Second Lien Term Loan Agreement attached hereto as Exhibit 10.45.
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