Rosetta Resources 8-K Index to Financial Statements

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, 2008 and 2007	2
Consolidated Statement of Operations for the years ended December 31, 2008, 2007 and 2006	3
Consolidated Statement of Cash Flows for the years ended December 31, 2008, 2007 and 2006	4
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006	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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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, 2008, 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 appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our audits (which were integrated audits in 2008 and 2007). 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.

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 27, 2009, except for Note 17 to the consolidated financial statements, as to which the date is May 13, 2009.

Item 8. Financial Statements and Supplementary Data

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except share amounts)

	December 31,
	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	42,855		$	3,216
Restricted cash		1,421			—
Accounts receivable		41,885			55,048
Derivative instruments		34,742			3,966
Prepaid expenses		5,046			10,413
Other current assets		4,071			4,249
Total current assets		130,020			76,892
Oil and natural gas properties, full cost method, of which $50.3 million at December 31, 2008 and $40.9 million at December 31, 2007 were excluded from amortization		1,900,672			1,566,082
Other property and equipment		9,439			6,393
		1,910,111			1,572,475
Accumulated depreciation, depletion, and amortization, including impairment		(935,851	)		(295,749	)
Total property and equipment, net		974,260			1,276,726
Deferred loan fees		1,168			2,195
Deferred tax asset		42,652			—
Other assets		6,278			1,401
Total other assets		50,098			3,596
Total assets	$	1,154,378		$	1,357,214
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	2,268		$	33,949
Accrued liabilities		48,824			64,216
Royalties payable		17,388			18,486
Derivative instruments		985			2,032
Prepayment on gas sales		19,382			20,392
Deferred income taxes		12,575			720
Total current liabilities		101,422			139,795
Long-term liabilities:
Derivative instruments		—			13,508
Long-term debt		300,000			245,000
Asset retirement obligation		26,584			18,040
Deferred income taxes		—			67,916
Total liabilities		428,006			484,259
Commitments and Contingencies (Note 11)
Stockholders’ equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2008 or 2007		—			—
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 51,031,481 shares and 50,542,648 shares at December 31, 2008 and December 31, 2007, respectively		51			50
Additional paid-in capital		773,676			762,827
Treasury stock, at cost; 155,790 shares and 109,303 shares at December 31, 2008 and 2007, respectively		(2,672	)		(2,045	)
Accumulated other comprehensive income (loss)		24,079			(7,225	)
Retained earnings (accumulated deficit)		(68,762	)		119,348
Total stockholders’ equity		726,372			872,955
Total liabilities and stockholders’ equity	$	1,154,378		$	1,357,214

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

Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

	Year Ended December 31,
	2008			2007			2006
Revenues:
Natural gas sales	$	443,611		$	323,341		$	236,496
Oil sales		55,736			40,148			35,267
Total revenues		499,347			363,489			271,763
Operating costs and expenses:
Lease operating expense		55,694			47,044			36,273
Depreciation, depletion, and amortization		198,862			152,882			105,886
Impairment of oil and gas properties		444,369			—			—
Treating and transportation		6,323			4,230			2,544
Marketing fees		3,064			2,450			2,257
Production taxes		13,528			6,417			6,433
General and administrative costs		52,846			43,867			33,233
Total operating costs and expenses		774,686			256,890			186,626
Operating income (loss)		(275,339	)		106,599			85,137
Other (income) expense
Interest expense, net of interest capitalized		14,688			17,734			17,428
Interest income		(1,600	)		(1,674	)		(4,503	)
Other (income) expense, net		12,510			(698	)		(40	)
Total other expense		25,598			15,362			12,885
Income (loss) before provision for income taxes		(300,937	)		91,237			72,252
Income tax expense (benefit)		(112,827	)		34,032			27,644
Net income (loss)	$	(188,110	)	$	57,205		$	44,608
Earnings (loss) per share:
Basic	$	(3.71	)	$	1.14		$	0.89
Diluted	$	(3.71	)	$	1.13		$	0.88
Weighted average shares outstanding:
Basic		50,693			50,379			50,237
Diluted		50,693			50,589			50,408

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

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities
Net income (loss)		(188,110	)		57,205			44,608
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		198,862			152,882			105,886
Impairment of oil and gas properties		444,369			—			—
Deferred income taxes		(116,519	)		33,915			27,472
Amortization of deferred loan fees recorded as interest expense		1,027			1,180			1,180
Stock compensation expense		7,234			6,831			5,702
Other non-cash items		(512	)		(181	)		(171	)
Change in operating assets and liabilities:
Accounts receivable		13,163			(18,640	)		3,643
Income taxes receivable		(776	)		—			6,000
Prepaid expenses		5,367			(1,652	)		650
Other current assets		178			(1,284	)		(2,965	)
Other assets		191			144			1,691
Accounts payable		5,031			10,909			8,765
Accrued liabilities		7,322			3,998			310
Royalties payable		(2,108	)		12,000			(3,161	)
Net cash provided by operating activities		374,719			257,307			199,610
Cash flows from investing activities
Acquisition of oil and gas properties		(163,187	)		(38,656	)		(35,286	)
Purchases of oil and gas assets		(228,464	)		(284,541	)		(201,293	)
Increase in restricted cash		(1,421	)		—			—
Other		2			1,156			515
Net cash used in investing activities		(393,070	)		(322,041	)		(236,064	)
Cash flows from financing activities
Equity offering transaction fees		—			—			268
Borrowings on revolving credit facility		55,000			10,000			—
Payments on revolving credit facility		—			(5,000	)		—
Proceeds from stock options exercised		3,617			653			804
Purchases of treasury stock		(627	)		(483	)		(1,562	)
Net cash provided by (used in) financing activities		57,990			5,170			(490	)
Net increase (decrease) in cash		39,639			(59,564	)		(36,944	)
Cash and cash equivalents, beginning of year		3,216			62,780			99,724
Cash and cash equivalents, end of year	$	42,855		$	3,216		$	62,780
Supplemental disclosures:
Cash paid for interest expense, net of capitalized interest	$	13,658		$	18,862		$	17,875
Cash paid for income taxes	$	4,470		$	115		$	172
Supplemental non-cash disclosures:
Capital expenditures included in Accrued liabilities	$	26,555		$	34,599		$	21,674
Accrued purchase price adjustment	$	—		$	—		$	11,400
Release of suspended net revenues 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.

Rosetta Resources Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands, except share amounts)

	Common Stock			Additional Paid-In Capital		Treasury Stock				Accumulated Other Comprehensive (Loss)/Income			Retained Earnings / (Accumulated Deficit)			Total Stockholders’ Equity
	Shares	Amount				Shares	Amount
Balance December 31, 2005	50,003,500	$	50	$	748,569	—	$	—		$	(50,731	)	$	17,535		$	715,423
Equity offering - transaction fees	—		—		268	—		—			—			—			268
Stock options exercised	49,896		—		804	—		—			—			—			804
Treasury stock - employee tax payment	—		—		—	85,788		(1,562	)		—			—			(1,562	)
Stock-based compensation	—		—		5,702	—		—			—			—			5,702
Vesting of restricted stock	352,398		—		—	—		—			—			—			—
Comprehensive Income:
Net Income	—		—		—	—		—			—			44,608			44,608
Change in fair value of derivative hedging instruments	—		—		—	—		—			121,540			—			121,540
Hedge settlements reclassified to income	—		—		—	—		—			(29,578	)		—			(29,578	)
Tax expense related to cash flow hedges	—		—		—	—		—			(34,916	)		—			(34,916	)
Comprehensive Income	—		—		—	—		—			—			—			101,654
Balance 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 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	—		—		—	—		—			30,059			—			30,057
Hedge settlements reclassified to income	—		—		—	—		—			19,827			—			19,829
Tax expense related to cash flow hedges	—		—		—	—		—			(18,582	)		—			(18,582	)
Comprehensive Loss	—		—		—	—		—			—			—			(156,806	)
Balance December 31, 2008	51,031,481	$	51	$	773,676	155,790	$	(2,672	)	$	24,079		$	(68,762	)	$	726,372

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

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.

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

Principles of Consolidation and Basis of Presentation

The accompanying consolidated financial statements for the years ended December 31, 2008, 2007 and 2006 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.

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 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 followed this policy prior to the recent changes in credit markets, and believes this is an appropriate approach for the investment of Company funds in the current environment.

Restricted Cash

Restricted cash of $1.4 million as of December 31, 2008 consists 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 $7.1 million and $5.5 million of internal costs for the years ended December 31, 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 such 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 SFAS No. 143, and estimated future income taxes thereon. However, in periods in which a write-down is required, if oil and gas prices increase subsequent to the end of a quarter but prior to the issuance of our financial statements, the Company may not be subject to a write-down. If the net capitalized costs of oil and natural gas properties exceed the cost center ceiling, the Company is subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, it would reduce earnings and impact shareholders’ equity in the period of occurrence and result in a lower depreciation, depletion and amortization expense in the future.

The Company’s ceiling test computation was calculated quarterly using hedge adjusted market prices based on Henry Hub gas prices and West Texas Intermediate oil prices. At September 30, 2008, the ceiling test computation was based on a Henry Hub price of $7.12 per MMBtu and a West Texas Intermediate oil price of $96.37 per Bbl (adjusted for basis and quality differentials). At December 31, 2008, the ceiling test computation was based on a Henry Hub price of $5.71 per MMBtu and a West Texas Intermediate oil price of $41.00 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at September 30 and December 31, 2008 increased the calculated ceiling value by approximately $37 million (pre-tax) and $47 million (pre-tax), respectively. Based upon studies to date, and in coordination with the Company’s independent reserve engineers, the Company recognized a downward revision of 64 Bcfe of proved reserves during the third quarter of 2008. Based upon this analysis and the reserve revision, a non-cash, pre-tax write-down of $205.7 million was recorded 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 a non-cash, pre-tax write-down of $238.7 million. Due to the volatility of commodity prices, should natural gas prices continue to decline in the future, it is possible that an additional write-down could occur.

No impairment charge was recorded for the years ended December 31, 2007 and 2006.

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.

Capitalized Interest

The Company capitalizes interest on capital invested in projects related to unevaluated properties and significant development projects in accordance with SFAS No. 34, “Capitalization of Interest Cost,” (“SFAS No. 34”). 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, accounts payable, and other payables approximate their respective fair market values due to their short maturities. Derivatives are also recorded on the balance sheet at fair market

value. The carrying amount reported in the consolidated balance sheet at December 31, 2008 for long-term debt is $300 million. The Company adjusted the fair value measurement of its long-term debt as of December 31, 2008, in accordance with SFAS No. 157 using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. The Company has determined the fair market value of its debt to be $275 million at December 31, 2008.

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.

Deferred Loan Fees

Deferred 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 transaction. The Company’s derivatives consist of cash flow hedge transactions 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. 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 that it is probable that a hedged forecasted transaction will not 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 Note 6 – Commodity Hedging Contracts and Other Derivatives for a description of the derivative contracts which the Company executes.

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 SFAS No. 143, “Accounting for Asset Retirement Obligations”. This standard 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.

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, 2008 or 2007.

Stock-Based Compensation

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payments” (“SFAS No. 123R”). This statement applies to all awards granted, modified, repurchased or cancelled after January 1, 2006 and to the unvested portion of all awards granted prior to that date. The Company adopted this statement using the modified version of the prospective application (modified prospective application). Under the modified prospective application, compensation cost for the portion of awards for which the employee’s requisite service has not been rendered that are outstanding as of January 1, 2006 must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of awards shall be based on the original fair market value of those awards on the date of grant as calculated for recognition under SFAS No. 123, “Accounting for Stock-Based Compensation” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” (“SFAS No. 123”). The compensation cost for these earlier awards shall be attributed to periods beginning on or after January 1, 2006 using the attribution method that was used under SFAS No. 123.

Any excess tax benefit is recognized as a credit to additional paid in capital when realized and is calculated as the amount by which the tax deduction we receive exceeds the deferred tax asset associated with the recorded stock compensation expense. We have approximately $0.2 million of related excess tax benefits which will be recognized upon utilization of our net operating loss carryforward.��SFAS No. 123R 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, 2008 and 2007, there were no shares 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, 2008 and 2007, imbalances were insignificant.

Since there is a ready market for natural gas, crude oil and natural gas liquids (“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, natural gas liquids 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.

It is the Company’s policy to calculate and pay 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 bases of assets and liabilities using the liability method in accordance with the provisions set forth in SFAS

No. 109, “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.

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”) requires that we 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 may impact the Company in future periods.

Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141R”). SFAS No. 141R broadens the guidance of SFAS No. 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. SFAS No. 141R also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases. This could cause us to expense transaction costs for future oil and gas property purchases that we have historically capitalized. Additionally, SFAS No. 141R expands the required disclosures to improve the statement users’ abilities to evaluate the nature and financial effects of business combinations. SFAS No. 141R is effective for business combinations for which the acquisition date is on or after January 1, 2009.

Noncontrolling Interests in Consolidated Financial Statements. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No. 160”), which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of SFAS No. 160 to have a material 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 SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (“SFAS No. 161”), which is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures. This statement is effective for fiscal years beginning after November 15, 2008. We do not expect the adoption of SFAS No. 161 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Fair Value Measurements. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP FAS 157-3”). This FSP clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. This FSP was effective upon issuance, including prior periods for which financial statements have not been issued. We applied this FSP to financial assets measured at fair value on a recurring basis at September 30, 2008. See Note 7 - Fair Value Measurements. The adoption of FSP FAS 157-3 did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Oil and Gas Reporting Requirements. In December 2008, the SEC released Release No. 33-8995, “Modernization of Oil and Gas Reporting” (the “Release”). The disclosure requirements under this Release will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in 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 ended December 31, 2009. We are currently evaluating the impact of this Release on our oil and gas accounting disclosures.

(3) Accounts Receivable

Accounts receivable consisted of the following:

	December 31,
	2008		2007
	(In thousands)
Natural gas, NGLs and oil revenue sales	$	37,982	$	46,376
Joint interest billings		3,422		7,750
Short-term receivable for royalty recoupment		481		922
Total		41,885		55,048

There are no balances in accounts receivable that will not be collected and that an allowance was unnecessary at December 31, 2008 and December 31, 2007.

(4) Property, Plant and Equipment

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

	December 31,
	2008			2007
	(In thousands)
Proved properties	$	1,813,527		$	1,499,046
Unproved/unevaluated properties		50,252			40,903
Gas gathering system and compressor stations		36,893			26,133
Other		9,439			6,393
Total		1,910,111			1,572,475
Less: Accumulated depreciation, depletion, and amortization		(935,851	)		(295,749	)
	$	974,260		$	1,276,726

Included in the Company’s oil and natural gas properties are asset retirement costs of $23.2 million and $20.1 million at December 31, 2008 and 2007, respectively, including additions of $1.7 million and $2.1 million for the year ended December 31, 2008 and 2007, respectively.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center. The Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at September 30 and December 31, 2008, which were based on a Henry Hub price of $7.12 per MMBtu and $5.71 per MMBtu, respectively, and a West Texas Intermediate oil price of $96.37 per Bbl and $41.00 per Bbl (adjusted for basis and quality differentials), respectively. Cash flow hedges of natural gas production in place at September 30 and December 31, 2008 increased the calculated ceiling value by approximately $37 million (pre-tax) and $47 million (pre-tax), respectively. Based upon studies to date, and in coordination with the Company’s independent reserve engineers, the Company recognized a downward revision of 64 Bcfe of proved reserves during the third quarter of 2008. Based upon this analysis and the reserve revision, a non-cash, pre-tax write-down of $205.7 million was recorded 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 a non-cash, pre-tax write-down of $238.7 million. It is possible that another write-down of the Company’s oil and gas properties could occur in the future should oil and natural gas prices continue to decline and/or the Company experiences downward adjustments to the estimated proved reserves.

Capitalized costs excluded from depreciation, depletion, and amortization as of December 31, 2008 and 2007, are as follows by the year in which such costs were incurred:

	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	—
	50,252	42,811	5,382	2,028	31
	December 31, 2007
	Total	2007	2006	2005
	(in thousands)
Onshore:
Development cost	591	591	—	—
Exploration cost	5,650	5,650	—	—
Acquisition cost of undeveloped acreage	24,995	9,023	7,568	8,404
Capitalized Interest	3,061	2,026	999	36
	34,297	17,290	8,567	8,440
Offshore:
Development cost	—	—	—	—
Exploration cost	—	—	—	—
Acquisition cost of undeveloped acreage	6,069	209	5,860	—
Capitalized Interest	537	381	150	6
	6,606	590	6,010	6
	40,903	17,880	14,577	8,446

It is anticipated that the acquisition of undeveloped acreage and associated capitalized interest of $33.4 million and development and exploration costs of $16.9 million will be included in oil and gas properties subject to amortization within five years and one year, respectively.

Property Acquisitions. 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 from Pinedale Energy, LLC and CEU W&D, LLC and W&D Gas Partners, LLC, respectively.

During the second quarter of 2008, the Company acquired a 50% working interest position in approximately 12,000 gross acres in the Rockies from North American Petroleum Corporation USA, a subsidiary of Petroflow Energy Ltd. for $29.0 million.

During the second quarter of 2007, the Company acquired properties located in the Sacramento Basin from Output Exploration, LLC and OPEX Energy, LLC at a total purchase price of $38.7 million.

During the fourth quarter of 2006, the Company acquired a 50% working interest in Main Pass 29 in the Gulf of Mexico from Andex/Wolf for $16.7 million and a 25% working interest in Grand Isle 72 in the Gulf of Mexico from Contango Oil and Gas for $7.0 million.

In April 2006, the Company also acquired certain oil and gas producing non-operated properties located in Duval, Zapata, and Jim Hogg Counties, Texas and Escambia County in Alabama from Contango Oil and Gas for $11.6 million in cash.

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 $39.8 million and $26.1 million at December 31, 2008 and 2007, 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, 2008 and 2007 was $5.3 million and $3.0 million, respectively. The depreciation expense associated with the gas gathering system and compressor stations for the years ended December 31, 2008, 2007 and 2006 was $2.2 million, $1.5 million, and $1.0 million, respectively.

Other Property and Equipment. Other property and equipment at December 31, 2008 and 2007 of $9.4 million and $6.4 million, respectively, consists primarily of furniture and fixtures. The accumulated depreciation associated with other assets at December 31, 2008 and 2007 was $2.6 million and $1.4 million, respectively. For the years ended December 31, 2008, 2007 and 2006 depreciation expense for other property and equipment was $1.2 million, $0.8 million, and $0.5 million, respectively.

(5) Deferred Loan Fees

At December 31, 2008 and 2007, deferred loan fees were $1.2 million and $2.2 million, respectively. Total amortization expense for deferred loan fees was $1.0 million, $1.2 million and $1.2 million for the years ended December 31, 2008, 2007 and 2006, 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, 2008:

Settlement Period	Derivative Instrument	Hedge Strategy	Notional Daily Volume MMBtu	Total of Notional Volume MMBtu	Average Floor/ Fixed Prices MMBtu		Average Ceiling Prices MMBtu		Natural Gas Production Hedged (1)		Fair Market Value Gain/ (Loss) (In thousands)
2009	Swap	Cash flow	52,141	19,031,465	$	7.65	$	—	37	%	$	31,082
2009	Costless Collar	Cash flow	5,000	1,825,000		8.00		10.05	4	%		3,660
2010	Swap	Cash flow	10,000	3,650,000		8.31		—	9	%		4,615
				24,506,465							$	39,357

(1) Estimated based on anticipated future gas production.

The Company has hedged the interest rates on $50.0 million of its outstanding debt through June 2009. As of December 31, 2008, the Company had the following financial interest rate swap positions outstanding:

Settlement Period	Derivative Instrument	Hedge Strategy	Average Fixed Rate		Fair Market Value Gain/ (Loss) (In thousands)
2009	Swap	Cash flow	4.55	%	$	(985	)
					$	(985	)

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, 2008, 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,
	2008			2007
Natural Gas
Quantity settled (MMBtu)		26,684,616			23,464,500
Increase (decrease) in natural gas sales revenue (In thousands)	$	(18,669	)	$	22,926
Interest Rate Swaps
Decrease (increase) in interest expense (In thousands)	$	(1,158	)	$	20

The Company expects to reclassify gains of $33.8 million based on market pricing as of December 31, 2008 to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.

At December 2008, the Company had derivative assets of $39.4 million, of which $4.6 million is included in other assets on the Consolidated Balance Sheet. The Company also had derivative liabilities of $0.9 million included in current liabilities on the Consolidated Balance Sheet at December 31, 2008.

(7) Fair Value Measurements

The Company partially adopted Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“SFAS No. 157”) effective January 1, 2008. As defined in SFAS No. 157, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

• 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, 2008. The Company utilizes counterparty and third party broker quotes to determine the valuation of its derivative instruments. Fair values derived from counterparties and brokers are further verified using the closing price as of December 31, 2008 for the relevant NYMEX futures contracts and Intercontinental 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, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	At fair value as of December 31, 2008 (In thousands)
	Level 1	Level 2	Level 3		Total
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 required under SFAS No. 157. These factors include

the credit standing of the counterparties involved, the impact of credit enhancements and the impact of the Company’s nonperformance risk on its liabilities. The Company considered credit adjustments for the counterparties using current credit default swap values and default probabilities for each counterparty in determining fair value.

The table below presents a reconciliation for the assets and liabilities classified as Level 3 in the fair value hierarchy during 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, 2008.

	Derivatives Asset (Liability)			Investments		Total
	(In thousands)
Balance as of 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 as of 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,
	2008		2007
	(In thousands)
Accrued capital costs	$	26,555	$	34,599
Accrued purchase price adjustments		—		11,400
Accrued payroll and employee incentive expense		5,721		5,361
Accrued lease operating expense		12,196		4,930
Asset retirement obligation		1,359		4,629
Other		2,993		3,297
Total	$	48,824	$	64,216

(9) Asset Retirement Obligation

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

	For the Year Ended December 31,
	2008			2007
	(In thousands)
ARO as of the beginning of the period	$	22,670		$	10,689
Revision of previous estimate		1,785			9,751
Liabilities incurred during period		1,727			2,105
Liabilities settled during period		(363	)		(1,355	)
Accretion expense		2,125			1,480
ARO as of the end of the period	$	27,944		$	22,670

Of the total ARO, approximately $1.4 million and $4.6 million are included in accrued liabilities on the Consolidated Balance Sheet at December 31, 2008 and 2007, respectively.

(10) Long-Term Debt

Long-term debt consists of the following:

	December 31,
	2008		2007
	(In thousands)
Senior secured revolving line of credit	$	225,000	$	170,000
Second lien term loan		75,000		75,000
		300,000		245,000
Less: current portion of long-term debt		—		—
	$	300,000	$	245,000

Senior Secured Revolving Line of Credit. BNP Paribas, in July 2005, provided the Company with a senior secured revolving line of credit concurrent with the acquisition in the amount of up to $400.0 million (“Revolver”). This Revolver was syndicated to a group of lenders on September 27, 2005. Availability under the Revolver is restricted to the borrowing base. The borrowing base is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements. In June 2008, the borrowing base was adjusted to $400.0 million and affirmed in December 2008. The next borrowing base review is scheduled to begin on March 2, 2009. Initial amounts outstanding under the Revolver bore interest, as amended, at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%. These rates over LIBOR were adjusted in June 2008 to be 1.125% to 1.875%. Such margins will fluctuate based on the utilization of the facility. Borrowings under the 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 pretax SEC PV-10 reserve value, a guaranty by all of the Company’s domestic subsidiaries, a pledge of 100% of the membership interests of domestic subsidiaries and a lien on cash securing the Calpine gas purchase and sale contract. 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 with the pro forma effect of acquisitions and divestitures. At December 31, 2008, the Company’s current ratio was 2.7 and the leverage ratio was 0.8. In addition, the Company is subject to covenants 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, 2008. As of December 31, 2008, the Company had $175.0 million available for borrowing under their revolving line of credit. All amounts drawn under the Revolver are due and payable on April 5, 2010.

Second Lien Term Loan.BNP Paribas, in July 2005, also provided the Company with a second lien term loan concurrent with the acquisition of oil and gas properties from Calpine (“Term Loan”). Borrowings under the Term Loan are $75.0 million as of December 31, 2008. Such borrowings are syndicated to a group of lenders including BNP Paribas. Borrowings under the Term Loan bear interest at LIBOR plus 4.00%. 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 with the pro forma effect of acquisitions and divestitures. At December 31, 2008, the Company’s asset coverage ratio was 3.1 and the leverage ratio was 0.8. In addition, the Company is subject to covenants 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, 2008. The principal balance of the Term Loan is due and payable on July 7, 2010.

The Company’s ability to raise capital depends on the current state of the financial markets, which are subject to general and economic and industry conditions. Therefore, the availability of and price of capital in the financial markets could negatively affect the Company’s liquidity position. The Company has already begun the process of extending the maturity of its revolving credit facility and second lien term loan. If the Company is unable to extend the maturity of the revolving credit facility, it will become a current liability on April 5, 2009 and would result in the Company being in default with respect to the working capital covenants in the revolving credit facility and second lien term loan. The Company believes that it will be successful in extending this maturity on acceptable terms and conditions. Similarly, if the Company is unable to extend the maturity of the second lien term loan, it will become a current liability on July 7, 2009. Current market conditions could result in increased costs of borrowing.

Aggregate maturities of long-term debt at December 31, 2008 due in the next five years are $300 million in 2010.

(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.

Calpine Settlement

On December 20, 2005, Calpine Corporation and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the Bankruptcy Court. Two years later, on December 19, 2007, the Bankruptcy Court confirmed a plan of reorganization for Calpine, which emerged from bankruptcy on January 31, 2008. During that period, on June 29, 2007, Calpine commenced the Lawsuit. Over the next fourteen months, the Company vigorously disputed Calpine’s contentions in the Lawsuit, including any and all allegations that it underpaid for Calpine’s oil and gas business.

On October 22, 2008, Calpine and the Company announced that they had entered into a comprehensive settlement agreement (the “Settlement Agreement”) which, among other things, would (i) resolve all claims in the Lawsuit, (ii) result in Calpine conveying clean legal title on all remaining oil and gas assets to Rosetta (except those properties subject to the preferential rights of third parties who have indicated a desire to exercise their rights), (iii) settle all pending claims the Company filed in the Calpine bankruptcy, (iv) modify and extend a gas purchase agreement by which Calpine purchases the Company’s dedicated production from the Sacramento Valley, California, and (v) formalize the assumption by Calpine of the July 7, 2005 purchase and sale agreement (together with all interrelated agreements, the “Purchase Agreement”) by which Calpine’s oil and gas business was conveyed to the Company thus resulting in the parties honoring their obligations under the Purchase Agreement on a going-forward basis. The Settlement Agreement became effective when the Bankruptcy Court entered its order on November 13, 2008, authorizing the execution of the Settlement Agreement and the performance of the obligations set forth therein. No objections or appeals to this order were filed or taken with the Bankruptcy Court before or after the hearing on November 13, 2008, and it became final on or about November 23, 2008.

The parties completed this settlement pursuant to the terms of the Settlement Agreement on December 1, 2008. The cash component of the settlement consisted of $12.4 million pre-tax payable in cash to Calpine to resolve all outstanding legal disputes regarding various matters, including Calpine’s fraudulent conveyance lawsuit. In addition, the Company paid $84.6 million under the Purchase Agreement to close the original acquisition transaction of the producing properties that were the subject of the lawsuit. This $84.6 million consisted of $67.6 million, which the Company withheld from the purchase price at the closing on July 7, 2005, related to non-consent properties (excluding the properties subject to preferential rights) that were not conveyed to the Company at closing on July 7, 2005, as well as $17.0 million for various disputed post-closing adjustments under the terms of the Purchase Agreement, as amended by the Bankruptcy Court order to remove the properties that had been subject to the Petersen preferential rights as if these properties had not been part of the Purchase Agreement.

As a result of the conclusion of this settlement, the Company recorded a pre-tax charge of $12.4 million in the fourth quarter of 2008, which is included in Other Income (Expense) in the Consolidated Statement of Operations.

Arbitration between the Company and the successor to Pogo Producing Company

On October 27, 2008, the Company, Calpine and XTO, as the successor to Pogo, agreed to a Title Indemnity Agreement in which Calpine agreed to indemnify XTO for certain title disputes, and the Company, Calpine and XTO agreed to dismissal of the arbitration proceeding against the Company and release of Pogo’s proofs of claim. The Company’s proofs of claim were resolved within the framework of the Settlement Agreement with Calpine, which was approved by the Bankruptcy Court and an order issued in this regard. XTO has dismissed with prejudice the arbitration against the Company.

Lease Obligations and Other Commitments

The Company has operating leases for office space and other property and equipment. The Company incurred lease rental expense of $3.3 million, $2.6 million and $2.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Future minimum annual rental commitments under non-cancelable leases at December 31, 2008 are as follows (In thousands):

2009	$	3,055
2010		2,972
2011		3,049
2012		3,074
2013		3,130
Thereafter		513
	$	15,793

The Company also has drilling rig commitments of $5.0 million for 2009.

(12) Stock-Based Compensation

Effective January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123R, whereby the Company records stock-based compensation expense based on the fair value of awards described below. Stock-based compensation expense recorded for all share-based payment arrangements for the years ended December 31, 2008, 2007 and 2006 was $7.2 million, $6.8 million and $5.7 million, respectively, with an associated tax benefit of $2.9 million, $2.5 million and $2.1 million, respectively. The remaining unrecognized compensation expense associated with total unvested awards as of December 31, 2008 was $9.8 million.

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 can not 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, 2008, 2007 and 2006 was $9.19 per share, $9.51 per share, and $10.71 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,
	2008		2007		2006
Expected option term (years)	6.5		6.5		6.5
Expected volatility	42.45	%	42.45	%	56.65	%
Expected dividend rate	0.00	%	0.00	%	0.00	%
Risk free interest rate	3.48% -3.84	%	4.36% -5.00	%	4.33% -5.15	%

The Company has assumed an annual forfeiture rate of 11% for the options granted in 2008 based on the Company’s history for this type of award to various employee groups. 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, 2008:

	Shares		Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term (In years)	Aggregate Intrinsic Value (In thousands)
Outstanding at December 31, 2006	853,354		$	16.80
Granted	316,100			19.11
Exercised	(40,104	)		16.26
Forfeited	(156,750	)		17.60
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
Options Vested and Exercisable at December 31, 2008	629,155		$	17.76	7.34	$	—

Stock-based compensation expense recorded for stock option awards for the years ended December 31, 2008, 2007 and 2006 was $1.7 million, $3.9 million and $2.9 million, respectively. Unrecognized expense as of December 31, 2008 for all outstanding stock options is $1.4 million and will be recognized over a weighted average period of 0.92 years.

The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 is $1.4 million, $0.2 million and $0.1 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 11% 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, 2008:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2006	326,900		$	17.05
Granted	315,350			19.48
Vested	(96,750	)		16.95
Forfeited	(90,075	)		18.34
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

The non-vested restricted stock outstanding at December 31, 2008 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, 2008 was $6.2 million.

Stock-based compensation expense recorded for restricted stock awards for the years ended December 31, 2008, 2007 and 2006 was $5.5 million, $2.9 million and $2.8 million, respectively. Unrecognized expense as of December 31, 2008 for all outstanding restricted stock awards is $8.5 million and will be recognized over a weighted average period of 1.78 years.

(13) Income Taxes

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

	Year Ended December 31,
	2008			2007		2006
	(In thousands)
Current:
Federal	$	2,304		$	—	$	—
State		1,388			115		172
		3,692			115		172
Deferred:
Federal		(107,568	)		31,979		24,132
State		(8,951	)		1,938		3,340
		(116,519	)		33,917		27,472
Total income tax expense (benefit)	$	(112,827	)	$	34,032	$	27,644

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,
	2008					2007				2006
	(In thousands)			(%)		(In thousands)		(%)		(In thousands)		(%)
US Statutory Rate	$	(105,327	)	35.0	%	$	31,933	35.0	%	$	25,288	35.0	%
Income/franschise tax, net of federal benefit		(7,562	)	2.5	%		2,053	2.3	%		2,283	3.2	%
Permanent differences and other		62		0.0	%		46	0.0	%		73	0.0	%
Total tax expense (Benefit)	$	(112,827	)	37.5	%	$	34,032	37.3	%	$	27,644	38.2	%

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,
	2008			2007
	(In thousands)
Deferred tax assets
Oil and gas properties basis differences	$	39,089		$	—
Alternative Minimum Tax credit		2,443			—
Accrued liabilities not currently deductible		2,603			3,273
Hedge activity		—			4,289
Net operating loss carryforward		621			12,506
Other		1,158			892
Total deferred tax assets		45,914			20,960
Oil and gas properties basis differences		—			(89,397	)
Hedge activity		(14,294	)		—
Other		(1,543	)		(200	)
Total gross deferred tax liabilities		(15,837	)		(89,597	)
Net deferred tax assets (liabilities)	$	30,077		$	(68,637	)

At December 31, 2008, the Company had a deferred tax asset related to federal and state net operating loss carryforwards of approximately $1.5 million. The 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 $39.1 million. 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 against future taxable income recorded on deferred tax assets as the Company believes it is more likely than not that the asset will be utilized.

It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on our financial condition or results of operations. As of December 31, 2008 and 2007, the Company has no unrecognized tax benefits that if recognized would affect the effective tax rate.

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.

(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,
	2008	2007	2006
	(In thousands)
Basic weighted average number of shares outstanding	50,693	50,379	50,237
Dilution effect of stock option and awards at the end of the period	—	210	171
Diluted weighted average number of shares outstanding	50,693	50,589	50,408
Anti-dilutive stock options and awards	592	385	198

Because the Company recognized a net loss for the year ended December 31, 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.

(15) Operating Segments

The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information”. Also, as all of our operations are located in the U.S., all of our 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 eight 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,
	2008(1)		2007(1)		2006(1)
	(In thousands)
Oil and Natural Gas Revenue
California	$	141,569	$	110,607	$	76,408
Rockies		29,491		10,676		2,115
South Texas		204,791		143,886		100,988
Texas State Waters		49,745		8,789		8,183
Other Onshore		44,809		25,905		27,757
Gulf of Mexico		47,611		40,700		26,734
	$	518,016	$	340,563	$	242,185

	December 31,
	2008		2007
	(In thousands)
Oil and Natural Gas Properties
California	$	619,593	$	540,924
Rockies		175,294		76,343
South Texas		712,464		591,355
Texas State Waters		65,085		55,918
Other Onshore		171,855		145,675
Gulf of Mexico		156,381		155,867
Other		9,439		6,393
	$	1,910,111	$	1,572,475

(1) Excludes the effects of hedging losses of $18.7 million for the year ended December 31, 2008 and hedging gains of $22.9 million and $29.6 million for the years ended December 31, 2007 and 2006, respectively.

Major Customers

For the year ended December 31, 2008, the Company had one major customer, Calpine Energy Services (“CES”), a Calpine affiliate, which accounted for approximately 61% of the Company’s consolidated annual revenue. The Company’s annual consolidated revenue from CES accounted for approximately 55% for the year ended December 31, 2007 and 45% for the year ended December 31, 2006, respectively, and is reflected in oil and natural gas sales.

For the years ended December 31, 2008, 2007 and 2006, revenues from sales to CES were $305.9 million, $201.4 million, and $99.1 million, respectively. There was no receivable from CES at December 31, 2008 or 2007. 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, 2008 and 2007, the Company had $19.4 million and $20.4 million in the margin account for December sales to CES which is included in Accrued Liabilities on the Consolidated Balance Sheet.

Marketing Services Agreement

The Company entered into a new marketing services agreement (“MSA”) with Calpine Producer Services (“CPS”) in connection with the partial transfer and release agreement (“PTRA”) settlement on August 3, 2007 for the period July 1, 2007 through June 30, 2009, subject to earlier termination on the occurrence of certain events. The MSA covers a majority of the Company’s current and future production during the term of the MSA. Additionally, CPS provides services related to the sale of the Company’s production including nominating, scheduling, balancing and other customary marketing services and assists the Company with volume reconciliation, well connections, credit review, training, severance and other similar taxes, royalty support documentation, contract administration, billing, collateral management and other administrative functions. All CPS activities are performed as agent and on the Company’s behalf, and under the Company’s control and direction. The fee payable by the Company under the MSA is based on net proceeds of all commodity sales multiplied by 0.50%, subject to caps imposed under the MSA. For the years ended December 31, 2008, 2007 and 2006, the fee was approximately $3.1 million, $2.5 million, and $2.3 million, respectively. The MSA provides that all contracts, agreements, collateral and funds related to the marketing and sales activity be contracted directly with the Company or the Company’s designee, and paid directly to the Company. The MSA will expire in June 2009 and the Company does not have intentions of renewing the MSA. The Company is expanding its internal capabilities in this regard so as to be able to market in-house all of its oil and gas production at the conclusion of the MSA.

(16) Related Party Transactions

In January 2006, the Company purchased certain leases from LOTO Energy II, LLC (“LOTO II”) for cash, subject to a retained overriding royalty in favor of LOTO II. LOTO II is indirectly owned in part by family trusts established by our former director G. Louis Graziadio, III. The Company also made certain ongoing development commitments to LOTO II associated with these leases. LOTO II is indirectly owned in part by family trusts established by Mr. Graziadio who was its president at the time of this purchase.

(17) Guarantor Subsidiaries

In the event that the Company files a shelf registration statement, any debt securities being registered may be guaranteed by substantially all of the Company’s subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The Company contemplates that if it offers guaranteed debt securities pursuant to the shelf registration statement, the guarantees by the subsidiaries will be 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, there are no restricted assets in any of the subsidiaries.