Rosetta Resources 8-K Other Events

Exhibit 99.1

Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

	Page
Report of Independent Registered Public Accounting Firm	1
Consolidated Balance Sheet at December 31, 2009 and 2008	2
Consolidated Statement of Operations for the years ended December 31, 2009, 2008 and 2007	3
Consolidated Statement of Cash Flows for the years ended December 31, 2009, 2008 and 2007	4
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2009, 2008 and 2007	5
Notes to Consolidated Financial Statements	6

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Rosetta Resources Inc.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows and of stockholders’ equity present fairly, in all material respects, the financial position of Rosetta Resources Inc. and its subsidiaries (the “Company”) at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting (not presented here in) appearing under Item 9A of the Company’s 2009 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2, at December 31, 2009 the Company changed the manner in which its oil and gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and gas costs.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2010, except with respect to our opinion on the consolidated financial statements insofar as it relates to guaranteed subsidiaries discussed in Note 17, as to which the date is July 20, 2010

1

Item 8. Financial Statements and Supplementary Data

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except share amounts)

	December 31,
	2009			2008
Assets
Current assets:
Cash and cash equivalents	$	61,256		$	42,855
Restricted cash		—			1,421
Accounts receivable		32,691			41,885
Derivative instruments		8,983			34,742
Prepaid expenses		2,837			5,046
Other current assets		6,415			4,071
Total current assets		112,182			130,020
Oil and natural gas properties, full cost method, of which $42.3 million at December 31, 2009 and $50.3 million at December 31, 2008 were excluded from amortization		2,030,433			1,900,672
Other fixed assets		12,417			9,439
		2,042,850			1,910,111
Accumulated depreciation, depletion, and amortization, including impairment		(1,452,248	)		(935,851	)
Total property and equipment, net		590,602			974,260
Deferred loan fees		4,921			1,168
Deferred tax asset		169,732			42,652
Other assets		2,147			6,278
Total other assets		176,800			50,098
Total assets	$	879,584		$	1,154,378
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	2,279		$	2,268
Accrued liabilities		37,107			48,824
Royalties payable		16,064			17,388
Derivative instruments		236			985
Prepayment on gas sales		7,542			19,382
Deferred income taxes		3,258			12,575
Total current liabilities		66,486			101,422
Long-term liabilities:
Derivative instruments		1,960			—
Long-term debt		288,742			300,000
Other long-term liabilities		29,301			26,584
Total liabilities	$	386,489		$	428,006
Commitments and contingencies (Note 11)
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 51,254,709 shares and 51,031,481 shares at December 31, 2009 and 2008, respectively		51			51
Additional paid-in capital		780,196			773,676
Treasury stock, at cost; 199,955 and 155,790 shares at December 31, 2009 and 2008, respectively		(3,473	)		(2,672	)
Accumulated other comprehensive income		4,259			24,079
Accumulated deficit		(287,938	)		(68,762	)
Total stockholders’ equity		493,095			726,372
Total liabilities and stockholders’ equity	$	879,584		$	1,154,378

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

2

Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

	Year Ended December 31,
	2009			2008			2007
Revenues:
Natural gas sales	$	250,684		$	398,268		$	295,644
Oil sales		21,763			55,736			40,148
NGL sales		21,504			45,343			27,697
Total revenues		293,951			499,347			363,489
Operating costs and expenses:
Lease operating expense		60,773			55,694			47,044
Depreciation, depletion, and amortization		121,042			198,862			152,882
Impairment of oil and gas properties		379,462			444,369			—
Treating and transportation		5,675			6,323			4,230
Marketing fees		593			3,064			2,450
Production taxes		6,131			13,528			6,417
General and administrative costs		46,993			52,846			43,867
Total operating costs and expenses		620,669			774,686			256,890
Operating income (loss)		(326,718	)		(275,339	)		106,599
Other (income) expense:
Interest expense, net of interest capitalized		19,258			14,688			17,734
Interest income		(97	)		(1,600	)		(1,674	)
Other (income) expense, net		(876	)		12,510			(698	)
Total other expense		18,285			25,598			15,362
Income (loss) before provision for income taxes		(345,003	)		(300,937	)		91,237
Income tax expense (benefit)		(125,827	)		(112,827	)		34,032
Net income (loss)	$	(219,176	)	$	(188,110	)	$	57,205
Earnings (loss) per share:
Basic	$	(4.30	)	$	(3.71	)	$	1.14
Diluted	$	(4.30	)	$	(3.71	)	$	1.13
Weighted average shares outstanding:
Basic		50,979			50,693			50,379
Diluted		50,979			50,693			50,589

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

3

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

	Year Ended December 31,
	2009			2008			2007
Cash flows from operating activities
Net income (loss)	$	(219,176	)	$	(188,110	)	$	57,205
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization		121,042			198,862			152,882
Impairment of oil and gas properties		379,462			444,369			—
Deferred income taxes		(124,632	)		(116,519	)		33,915
Amortization of deferred loan fees recorded as interest expense		2,102			1,027			1,180
Amortization of original issue discount recorded as interest expense		342			—			—
Stock compensation expense		7,836			7,234			6,831
Other non-cash items		—			(512	)		(181	)
Change in operating assets and liabilities:
Accounts receivable		9,194			13,163			(18,640	)
Income taxes receivable		—			(776	)		—
Prepaid expenses		2,209			5,367			(1,652	)
Other current assets		(2,344	)		178			(1,284	)
Other assets		(484	)		191			144
Accounts payable		11			5,031			10,909
Accrued liabilities		(1,897	)		7,322			3,998
Royalties payable		(13,164	)		(2,108	)		12,000
Net cash provided by operating activities		160,501			374,719			257,307
Cash flows from investing activities
Acquisition of oil and gas properties		(3,844	)		(163,187	)		(38,656	)
Purchases of oil and gas assets		(141,016	)		(228,464	)		(284,541	)
Disposals of oil and gas properties and assets		19,574			—			—
(Increase) decrease in restricted cash		1,421			(1,421	)		—
Other		—			2			1,156
Net cash used in investing activities		(123,865	)		(393,070	)		(322,041	)
Cash flows from financing activities
Borrowings on revolving credit facility		28,400			55,000			10,000
Payments on revolving credit facility		(40,000	)		—			(5,000	)
Deferred loan fees		(5,855	)		—			—
Proceeds from stock options exercised		21			3,617			653
Purchases of treasury stock		(801	)		(627	)		(483	)
Net cash (used in) provided by financing activities		(18,235	)		57,990			5,170
Net increase (decrease) in cash		18,401			39,639			(59,564	)
Cash and cash equivalents, beginning of year		42,855			3,216			62,780
Cash and cash equivalents, end of year	$	61,256		$	42,855		$	3,216
Supplemental disclosures:
Cash paid for interest expense, net of capitalized interest	$	16,813		$	13,658		$	18,862
Cash (received) paid for tax	$	(1,196	)	$	4,470		$	115
Supplemental non-cash disclosures:
Capital expenditures included in accrued liabilities	$	18,199		$	26,555		$	34,599
Release of suspended revenues and non-consent liabilities resulting from Calpine Settlement included in Accounts payable and Acquisition of oil and gas properties	$	—		$	36,713		$	—

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

4

Rosetta Resources Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands, except share amounts)

				Additional Paid-In Capital						Accumulated Other Comprehensive (Loss)/Income			Retained Earnings / Accumulated Deficit			Total Stockholders’ Equity
	Common Stock					Treasury Stock
	Shares	Amount				Share	Amount
Balance at December 31, 2006	50,405,794	$	50	$	755,343	85,788	$	(1,562	)	$	6,315		$	62,143		$	822,289
Stock options exercised	40,104		—		653	—		—			—			—			653
Treasury stock-employee tax payment	—		—		—	23,515		(483	)		—			—			(483	)
Stock-based compensation	—		—		6,831	—		—			—			—			6,831
Vesting of restricted stock	96,750		—		—	—		—			—			—			—
Comprehensive income:	—		—		—	—		—			—			—			—
Net income	—		—		—	—		—			—			57,205			57,205
Change in fair value of derivative hedging instruments	—		—		—	—		—			1,276			—			1,276
Hedge settlements reclassified to income	—		—		—	—		—			(22,926	)		—			(22,926	)
Tax benefit related to cash flow hedges	—		—		—	—		—			8,110			—			8,110
Comprehensive income	—		—		—	—		—			—			—			43,665
Balance at December 31, 2007	50,542,648	$	50	$	762,827	109,303	$	(2,045	)	$	(7,225	)	$	119,348		$	872,955
Stock options exercised	214,119		1		3,615	—		—			—			—			3,616
Treasury stock-employee tax payment	—		—		—	46,487		(627	)		—			—			(627	)
Stock-based compensation	—		—		7,234	—		—			—			—			7,234
Vesting of restricted stock	274,714		—		—	—		—			—			—			—
Comprehensive loss:	—		—		—	—		—			—			—			—
Net loss	—		—		—	—		—			—			(188,110	)		(188,110	)
Change in fair value of derivative hedging instruments	—		—		—	—		—			30,057			—			30,057
Hedge settlements reclassified to income	—		—		—	—		—			19,829			—			19,829
Tax expense related to cash flow hedges	—		—		—	—		—			(18,582	)		—			(18,582	)
Comprehensive loss	—		—		—	—		—			—			—			(156,806	)
Balance at December 31, 2008	51,031,481	$	51	$	773,676	155,790	$	(2,672	)	$	24,079		$	(68,762	)	$	726,372
Stock options exercised	14,125		—		21	—		—			—			—			21
Treasury stock-employee tax payment	—		—		—	44,165		(801	)		—			—			(801	)
Stock-based compensation	—		—		6,499	—		—			—			—			6,499
Vesting of restricted stock	209,103		—		—	—		—			—			—			—
Comprehensive loss:	—		—		—	—		—			—			—			—
Net loss	—		—		—	—		—			—			(219,176	)		(219,176	)
Change in fair value of derivative hedging instruments	—		—		—	—		—			43,693			—			43,693
Hedge settlements reclassified to income	—		—		—	—		—			(75,278	)		—			(75,278	)
Tax expense related to cash flow hedges	—		—		—	—		—			11,765			—			11,765
Comprehensive loss	—		—		—	—		—			—			—			(238,996	)
Balance at December 31, 2009	51,254,709	$	51	$	780,196	199,955	$	(3,473	)	$	4,259		$	(287,938	)	$	493,095

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

5

Rosetta Resources Inc.

Notes to Consolidated Financial Statements

(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.

In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through February 26, 2010, the date the financial statements were issued. See Item 8. “Financial Statements and Supplementary Data, Note 16 – Subsequent Events.”

Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income (loss).

(2) Summary of Significant Accounting Policies

Change in accounting principle

As more fully described below inProperty Plant and Equipment, net and Supplemental Oil and Gas Disclosures within these consolidated financial statements, in January 2010 the FASB issued Accounting Standards Update 2010-03, “Extractive Activities — Oil and Gas”, which conforms the authoritative guidance to the requirements of the new SEC rules released in December 2008 “Modernization of Oil and Gas Reporting” and are effective December 31, 2009. The principle revisions under the new authoritative guidance include changing the manner in which oil and gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and gas costs. This change in accounting has been treated in these financial statements as a change in accounting principle that is inseparable from a change in accounting estimate.

The effect of the adoption at December 31, 2009 was not significant to the Company’s financial statements. The adoption of the new rule will result in future amounts recorded for depreciation, depletion and amortization and ceiling limitations being different from what would have been recorded if the new rules would not have been mandated.

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. The Company applied this guidance as of the period ended September 30, 2009.

Principles of Consolidation and Basis of Presentation

The accompanying consolidated financial statements for the years ended December 31, 2009, 2008 and 2007 contain the accounts of Rosetta Resources Inc. and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.

Use of Estimates in Preparation of Financial Statements

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates their estimates and assumptions on a regular basis. The Company bases their estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of derivative instruments, future development and abandonment costs, estimates to certain oil and gas revenues and expenses and estimates of proved oil and natural gas reserve quantities used to calculate depletion, depreciation and impairment of proved oil and natural gas properties and equipment.

6

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

With respect to the current market environment for liquidity and access to credit, the Company, through banks participating in its credit facility, has 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. The Company has followed this policy and believes this is an appropriate approach for the investment of Company funds.

Restricted Cash

At December 31, 2009, the Company had no restricted cash. Restricted cash of $1.4 million at December 31, 2008 consisted of cash deposited by the Company in an escrow account, which was created in conjunction with the South Texas acquisitions for potential environmental remediation costs associated with acquired properties.

Allowance for Doubtful Accounts

The Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for individual customer balances.

Property, Plant and Equipment, Net

The Company follows the full cost method of accounting for oil and natural gas properties. Under the full cost method, all costs incurred in acquiring, exploring and developing properties, including salaries, benefits and other internal costs directly attributable to these activities, are capitalized when incurred into cost centers that are established on a country-by-country basis, and are amortized as reserves in the cost center in which they are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs, such as those associated with offshore U.S. operations, unevaluated properties and significant development projects are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and natural gas producing activities are regarded as integral to the acquisition, discovery and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $4.8 million, $7.1 million and $5.5 million of internal costs for the years ended December 31, 2009, 2008 and 2007, respectively. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment at which time they are transferred to the full cost pool to be amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless a significant portion of the pool or reserves are sold.

The Company assesses the impairment for oil and natural gas properties quarterly using a ceiling test to determine if impairment is necessary. This ceiling limits capitalized costs to the present value of estimated future cash flows from proved oil and natural gas reserves (including the effect of any related hedging activities) reduced by future operating expenses, development expenditures, abandonment costs (net of salvage values) to the extent not included in oil and gas properties pursuant to authoritative guidance, and estimated future income taxes thereon. Prior to December 31, 2009, the ceiling calculation dictated that prices and costs in effect as of the last day of the quarter be held constant. The current ceiling calculation utilizes prices calculated as a twelve-month average price using first day of the month prices and costs in effect as of the last day of the quarter are held constant. Prior to December 31, 2009, for periods in which a write-down was required, if oil and gas prices increased subsequent to the end of a quarter or annual period but prior to the issuance of the financial statements, the Company was allowed to adjust the write-down to reflect the higher prices. As of December 31, 2009, the use of the recovery of prices after the end of the period is no longer permitted. 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 lower DD&A expense in the future. The average rates of DD&A were $2.39, $3.71 and $3.34 per Mcfe in 2009, 2008 and 2007, respectively.

7

The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted:

	2009
	Total Impairment		December 31(3)		September 30(1)		June 30		March 31
Henry Hub natural gas price (per MMBtu)(4)			$	3.87	$	4.59	$	3.89	$	3.63
West Texas Intermediate oil price (per Bbl)(4)				57.65		76.25		66.25		46.00
Increase (decrease) of calculated ceiling value due to cash flow hedges (pre-tax) (in thousands)				45,000		29,334		55,299		79,664
Impairment recorded (pre-tax) (in thousands)	$	379,462		—		—		—		379,462
Potential impairment absent the effects of hedging (pre-tax) (in thousands) (5)				29,482		—		26,337		459,126

	2008
	Total Impairment		December 31		September 30		June 30			March 31
Henry Hub natural gas price (per MMBtu)(4)			$	5.71	$	7.12	$	13.10		$	9.37
West Texas Intermediate oil price (per Bbl)(4)				41.00		96.37		140.22			105.63
Increase (decrease) of calculated ceiling value due to cash flow hedges (pre-tax) (in thousands)				47,142		37,440		(141,123	)		(60,043	)
Impairment recorded (pre-tax) (in thousands)	$	444,369		238,710		205,659		—			—
Potential impairment absent the effects of hedging (pre-tax) (in thousands) (5)				285,852		243,099		—			—

	2007
	Total Impairment		December 31(2)			September 30		June 30		March 31
Henry Hub natural gas price (per MMBtu)(4)			$	8.91		$	6.38	$	6.80	$	7.34
West Texas Intermediate oil price (per Bbl)(4)				98.88			82.88		69.63		66.20
Increase (decrease) of calculated ceiling value due to cash flow hedges (pre-tax) (in thousands)				(34,616	)		46,056		34,582		23,904
Impairment recorded (pre-tax) (in thousands)	$	—		—			—		—		—
Potential impairment absent the effects of hedging (pre-tax) (in thousands) (5)				—			31,657		—		—

(1) 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 at the time, the Company re-evaluated the ceiling test on October 29, 2009 using the market price for Henry Hub of $4.59 per MMBtu and West Texas Intermediate oil price 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 Company’s net capitalized cost of oil and gas properties. As a result, no write-down was recorded for the quarter ended September 30, 2009.

(2) The Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at December 31, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and a West Texas Intermediate oil price of $92.50 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at December 31, 2007 increased the calculated ceiling value by approximately $32.1 million (pre-tax). The use of these prices would have resulted in a pre-tax write-down of $21.5 million at December 31, 2007. As allowed under the full cost accounting rules at the time, the Company re-evaluated the ceiling test on February 22, 2008 using the market price for Henry Hub of $8.91 per MMBtu and West Texas Intermediate oil price of $98.88 per Bbl (adjusted for basis and quality

8

differentials). At these prices, cash flow hedges of natural gas production in place decreased the calculated ceiling value by approximately $34.6 million (pre-tax). Utilizing these prices, the calculated ceiling amount exceeded the Company’s net capitalized cost of oil and gas properties. As a result, no write-down was recorded for the quarter ended December 31, 2007.

(3) The December 31, 2009 oil and natural gas prices are calculated as a twelve-month historical average of the first day of the month prices for the West Texas Intermediate oil price and the Henry Hub natural gas price.

(4) Adjusted for basis and quality differentials.

(5) Represents the total potential impairment excluding the effects of hedging. Where there is no potential impairment for the period, the Company was able to utilize higher prices subsequent to period end and there would have been no impairment recognized with or without the effects of hedging.

Due to the volatility of commodity prices, should oil and natural gas 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.

Other property, plant and equipment primarily includes furniture, fixtures and automobiles, which are recorded at cost and depreciated on a straight-line basis over useful lives of five to seven years. Repair and maintenance costs are charged to expense as incurred while renewals and betterments are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of property, plant and equipment are recorded in the period incurred. The net book value of the property, plant and equipment that is retired or sold is charged to accumulated depreciation, asset cost and amortization, and the difference is recognized as a gain or loss in the results of operations in the period the retirement or sale transpires.

Future Development and Abandonment Costs

Future development costs include costs incurred to obtain access to proved reserves, such as drilling costs and the installation of production equipment, and such costs are included in the calculation of DD&A expense. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis.

We provide for future abandonment costs in accordance with authoritative guidance regarding the accounting for asset retirement obligations. This guidance requires that a liability for the fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.

Capitalized Interest

The Company capitalizes interest on capital invested in projects related to unevaluated properties and significant development projects in accordance with authoritative guidance for the capitalization of interest cost. As proved reserves are established or impairment determined, the related capitalized interest is included in costs subject to amortization.

Fair Value of Financial Instruments

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. Derivatives are also recorded on the balance sheet at fair value. The carrying amount of long-term debt reported in the consolidated balance sheet at December 31, 2009 is $288.7 million. The Company calculated the fair value of its long-term debt as of December 31, 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 $303.0 million at December 31, 2009. The fair market value of debt at December 31, 2008 was $275.0 million.

Concentrations of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative instruments. The Company’s accounts receivable and derivative instruments are concentrated among entities engaged in the energy industry within the United States and financial institutions, respectively.

9

Deferred Loan Fees

Loan fees incurred in connection with the credit facility are recorded on the Company’s Consolidated Balance Sheet as deferred loan fees. The deferred loan fees are amortized to interest expense over the term of the related debt using the straight-line method, which approximates the effective interest method.

Derivative Instruments and Hedging Activities

The Company uses derivative instruments to manage market risks resulting from fluctuations in commodity prices of natural gas and crude oil. The Company also uses derivatives to manage interest rate risk associated with its debt under its credit facility. The Company periodically enters into derivative contracts, including price swaps or costless price collars, which may require payments to (or receipts from) counterparties based on the differential between a fixed price or interest rate and a variable price or LIBOR rate for a fixed notional quantity or amount 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 or debt under its current credit agreements.

Derivatives are recorded on the balance sheet at fair market value and changes in the fair market value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated and qualifies as a hedge. The Company’s derivatives consist of cash flow hedges in which the Company is hedging the variability of cash flows related to a forecasted transaction. Changes in the fair market value of these derivative instruments designated as cash flow hedges are reported in accumulated other comprehensive income and reclassified to earnings in the periods in which the contracts are settled. The ineffective portion of the cash flow hedge is recognized in current period earnings as other income (expense). Gains and losses on derivative instruments that do not qualify for hedge accounting are included in revenue in the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities.

At the inception of a derivative contract, the Company may designate the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, the Company formally documents the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. The Company measures hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item and gains and losses are recognized in income. Gains and losses included in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered. If the Company determines it is not probable that a forecasted transaction will occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. The Company does not enter into derivative agreements for trading or other speculative purposes. See Item 8. “Financial Statements and Supplementary Data, Note 6 – Commodity Hedging Contracts and Other Derivatives” for a description of the derivative contracts which the Company executes.

Environmental

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the cost can be reasonably estimated. There were no significant environmental liabilities at December 31, 2009 or 2008.

Stock-Based Compensation

Stock-based compensation cost for options is estimated at the grant date based on the award’s fair value as calculated by the Black-Scholes option-pricing model and is recognized as expense over the requisite service period. The Black-Scholes model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. Stock-based compensation cost for restricted stock is estimated at the grant date based on the award’s fair value which is equal to the average high and low common stock price on the date of grant and is recognized as expense over the requisite service period.

Stock-based compensation for PSUs is 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 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 measured at the end of each reporting period based on

10

the fair value derived from the Monte Carlo model. The Monte Carlo model requires various highly judgmental assumptions including volatility and future cash flow projections. If any of the assumptions used in the Monte Carlo model change significantly, stock-based compensation expense may differ materially in the future from that recorded in the current period.

Any excess tax benefit arising from our deferred compensation plans is recognized as a credit to additional paid in capital when realized and is calculated as the amount by which the tax deduction received exceeds the deferred tax asset associated with the recorded stock compensation expense. The Company has approximately $0.3 million of related excess tax benefits which will be recognized upon utilization of our net operating loss carryforward. Current authoritative guidance requires the cash flows that result from tax deductions in excess of the compensation expense to be recognized as financing activities.

Preferred Stock

The Company is authorized to issue 5,000,000 shares of preferred stock with preferences and rights as determined by the Company’s Board of Directors. As of December 31, 2009 and 2008, there were no shares of preferred stock outstanding.

Treasury Stock

Shares of common stock were repurchased by the Company as the shares were surrendered by the 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 the Company’s common stock, nor does the Company have a publicly announced program to repurchase shares of common stock.

Revenue Recognition

The Company uses the sales method of accounting for the sale of its natural gas. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At December 31, 2009 and 2008, imbalances were insignificant.

Since there is a ready market for natural gas, crude oil and NGLs, the Company sells its products soon after production at various locations at which time title and risk of loss pass to the buyer. Revenue is recorded when title passes based on the Company’s net interest or nominated deliveries of production volumes. The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, NGLs and crude oil are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. Historically, these adjustments have been insignificant. In addition, natural gas and crude oil volumes sold are not significantly different from the Company’s share of production.

The Company calculates and pays royalties on natural gas, crude oil and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in the period in which the natural gas, crude oil or NGLs are produced and are included in Royalties Payable on the Company’s Consolidated Balance Sheet.

Income Taxes

Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax basis of assets and liabilities using the liability method in accordance with the provisions set forth in the authoritative guidance regarding the accounting for income taxes. Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Recent Accounting Developments

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

Business Combinations. In December 2007, the FASB 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

11

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 the Company 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 the Company’s consolidated financial position, results of operations or cash flows.

Noncontrolling 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 the Company’s 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 Item 8. “Financial Statements and Supplementary Data, Note 6 - Commodity Hedging Contracts and Other Derivatives.”

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, the Company implemented the guidance for nonfinancial assets and liabilities. The adoption of this guidance did not have an impact on the Company’s 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. The Company applied this guidance to financial assets measured at fair value on a recurring basis at September 30, 2009. See Item 8. “Financial Statements and Supplementary Data, Note 5 – Fair Value Measurements.” The adoption of this guidance did not have a significant impact on the Company’s 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. The Company 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.

In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures will be required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance will require additional disclosures but will not impact the Company’s consolidated financial position, results of operations or cash flows.

Subsequent Events. In May 2009, the FASB issued authoritative guidance on subsequent events to incorporate accounting guidance that originated as auditing standards into the body of authoritative literature issued by the FASB. This guidance requires the evaluation of subsequent events through the date the financial statements are issued or are available for issue and the disclosure of the date through which subsequent events were evaluated and the basis for that date. This guidance is effective for interim and annual financial periods ending after June 15, 2009. The Company adopted the requirements of this guidance for the period ended June 30, 2009 and the adoption did not have a significant impact on our consolidated financial position, results of operations or cash flows. On February 25, 2010, the FASB amended this guidance to remove the requirement to disclose the date through which an entity has evaluated subsequent events. See Item 8. “Financial Statements and Supplementary Data, Note 16 – Subsequent Events.”

12

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

Oil and Gas Reporting Requirements. In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting” (the “Release”). The disclosure requirements under this Release require reporting of oil and gas reserves using an average price based upon the prior twelve-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 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. In January 2010, the FASB issued its guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. The Company applied this guidance at December 31, 2009 as a change in accounting principle that is inseparable from a change in accounting estimate. This methodology was different than that applied at December 31, 2008 and March 31, 2009, each of which resulted in a ceiling test write-down. The effect of the adoption at December 31, 2009 was not significant to the Company’s financial statements. The adoption of the new rule will result in future amounts recorded for depreciation, depletion and amortization and ceiling limitations being different from what would have been recorded if the new rules would not have been mandated. See Item 8. “Financial Statements and Supplementary Data, Supplemental Oil and Gas Disclosures.”

(3) Accounts Receivable

Accounts receivable consists of the following:

	December 31,
	2009		2008
	(In thousands)
Natural gas, NGLs and oil revenue sales	$	29,938	$	37,982
Joint interest billings		2,328		3,422
Short-term receivable for royalty recoupment		425		481
Total		32,691		41,885

There are no balances in accounts receivable that are considered to be uncollectible and an allowance was unnecessary at December 31, 2009 and 2008.

(4) Property, Plant and Equipment

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

	December 31,
	2009			2008
	(In thousands)
Proved properties	$	1,949,515		$	1,813,527
Unproved/unevaluated properties		42,344			50,252
Gas gathering system and compressor stations		38,574			36,893
Other		12,417			9,439
Total		2,042,850			1,910,111
Less: Accumulated depreciation, depletion, and amortization		(1,452,248	)		(935,851	)
	$	590,602		$	974,260

Included in the Company’s oil and natural gas properties are asset retirement costs of $21.9 million and $23.2 million at December 31, 2009 and 2008, respectively, including additions of $1.9 million and $1.7 million for the year ended December 31, 2009 and 2008, respectively.

13

As discussed in Note 2, 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 recorded a non-cash, pre-tax write-down of $379.5 million at March 31, 2009. There were no other ceiling test write-downs recorded during the year ended December 31, 2009. However, due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that an additional write-down could occur.

The Company also recorded a non-cash, pre-tax write-down of $205.7 million at September 30, 2008. Due to continued declines in oil and gas prices and a downward revision of 8 Bcfe due to year-end commodity prices, at December 31, 2008, capitalized costs of our proved oil and gas properties exceeded our ceiling, resulting in an additional non-cash, pre-tax write-down of $238.7 million.

Capitalized costs excluded from DD&A as of December 31, 2009 and 2008, are as follows by the year in which such costs were incurred:

	December 31, 2009
	Total		2009		2008		2007		Prior
	(in thousands)
Onshore:
Development cost	$	505	$	505	$	—	$	—	$	—
Exploration cost		8,732		8,732		—		—		—
Acquisition cost of undeveloped acreage		31,326		14,165		14,734		2,398		29
Capitalized interest		1,781		83		1,347		349		2
		42,344		23,485		16,081		2,747		31
Offshore:
Development cost		—		—		—		—		—
Exploration cost		—		—		—		—		—
Acquisition cost of undeveloped acreage		—		—		—		—		—
Capitalized interest		—		—		—		—		—
		—		—		—		—		—
Total capitalized costs excluded from DD&A	$	42,344	$	23,485	$	16,081	$	2,747	$	31

	December 31, 2008
	Total		2008		2007		2006		Prior
	(in thousands)
Onshore:
Development cost	$	13,320	$	13,320	$	—	$	—	$	—
Exploration cost		3,555		3,555		—		—		—
Acquisition cost of undeveloped acreage		29,926		23,958		4,949		988		31
Capitalized interest		2,552		1,978		433		141		—
		49,353		42,811		5,382		1,129		31
Offshore:
Development cost		—		—		—		—		—
Exploration cost		—		—		—		—		—
Acquisition cost of undeveloped acreage		786		—		—		786		—
Capitalized interest		113		—		—		113		—
		899		—		—		899		—
Total capitalized costs excluded from DD&A	$	50,252	$	42,811	$	5,382	$	2,028	$	31

It is anticipated that the acquisition of undeveloped acreage and associated capitalized interest of $33.1 million and development and exploration costs of $9.2 million will be included in oil and gas properties subject to amortization within five years and one year, respectively.

Property Acquisitions. During the first quarter of 2009, the Company acquired the remaining 10% working interest in the 1,280-acre position Pinedale Anticline in the Rockies for $3.8 million and obtained operatorship.

During the fourth quarter of 2008, the Company acquired a 90% working interest in a 1,280-acre position in the Pinedale Anticline in the Rockies for $35.0 million and a 70% working interest in certain properties in the Catarina Field and a 35% working interest in a significant acreage position in the Eagle Ford shale in South Texas for $20.0 million.

14

During the second quarter of 2008, the Company acquired a 50% working interest position in approximately 12,000 gross acres in the Rockies for $29.0 million.

During the second quarter of 2007, the Company acquired properties located in the Sacramento Basin at a total purchase price of $38.7 million.

Gas Gathering System and Compressor Stations. In December 2008, we purchased approximately 62 miles of low pressure gathering from Pacific Gas and Electric for $1.3 million. The gathering system is located in the heart of the Rio Vista field and gathers much of our low pressure production within the Rio Vista field. The gas gathering system and compressor stations of $38.6 million and $36.9 million at December 31, 2009 and 2008, respectively, are primarily located in California and the Rockies, and are recorded at cost and depreciated on a straight-line basis over useful lives of 15 years. The accumulated depreciation for the gas gathering system at December 31, 2009 and 2008 was $7.7 million and $5.3 million, respectively. The depreciation expense associated with the gas gathering system and compressor stations for the years ended December 31, 2009, 2008 and 2007 was $2.5 million, $2.2 million, and $1.5 million, respectively.

Other Property and Equipment. Other property and equipment at December 31, 2009 and 2008 of $12.4 million and $9.4 million, respectively, consists primarily of furniture and fixtures. The accumulated depreciation associated with other assets at December 31, 2009 and 2008 was $4.3 million and $2.6 million, respectively. For the years ended December 31, 2009, 2008 and 2007 depreciation expense for other property and equipment was $1.7 million, $1.2 million, and $0.8 million, respectively.

(5) Deferred Loan Fees

At December 31, 2009 and 2008, deferred loan fees were $4.9 million and $1.2 million, respectively. Total amortization expense for deferred loan fees was $2.1 million, $1.0 million and $1.2 million for the years ended December 31, 2009, 2008 and 2007, respectively.

(6) 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 December 31, 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)
2010	Swap	Cash flow	15,000	5,475,000	$	7.46	$	—	13	%	$	8,834
2010	Costless Collar	Cash flow	15,041	5,490,000		5.75		7.40	13	%		548
2011	Swap	Cash flow	5,000	1,825,000		5.72			5	%		(408	)
2011	Costless Collar	Cash flow	25,000	9,125,000		5.80		7.58	23	%		(1,552	)
				21,915,000							$	7,422

(1) Estimated based on anticipated future gas production.

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

Settlement Period	Derivative Instrument	Hedge Strategy	Average Fixed Rate		Fair  Market Value Asset/(Liability) (In thousands)
January 1 - December 31, 2010	Swap	Cash Flow	1.24	%	$	(635	)

15

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 December 31, 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:

	For the Year Ended December 31,
	2009			2008
Natural Gas
Quantity settled (MMBtu)		20,856,465			26,684,616
Increase (decrease) in natural gas sales revenue (In thousands)	$	76,567		$	(18,669	)
Interest Rate Swaps
Increase in interest expense (In thousands)	$	(1,289	)	$	(1,158	)

As of December 31, 2009, the Company expects to reclassify gains of $8.7 million to earnings from the balance in accumulated other comprehensive income (loss) 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.

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 December 31, 2009, the Company had outstanding natural gas commodity forward contracts with a notional volume of 21,915,000 MMBtus that were entered into to hedge forecasted natural gas sales.

As of December 31, 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 December 31, 2009 is as follows:

	Fair Values of Derivative Instruments Derivative Assets (Liabilities)
	December 31, 2009
	Balance Sheet Location	Fair Value
		(in thousands)
Derivatives designated as hedging instruments
Interest rate swap	Derivative Instruments - current assets	$	(399	)
Interest rate swap	Derivative Instruments - current liabilities		(236	)
Interest rate swap	Derivative Instruments - non-current liabilities		—
Interest rate swap	Other assets - non-current assets		—
Commodity contracts	Derivative Instruments - current assets		9,382
Commodity contracts	Derivative Instruments - non-current liabilities		(1,960	)
Total derivatives designated as hedging instruments		$	6,787
Total derivatives not designated as hedging instruments		$	—
Total derivatives		$	6,787

��

16

	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)			Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion  and Amount Excluded from Effectiveness Testing)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (1)
Derivatives in Cash Flow Hedging Relationships	Twelve Months Ended December 31, 2009				Twelve Months Ended December 31, 2009				Twelve Months Ended December 31, 2009
	(in thousands)				(in thousands)				(in thousands)
Interest rate swap	$	(1,923	)	Interest expense, net of interest capitalized	$	(767	)	Interest expense, net of interest capitalized	$	(522	)
Commodity contracts		45,616		Natural gas sales		76,567		Natural gas sales		—
Total	$	43,693		Total	$	75,800		Total	$	(522	)

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

On April 9, 2009, the Company entered into an amended and restated revolving credit agreement replacing the previous revolving credit agreement. At the time of the amended and restated revolving credit agreement, the Company had two outstanding interest rate swaps which established a fixed interest rate for a portion of the previous outstanding revolver that were designated as cash flow hedges and which became ineffective. 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 twelve months ended December 31, 2009, there were no gains or losses recognized in income representing hedge components excluded from the assessment of effectiveness.

(7) 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 December 31, 2009, and no other fair value measurements are required to be recognized on a non-recurring basis, no additional disclosures are provided at December 31, 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

17

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 December 31, 2009 and 2008. The Company identified the money market funds as Level 3 instruments due to the fact that quoted prices for the underlying investments cannot be obtained and there is not an active market for the underlying investments. The Company utilizes counterparty and third party broker quotes to determine the valuation of its derivative instruments. Fair values derived from counterparties and brokers are further verified using relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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

	Fair value as of December 31, 2008
	Level 1		Level 2		Level 3			Total
			(In thousands)
Assets (liabilities):
Money market funds	$	—	$	—	$	5,025		$	5,025
Commodity derivative contracts		—		—		39,357			39,357
Interest rate swap contracts		—		—		(985	)		(985	)
Total	$	—	$	—	$	43,397		$	43,397

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 $0.01 million at December 31, 2009.

The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy during the years ended December 31, 2009 and 2008. 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 December 31, 2009 and 2008.

18

	For the year ended December 31, 2009
	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(in thousands)
Balance at January 1, 2009	$	38,372		$	5,025		$	43,397
Total (gains) losses (realized or unrealized)
included in earnings		—			10			10
included in other comprehensive income		43,693			—			43,693
Purchases, issuances and settlements		(75,278	)		(3,000	)		(78,278	)
Transfers in and out of level 3		—			—			—
Balance at December 31, 2009	$	6,787		$	2,035		$	8,822
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 December 31, 2009	$	—		$	—		$	—

	For the year ended December 31, 2008
	Derivatives Asset (Liability)			Money Market Funds Asset (Liability)		Total
	(in thousands)
Balance at January 1, 2008	$	(10,792	)	$	—	$	(10,792	)
Total (gains) losses (realized or unrealized)
included in earnings		—			25		25
included in other comprehensive income		29,337			—		29,337
Purchases, issuances and settlements		19,827			5,000		24,827
Transfers in and out of level 3		—			—		—
Balance at December 31, 2008	$	38,372		$	5,025	$	43,397
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 December 31, 2008	$	—		$	—	$	—

(8) Accrued Liabilities

The Company’s accrued liabilities consist of the following:

	December 31,
	2009		2008
	(In thousands)
Accrued capital costs	$	18,200	$	26,555
Accrued payroll and employee incentive expense		7,137		5,721
Accrued lease operating expense		8,011		12,196
Asset retirement obligation		956		1,359
Other		2,803		2,993
Total	$	37,107	$	48,824

19

(9) Asset Retirement Obligation

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

	For the Year Ended December 31,
	2009			2008
	(In thousands)
ARO at the beginning of the period	$	27,944		$	22,670
Revision of previous estimate		(1,886	)		1,785
Liabilities incurred during period		1,855			1,727
Liabilities settled during period		(1,328	)		(363	)
Accretion expense		2,335			2,125
ARO at the end of the period	$	28,920		$	27,944

Of the total ARO, the current portion is approximately $1.0 million and $1.4 million at December 31, 2009 and 2008, respectively, and is included in Accrued liabilities on the Consolidated Balance Sheet. The long-term portion of ARO is approximately $27.9 million and $26.5 million at December 31, 2009 and 2008, respectively, and is included in Other long-term liabilities on the Consolidated Balance Sheet.

(10) Long-Term Debt

Long-term debt consists of the following:

	December 31,
	2009			2008
	(In thousands)
Amended and Restated Senior Revolving Credit Agreement	$	190,000		$	225,000
Amended and Restated Second Lien Term Loan		100,000			75,000
		290,000			300,000
Less:
Original issue discount on amended and restated second lien term loan		(1,258	)		—
Current portion of long-term debt		—			—
	$	288,742		$	300,000

Senior Secured Revolving Line of Credit. On April 9, 2009, the Company entered into the 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 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. At December 31, 2009, the Company’s current ratio was 4.3 and the leverage ratio was 1.6. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company was in compliance with all covenants at December 31, 2009. 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 December 31, 2009, the Company had $190.0 million outstanding with $160.0 million available for borrowing under the revolving line of credit. All amounts drawn under the Restated Revolver are due and payable on July 1, 2012. As of February 26, 2010, the Company had $190.0 million outstanding with $160.0 million available for borrowing under the revolving line of credit.

20

Second Lien Term Loan.On April 9, 2009, the Company also entered into the Restated Term Loan and extended 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%. In accordance with authoritative guidance for derivative instruments and hedging activities, the Company evaluated the LIBOR floor as an embedded derivative and concluded that because the terms are clearly and closely related to the debt instrument, it does not represent an embedded derivative that must be accounted for separately. The 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. At December 31, 2009, the Company’s asset coverage ratio was 2.7 and the leverage ratio was 1.6. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company was in compliance with all covenants at December 31, 2009. 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 December 31, 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. All amounts drawn under the Restated Term Loan are due and payable on October 2, 2012. The Company has the right to prepay the Restated Term Loan at any time on or after the first anniversary of the effective date (April 10, 2010), in whole or in part, from April 10, 2010 to April 10, 2011 with a premium equal to 2% of such amount prepaid or subsequent to April 10, 2011 without premium or penalty provided that each prepayment is in an amount that is an integral multiple of $1.0 million and not less than $1.0 million, or if such amount is less than $1.0 million, the outstanding principal amount. The Company may not prepay the Restated Term Loan prior to April 10, 2010. There were no additional borrowings under the Restated Term Loan subsequent to December 31, 2009 through the date of this Annual Report on Form 10-K.

Aggregate maturities of long-term debt at December 31, 2009 due in the next five years are $290.0 million due in 2012. At December 31, 2009, the Company’s weighted average borrowing rate was 6.24%.

(11) 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.

Lease Obligations and Other Commitments

The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of $4.3 million, $3.3 million and $2.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Future minimum annual rental commitments under non-cancelable leases at December 31, 2009 are as follows (In thousands):

2010	$	3,025
2011		3,103
2012		3,101
2013		3,130
2014		513
Thereafter		—
	$	12,872

The Company also has drilling rig commitments of $3.5 million for 2010.

(12) Stock-Based Compensation

Stock-based compensation expense recorded for all share-based payment arrangements for the years ended December 31, 2009, 2008 and 2007 was $7.5 million, $7.2 million and $6.8 million, respectively, with an associated tax benefit of $2.7 million, $2.9 million and $2.5 million, respectively. During 2009, the Company capitalized $0.4 million of stock-based compensation expense. The remaining unrecognized compensation expense associated with total unvested awards as of December 31, 2009 was approximately $7.0 million.

21

2005 Long-Term Incentive Plan

In July 2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan (the “Plan”) whereby stock is granted to employees, officers and directors of the Company. The Plan allows for the grant of stock options, stock awards, restricted stock, restricted stock units, stock appreciation rights, performance awards and other incentive awards. Employees, non-employee directors and other service providers of the Company and its affiliates who, in the opinion of the Compensation Committee or another Committee of the Board of Directors (the “Committee”), are in a position to make a significant contribution to the success of the Company and the Company’s affiliates are eligible to participate in the Plan. The Plan provides for administration by the Committee, which determines the type and size of award and sets the terms, conditions, restrictions and limitations applicable to the award within the confines of the Plan’s terms. The maximum number of shares available for grant under the Plan was increased from 3,000,000 shares to 4,950,000 shares by vote of the shareholders in 2008. The shares available for grant include these 4,950,000 shares plus any shares of common stock that become available under the Plan for any reason other than exercise, such as shares traded for the related tax liabilities of employees. The maximum number of shares of common stock available for grant of awards under the Plan to any one participant is (i) 300,000 shares during any fiscal year in which the participant begins work for Rosetta and (ii) 200,000 shares during each fiscal year thereafter.

Stock Options

The Company has granted stock options under its 2005 Long-Term Incentive Plan (the “Plan”). Options generally expire ten years from the date of grant. The exercise price of the options cannot be less than the fair market value per share of the Company’s common stock on the grant date. The majority of options generally vest over a three year period.

The weighted average fair value at date of grant for options granted during the years ended December 31, 2009, 2008 and 2007 was $3.42 per share, $9.19 per share, and $9.51 per share, respectively. The fair value of options granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

	Year Ended December 31,
	2009	2008	2007
Expected option term (years)	6.5	6.5	6.5
Expected volatility	42.45% - 56.95%	42.45%	42.45%
Expected dividend rate	0.00%	0.00%	0.00%
Risk free interest rate	2.42% - 3.19%	3.48% - 3.84%	4.36% - 5.00%

The Company has assumed an annual forfeiture rate of 13% for the options granted in 2009 based on the Company’s history for this type of award to various employee groups, compared to an annual forfeiture rate of 11% for options granted in 2008. Compensation expense is recognized ratably over the requisite service period.

The following table summarizes information related to outstanding and exercisable options held by the Company’s employees and directors at December 31, 2009:

	Shares		Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (In years)	Aggregate Intrinsic Value (In thousands)
Outstanding at December 31, 2007	972,600		$	17.45
Granted	209,375			19.13
Exercised	(214,119	)		16.89
Forfeited	(26,100	)		17.57
Outstanding at December 31, 2008	941,756		$	17.94
Granted	384,514			7.56
Exercised	(14,125	)		16.16
Forfeited	(64,176	)		17.16
Outstanding at December 31, 2009	1,247,969		$	14.80
Options vested and exercisable at December 31, 2009	718,548		$	17.94	5.25	$	1,797

Stock-based compensation expense recorded for stock option awards for the years ended December 31, 2009, 2008 and 2007 was $1.1 million, $1.7 million and $3.9 million, respectively. Unrecognized expense as of December 31, 2009 for all outstanding stock options is $1.0 million and will be recognized over a weighted average period of 1.64 years.

22

The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 is $0.1 million, $1.4 million and $0.2 million, respectively.

Restricted Stock

The Company has granted restricted stock under its 2005 Long-Term Incentive Plan. The majority of restricted stock vests over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The Company also assumes an annual forfeiture rate of 13% for these awards based on the Company’s history for this type of award to various employee groups.

The following table summarizes information related to restricted stock held by the Company’s employees and directors at December 31, 2009:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2007	455,425		$	18.50
Granted	607,079			20.06
Vested	(274,714	)		18.31
Forfeited	(70,351	)		19.54
Non-vested shares outstanding at December 31, 2008	717,439		$	19.78
Granted	670,673			7.25
Vested	(209,103	)		19.34
Forfeited	(54,351	)		16.48
Non-vested shares outstanding at December 31, 2009	1,124,658		$	12.55

The non-vested restricted stock outstanding at December 31, 2009 generally vests at a rate of 25% on the first anniversary of the date of grant, 25% on the second anniversary and 50% on the third anniversary. The fair value of awards vested for the year ended December 31, 2009 was $1.8 million.

Stock-based compensation expense recorded for restricted stock awards for the years ended December 31, 2009, 2008 and 2007 was $5.1 million, $5.5 million and $2.9 million, respectively. Unrecognized expense as of December 31, 2009 for all outstanding restricted stock awards is $6.0 million and will be recognized over a weighted average period of 1.70 years.

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 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 and are included as a component of other long-term liabilities. 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.

As discussed in Note 2, compensation expense associated with PSUs is 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 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 measured at the end of each reporting period based on the fair value derived from the Monte Carlo model.

At December 31, 2009, one-third of the PSUs granted to executive employees include various market-based components requiring complex modeling to value the grant and these grants vest at the end of a three-year performance period based on the comparative performance of the Company’s change in cash flow multiple (share price divided by trailing twelve months cash flow per share) against the change in cash flow multiple of the Index. The Company uses a Monte Carlo model which incorporates a

23

risk-neutral valuation approach to value these awards. This model samples paths of the Company’s and the Index’s stock price and calculates the resulting change in cash flow multiple at the end of the forecasted performance period. This model iterates these randomly forecasted results until the distribution of results converge on a mean or estimated fair value. The five primary inputs for the Monte Carlo model are the risk-free rate, independent analyst cash flow per share estimates for the Company and the Index, volatility of the equities of the Company and the Index, expected dividends, where applicable, and various historical market data. The risk-free rate was generated from Bloomberg for United States Treasuries with a two-year tenor. Volatility was set equal to the annualized daily volatility measured over a historic 400-day period ending on the reporting date for the Company and the Index. No forfeiture rate is assumed for this type of award. Expense related to these awards can be volatile based on the Company’s comparative performance at the end of each quarter.

The following assumptions were used as of December 31, 2009 for the Monte Carlo model to value the expense and liability components of the awards that contain market conditions:

	December 31, 2009
Expected term of award (years)	3
Risk-free interest rate	1.28	%
Rosetta volatility	79.43	%
Index volatility	79.40	%
Rosetta/Index correlation	82	%

The following table summarizes information related to PSUs held by the Company’s officers at December 31, 2009:

	Units
Unvested PSUs at December 31, 2008	—
Granted	355,848
Vested	—
Forfeited	(10,318	)
Unvested PSUs at December 31, 2009	345,530

The fair value per unit at December 31, 2009 was $19.92 for awards with performance conditions and $19.70 for awards with market conditions. As of December 31, 2009, the Company recognized $1.3 million of compensation expense and long-term liability associated with the PSUs. At the current fair value and assuming that the Board elects 100% pay-out for the PSUs for all metrics, total compensation expense related to the PSUs to be recognized ratably over the 3-year service period would be $6.9 million at December 31, 2009. The total compensation expense will be measured and adjusted quarterly until settlement based on the quarter-end closing common stock prices and the Monte Carlo model valuations.

(13) Income Taxes

The Company’s income tax expense (benefit) consists of the following:

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Current:
Federal	$	(1,611	)	$	2,304		$	—
State		416			1,388			115
		(1,195	)		3,692			115
Deferred:
Federal		(119,111	)		(107,568	)		31,979
State		(5,521	)		(8,951	)		1,938
		(124,632	)		(116,519	)		33,917
Total income tax expense (benefit) (1)	$	(125,827	)	$	(112,827	)	$	34,032

(1) Interest and penalties are classified as a component of tax expense in the Consolidated Statement of Operations.

24

The differences between income taxes computed using the statutory federal income tax rate and that shown in the statement of operations are summarized as follows:

		Year Ended December 31,
		2009					2008					2007
		(In thousands)			(%)		(In thousands)			(%)		(In thousands)		(%)
US Statutory Rate		$	(120,751	)	35.0	%	$	(105,327	)	35.0	%	$	31,933	35.0	%
Income/franchise tax, net of federal benefit	��		(5,545	)	1.6	%		(7,562	)	2.5	%		2,053	2.3	%
Permanent differences and other			469		(0.1	)%		62		0.0	%		46	0.0	%
Total tax expense (benefit)		$	(125,827	)	36.5	%	$	(112,827	)	37.5	%	$	34,032	37.3	%

The effective tax rate in all periods is the result of the earnings in various domestic tax jurisdictions that apply a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate due primarily to state taxes. Future effective tax rates could be adversely affected if unfavorable changes in tax laws and regulations occur, or if the Company experiences future adverse determinations by taxing authorities.

The components of deferred taxes are as follows:

	December 31,
	2009			2008
	(In thousands)
Deferred tax assets
Oil and gas properties basis differences	$	130,562		$	39,089
Alternative Minimum Tax credit		693			2,443
Accrued liabilities not currently deductible		6,501			2,603
Hedge activity		730			—
Net operating loss carryforward		31,429			621
Other		(183	)		1,158
Total deferred tax assets		169,732			45,914
Hedge activity		(3,258	)		(14,294	)
Other		—			(1,543	)
Total gross deferred tax liabilities		(3,258	)		(15,837	)
Net deferred tax assets	$	166,474		$	30,077

The Company had a deferred tax asset related to federal and state net operating loss carryforwards of approximately $31.4 million and $9.7 million at December 31, 2009 and 2008, respectively. The federal net operating loss carryforward will begin to expire in 2025. Additionally, the Company had a deferred tax asset related to oil and gas properties basis of $130.8 million and $39.1 million at December 31, 2009 and 2008, respectively. Realization of the deferred tax assets is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. There is no valuation allowance recorded on deferred tax assets as the Company believes it is more likely than not that the asset will be utilized.

As of December 31, 2009, the Company is not aware of any uncertain tax positions requiring adjustments to its tax liability. If applicable, the Company will record to the income tax provision any interest and penalties related to unrecognized tax positions.

The Company files income tax returns in the U.S. and in various state jurisdictions. With few exceptions, the Company is subject to US federal, state and local income tax examinations by tax authorities for tax periods 2005 and forward.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

25

(14) Earnings Per Share

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

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

	Year Ended December 31,
	2009	2008	2007
	(In thousands)
Basic weighted average number of shares outstanding	50,979	50,693	50,379
Dilution effect of stock option and awards at the end of the period (1)	—	—	210
Diluted weighted average number of shares outstanding	50,979	50,693	50,589
Anti-dilutive stock options and awards	1,364	592	385

(1) Because the Company recognized a net loss for the years ended December 31, 2009 and 2008, no unvested stock awards and options were included in computing earnings per share because the effect was anti-dilutive. In computing earnings per share, no adjustments were made to reported net income (loss).

(15) Operating Segments

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

Geographic Area Information

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

	Year Ended December 31,
	2009 (1)		2008 (1)		2007 (1)
Natural gas, oil and NGL Revenue	(In thousands)
California	$	65,295	$	141,569	$	110,607
Rockies		21,999		29,491		10,676
South Texas		90,043		204,791		143,886
Texas State Waters		10,465		49,745		8,789
Other Onshore		17,742		44,809		25,905
Gulf of Mexico		11,840		47,611		40,700
	$	217,384	$	518,016	$	340,563

	December 31,
	2009		2008
Oil and Natural Gas Properties and Other Fixed Assets	(In thousands)
California	$	624,765	$	619,593
Rockies		202,502		175,294
South Texas		791,934		712,464
Texas State Waters		70,667		65,085
Other Onshore		186,912		171,855
Gulf of Mexico		153,653		156,381
Other		12,417		9,439
	$	2,042,850	$	1,910,111

(1) Excludes the effects of hedging gains of $76.6 million for the year ended December 31, 2009, hedging losses of $18.7 million for the year ended December 31, 2008 and hedging gains of $22.9 million for the year ended December 31, 2007.

26

Major Customers

For the year ended December 31, 2009, the Company had one major customer, CES, which accounted for approximately 57% of the Company’s consolidated annual revenue. The Company’s annual consolidated revenue from CES accounted for approximately 61% and 55% for the years ended December 31, 2008 and 2007, respectively, and is reflected in oil and natural gas sales. For the years ended December 31, 2009, 2008 and 2007, revenues from sales to CES were $117.8 million, $305.9 million, and $201.4 million, respectively. There was no receivable from CES at December 31, 2009 or 2008. Under the gas purchase and sale contract, CES is required to collateralize payments under the contract by daily margin payments into the Company’s collateral account, which are then settled at the end of the month. At December 31, 2009 and 2008, the Company had $7.5 million and $19.4 million in the margin account for December sales to CES which is included in Prepayment on gas sales on the Consolidated Balance Sheet.

(16) Subsequent Events

On January 26, 2010, the Company entered into a purchase and sale agreement with St. Mary Land & Exploration Company to purchase the remaining 30% working interest and obtain operatorship in the Catarina Field for approximately $5.9 million, subject to any applicable purchase price adjustments. The purchase is effective as of January 1, 2010 and closing shall occur on or before March 4, 2010, but no later than May 1, 2010.

In January 2010, the Company entered into additional costless collar transactions to hedge 10,000 MMBtu/d of its expected production for July 2010 through December 2012. The costless collars have a floor price of $5.75 per MMBtu and a ceiling price of $6.50 per MMBtu through 2011 and $7.15 per MMBtu in 2012. In February 2010, the Company entered into natural gas fixed-price swaps to hedge 10,000 MMBtu/d of its expected production for July 2010 through December 2011 at an average price of $5.91 per MMBtu.

(17) Guarantor Subsidiaries

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

27