form10q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-Q


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

For The Quarterly Period Ended September 30, 2008

OR

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


Commission File Number: 000-51801
 

ROSETTA RESOURCES INC.
(Exact name of registrant as specified in its charter)

   
Delaware
43-2083519
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
717 Texas, Suite 2800, Houston, TX
77002
(Address of principal executive offices)
(Zip Code)
   
(Registrant's telephone number, including area code) (713) 335-4000
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x  No o
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
 
Large accelerated filer x
Accelerated filer o
   
Non-Accelerated filer o
Smaller Reporting Company o
(Do not check if smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o  No x
 
The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of November 3, 2008 was 51,744,778.
 
 
 
 

Table of Contents



PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Rosetta Resources Inc.
Consolidated Balance Sheet
(In thousands, except share amounts)

   
September 30,
2008
    
December 31,
2007
  
   
(Unaudited)
        
Assets
            
Current assets:
            
Cash and cash equivalents
   $ 135,183     $ 3,216  
Accounts receivable
     53,504       55,048  
Derivative instruments
     4,623       3,966  
Prepaid expenses
     5,550       10,413  
Other current assets
     4,068       4,249  
Total current assets
   $ 202,928     $ 76,892  
Oil and natural gas properties, full cost method, of which $32.0 million at September 30, 2008 and $40.9 million at December 31, 2007 were excluded from amortization
     1,752,569       1,566,082  
Other fixed assets
     7,738       6,393  
      1,760,307       1,572,475  
Accumulated depreciation, depletion, and amortization and impairment
     (649,007 )     (295,749 )
Total property and equipment, net
     1,111,300       1,276,726  
Deferred loan fees
     1,310       2,195  
Other assets
     1,567       1,401  
Total other assets
     2,877       3,596  
Total assets
   $ 1,317,105     $ 1,357,214  
                 
Liabilities and Stockholders' Equity
                
Current liabilities:
                
Accounts payable
   $ 36,995     $ 33,949  
Accrued liabilities
     54,078       64,216  
Royalties payable
     24,065       18,486  
Derivative instruments
     518       2,032  
Prepayment on gas sales
     23,078       20,392  
Deferred income taxes
     1,529       720  
Total current liabilities
     140,263       139,795  
Long-term liabilities:
                
Derivative instruments
     3,371       13,508  
Long-term debt
     245,000       245,000  
Asset retirement obligation
     25,858       18,040  
Deferred income taxes
     46,730       67,916  
Total liabilities
     461,222       484,259  
Commitments and contingencies (Note 9)
                
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 50,987,406 shares and 50,542,648 shares at September 30, 2008 and December 31, 2007, respectively
     50       50  
Additional paid-in capital
     771,471       762,827  
Treasury stock, at cost; 151,476 and 109,303 shares at September 30, 2008 and December 31, 2007, respectively
     (2,876 )     (2,045 )
Accumulated other comprehensive income (loss)
     461       (7,225 )
Retained earnings
     86,777       119,348  
Total stockholders' equity
     855,883       872,955  
Total liabilities and stockholders' equity
   $ 1,317,105     $ 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)
(Unaudited)

   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
   
2008
    
2007
    
2008
    
2007
  
Revenues:
                        
Natural gas sales
   $ 114,308     $ 79,061     $ 362,894     $ 225,658  
Oil sales
     15,728       10,657       49,941       26,730  
Total revenues
     130,036       89,718       412,835       252,388  
Operating Costs and Expenses:
                                
Lease operating expense
     12,857       11,912       40,445       33,274  
Depreciation, depletion, and amortization
     46,951       38,186       150,103       105,079  
Impairment of oil and gas properties
     205,659       -       205,659       -  
Treating and transportation
     1,780       1,412       4,624       3,057  
Marketing fees
     840       518       2,602       1,850  
Production taxes
     2,336       1,243       11,528       3,428  
General and administrative costs
     15,419       12,032       41,042       29,999  
Total operating costs and expenses
     285,842       65,303       456,003       176,687  
Operating (loss) income
     (155,806 )     24,415       (43,168 )     75,701  
                                 
Other (income) expense
                                
Interest expense, net of interest capitalized
     3,186       4,332       11,209       13,382  
Interest income
     (586 )     (240 )     (1,141 )     (1,469 )
Other (income) expense, net
     (40 )     (105 )     (170 )     (287 )
Total other expense
     2,560       3,987       9,898       11,626  
                                 
(Loss) income before provision for income taxes
     (158,366 )     20,428       (53,066 )     64,075  
Provision for income taxes
     (58,991 )     7,715       (20,495 )     24,280  
Net (loss) income
   $ (99,375 )   $ 12,713     $ (32,571 )   $ 39,795  
                                 
Earnings per share:
                                
Basic
   $ (1.96 )   $ 0.25     $ (0.64 )   $ 0.79  
Diluted
   $ (1.96 )   $ 0.25     $ (0.64 )   $ 0.79  
                                 
Weighted average shares outstanding:
                                
Basic
     50,813       50,409       50,636       50,363  
Diluted
     50,813       50,570       50,636       50,572  

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


Rosetta Resources Inc.
Consolidated Statement of Cash Flows
(In thousands)
(Unaudited)
 
   
Nine Months Ended
September 30,
  
   
2008
    
2007
  
Cash flows from operating activities
            
Net (loss) income
   $ (32,571 )   $ 39,795  
Adjustments to reconcile net (loss) income to net cash from operating activities
                
Depreciation, depletion and amortization
     150,103       105,079  
Impairment of oil and gas properties
     205,659       -  
Deferred income taxes
     (24,939 )     24,195  
Amortization of deferred loan fees recorded as interest expense
     885       885  
Income from unconsolidated investments
     (418 )     (117 )
Stock compensation expense
     4,975       4,090  
Change in operating assets and liabilities:
                
Accounts receivable
     1,544       84  
Other current assets
     5,044       (11,417 )
Other assets
     192       331  
Accounts payable
     3,046       12,267  
Accrued liabilities
     4,516       3,636  
Royalties payable
     8,265       4,725  
Net cash provided by operating activities
     326,301       183,553  
Cash flows from investing activities
                
Acquisition of oil and gas properties
     (29,570 )     (38,656 )
Purchases of property and equipment
     (167,629 )     (205,310 )
Disposals of property and equipment
     27       1,104  
Other
     0       25  
Net cash used in investing activities
     (197,172 )     (242,837 )
Cash flows from financing activities
                
Borrowing from revolving credit facility
     -       10,000  
Proceeds from stock options exercised
     3,669       571  
Purchases of treasury stock
     (831 )     (411 )
Net cash provided by financing activities
     2,838       10,160  
                 
Net increase (decrease) in cash
     131,967       (49,124 )
Cash and cash equivalents, beginning of period
     3,216       62,780  
Cash and cash equivalents, end of period
   $ 135,183     $ 13,656  
                 
Supplemental non-cash disclosures:
                
Capital expenditures included in accrued liabilities
   $ 23,316     $ 28,575  
 
The accompanying notes to the financial statements are an integral part hereof.


Rosetta Resources Inc.
 
Notes to Consolidated Financial Statements (unaudited)
 
(1)
Organization and Operations of the Company
 
Nature of Operations.    Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) was formed in June 2005 to acquire Calpine Natural Gas L.P. (and its partners) and the domestic oil and natural gas business formerly owned by Calpine Corporation and affiliates (“Calpine”). The Company acquired Calpine Natural Gas L.P. (and its partners) and Rosetta Resources California, LLC, Rosetta Resources Rockies, LLC, Rosetta Resources Offshore, LLC and Rosetta Resources Texas LP (and its partners) in July 2005 (hereinafter, the “Acquisition”) and, together with all subsequently acquired oil and natural gas properties, is engaged in oil and natural gas exploration, development, production and acquisition activities in North America. The Company’s main operations are primarily concentrated in the Sacramento Basin of California, the Rocky Mountains, the Lobo and Perdido Trends in South Texas, the State Waters of Texas and the Gulf of Mexico.
 
These interim financial statements have not been audited.  However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments necessary for a fair presentation of the financial statements have been included.  Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year.  In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America.  These financial statements and notes should be read in conjunction with the Company’s audited Consolidated/Combined Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.
 
Certain reclassifications of prior year balances have been made to conform them to the current year presentation.  These reclassifications have no impact on net income.
 
(2)
Summary of Significant Accounting Policies
 
The Company has provided a discussion of significant accounting policies, estimates and judgments in its Annual Report on Form 10-K for the year ended December 31, 2007.
 
Principles of Consolidation.  The accompanying consolidated financial statements as of September 30, 2008 and December 31, 2007 and for the three and nine months ended September 30, 2008 and 2007 contain the accounts of the Company and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.
 
Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements.  SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices.  SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The FASB also issued FASB Staff Position (“FSP”) FAS 157-2 (“FSP No. 157-2”), which delayed the effective date of SFAS No. 157 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.  Effective January 1, 2008, the Company partially adopted SFAS No. 157 and has chosen to defer the implementation of SFAS No.157 for nonfinancial assets and liabilities in accordance with FSP No. 157-2.  Accordingly, the Company will apply SFAS No. 157 to its nonfinancial assets and liabilities that are disclosed or recognized at fair value on a nonrecurring basis and other assets and liabilities in the first quarter of 2009.  We are still in the process of evaluating the effect of SFAS No. 157 on our nonfinancial assets and liabilities and therefore have not yet determined the impact that it will have on our financial statements upon full adoption in 2009. Nonfinancial assets and liabilities for which we have not yet applied the provisions of SFAS No. 157 include our asset retirement obligations.  The adoption of SFAS No. 157 for financial assets and liabilities did not have a significant effect on our consolidated financial position, results of operations or cash flows.  See Note 5 - Fair Value Measurements.
 
The Company also adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of SFAS No. 115” (“SFAS No. 159”) on January 1, 2008.  SFAS No. 159 permits companies to choose to measure financial instruments and certain other items at fair value that were not previously required to be measured at fair value.  The Company elected not to present assets and liabilities at fair value that were not required to be measured at fair value prior to the adoption of SFAS No. 159.
 
Recent Accounting Developments
 
The Hierarchy of Generally Accepted Accounting Principles. In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the “GAAP hierarchy”).  SFAS No. 162 is effective 60 days following the Securities and Exchange Commission’s (“SEC”) approval of the Public Company Accounting Oversight Board (“PCAOB”) amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.”  For pronouncements whose effective date is after March 15, 1992, and for entities initially applying an accounting principle after March 15, 1992 (except for EITF consensus positions issued before March 16, 1992, which become effective in the hierarchy for initial application of an accounting principle after March 15, 1993), an entity shall follow this Statement.  Any effect of applying the provisions of this Statement shall be reported as a change in accounting principle in accordance with FASB Statement No. 154, “Accounting Changes and Error Corrections.” An entity shall follow the disclosure requirements of that Statement, and additionally, disclose the accounting principles that were used before and after the application of the provisions of this Statement and the reason why applying this Statement resulted in a change in accounting principle.  The Company does not expect the adoption of SFAS No. 162 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.  The Company is currently evaluating the potential impact of SFAS No. 161 on the Company’s consolidated financial statements.
 
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.  The Company does 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.
 
Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141R”), which creates greater consistency in the accounting and financial reporting of business combinations.  This statement is effective for fiscal years beginning after December 15, 2008.   The Company does not expect the adoption of SFAS No. 141R to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
 
Derivative Instruments.  In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (“FSP FAS 133-1 and FIN 45-4”). This FSP amends FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” to require an additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB’s intent about the effective date of SFAS No.161.  This FSP is effective for reporting periods (annual or interim) ending after November 15, 2008. We do not expect this FSP to have a significant impact on our 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 5 - 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.
 
Equity Method Investments.  In October 2008, the FASB issued Emerging Issues Task Force (“EITF”) Issue No. 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”). The objective of this issue is to clarify how to account for certain transactions involving equity method investments. This issue is effective on a prospective basis in fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. Earlier application by an entity that has previously adopted an alternative accounting policy is not permitted. We do not expect this issue to have a significant impact on our consolidated financial position, results of operations or cash flows.


(3)
Property, Plant and Equipment
 
The Company’s total property, plant and equipment consists of the following:
 
   
September 30,
2008
    
December 31,
2007
  
   
(In thousands)
  
Proved properties
   $ 1,686,035     $ 1,499,046  
Unproved/unevaluated properties
     32,020       40,903  
Gas gathering systems and compressor stations
     34,514       26,133  
Other
     7,738       6,393  
Total oil and natural gas properties
     1,760,307       1,572,475  
Less: Accumulated depreciation, depletion, and amortization
     (649,007 )     (295,749 )
Total property and equipment, net
   $ 1,111,300     $ 1,276,726  
 
The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.5 million and $1.0 million of internal costs for the three months ended September 30, 2008 and 2007, respectively, and $4.3 million and $3.4 million for the nine months ended September 30, 2008 and 2007, respectively.
 
Included in the Company’s oil and gas properties are asset retirement costs of $23.0 million and $20.1 million as of September 30, 2008 and December 31, 2007, respectively.
 
Oil and gas properties include costs of $32.0 million and $40.9 million at September 30, 2008 and December 31, 2007, respectively, that were excluded from capitalized costs being amortized.  These amounts primarily represent unproved properties and unevaluated exploration projects in which the Company owns a direct interest.
 
Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets within each separate cost center.  The Company’s ceiling test was calculated using hedge adjusted market prices of gas and oil at September 30, 2008, which were 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). Cash flow hedges of natural gas production in place at September 30, 2008 increased the calculated ceiling value by approximately $23 million (net of tax).  Based upon studies to date, and in coordination with the Company's independent reserve engineers, the Company recognized a downward revision of 50-60 Bcfe of proved reserves during the third quarter of 2008.  Based upon this analysis and the reserve revision, a write-down of $129.1 million (net of tax) was recorded at September 30, 2008.  It is possible that another write-down of the Company's oil and gas properties could occur in the future should natural gas prices continue to decline and/or the Company experiences downward adjustments to the estimated proved reserves.
 
(4)
Commodity Hedging Contracts and Other Derivatives
 
The Company has entered into financial fixed price swaps with prices ranging from $6.81 per MMBtu to $8.63 per MMBtu covering a portion of the Company’s 2008, 2009 and 2010 natural gas production. The following financial fixed price swap transactions were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations at September 30, 2008:
 
Settlement Period
Derivative Instrument
Hedge Strategy
  
Notional Daily Volume MMBtu
    
Total of Notional Volume MMBtu
    
Average Underlying Prices MMBtu
    
Total of Proved Natural Gas Production Hedged (1)
    
Fair Market Value Gain/(Loss) (In thousands)
  
2008
Swap
Cash flow
     67,892       6,246,092       7.75       52 %   $ 5,246  
2009
Swap
Cash flow
     52,141       19,031,465       7.65       44 %     (4,942 )
2010
Swap
Cash flow
     10,000       3,650,000       8.31       9 %     (374 )
                  28,927,557                     $ (70 )
 
(1) Estimated based on net gas reserves presented in the December 31, 2007 Netherland, Sewell, & Associates, Inc. reserve report.
 
The Company has also entered into costless collar transactions covering a portion of the Company’s 2008 and 2009 natural gas production. The costless collars have an average floor price of $8.00 per MMBtu and an average ceiling price of $10.15 per MMBtu.  The following costless collar transactions were outstanding with associated notional volumes and contracted ceiling and floor prices that represent hedge prices at various market locations at September 30, 2008:
 

Settlement Period
Derivative Instrument
Hedge Strategy
  
Notional Daily Volume MMBtu
    
Total of Notional Volume MMBtu
    
Average Floor Price MMBtu
    
Average Ceiling Price MMBtu
    
Total of Proved Natural Gas Production Hedged (1)
    
Fair Market Value Gain/(Loss) (In thousands)
  
2008
Costless Collar
Cash flow
     5,000       460,000     $ 8.00     $ 10.55       4 %   $ 501  
2009
Costless Collar
Cash flow
     5,000       1,825,000     $ 8.00     $ 10.05       4 %     821  
                  2,285,000                             $ 1,322  
 
1) Estimated based on net gas reserves presented in the December 31, 2007 Netherland, Sewell, & Associates, Inc. reserve report.
 
In addition, the Company has hedged the interest rates on $75.0 million of its outstanding debt through 2008 and $50.0 million through June 2009.  As of September 30, 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)
  
2008
Swap
Cash Flow
     4.41 %   $ (156 )
2009
Swap
Cash Flow
     4.55 %     (362 )
                $ (518 )
 
The Company presents the fair value of its derivatives for which a master netting agreement exists on a net basis in accordance with FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts an interpretation of APB Opinion No. 10 and FASB Statement No. 105” (“FIN 39”).
 
The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities.  This eliminates the need for independent collateral postings for any margin obligation due to a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations.  As of September 30, 2008, the Company made no deposits for collateral.
 
The following table sets forth the results of the Company’s hedge transactions for the periods indicated below.
 
   
Three Months Ended September 30,
    
Nine Months Ended September 30,
  
Natural Gas
  
2008
    
2007
    
2008
    
2007
  
Quantity settled (MMBtu)
     6,706,092       6,009,100       19,498,524       17,750,400  
Increase (Decrease) in natural gas sales revenue (In thousands)
   $ (12,125 )   $ 10,333     $ (29,420 )   $ 17,810  
 
The following table sets forth the results of the Company’s interest rate hedging transactions for the periods indicated below.
 
   
Three Months Ended September 30,
    
Nine Months Ended September 30,
  
Interest Rate Swaps
  
2008
    
2007
    
2008
    
2007
  
Decrease in interest expense (In thousands)
     (372 )   $ -       (832 )   $ -  
 
As of September 30, 2008, the Company expects to reclassify gains of $4.1 million to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.
 

(5)
Fair Value Measurements
 
As discussed in Note 1, the Company partially adopted 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 natural gas swaps, natural gas zero cost collars and interest rate swaps. The Company utilizes counterparty and third party broker quotes to determine the valuation of its derivative instruments.  Fair values derived from counterparties and brokers are further verified using the closing price as of September 30, 2008 for the relevant NYMEX futures contracts and Intercontinental Exchange traded contracts for each derivative settlement location.  Accordingly, the Company did not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.
 
The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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 September 30, 2008
(In thousands)
  
   
Level 1
    
Level 2
    
Level 3
    
Total
  
Assets (Liabilities):
                        
Commodity derivative contracts
     -       -       1,252       1,252  
Interest rate swap contracts
     -       -       (518 )     (518 )
Total
     -       -       734       734  
 
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 September 30, 2008.
 

   
Derivatives Asset (Liability)
(In thousands)
  
Balance as of January 1, 2008
   $ (10,792 )
Total (gains) losses (realized or unrealized)
        
included in earnings
     -  
included in other comprehensive income
     (18,725 )
Purchases, issuances and settlements
     30,251  
Transfers in and out of level 3
     -  
Balance as of September 30, 2008
   $ 734  
         
Change in unrealized gains (losses) relating to derivatives still held as of September 30, 2008
   $ -  
 
(6)
Asset Retirement Obligation
 
Activity related to the Company’s asset retirement obligation (“ARO”) is as follows:
 
   
Nine Months Ended September 30, 2008
  
   
(In thousands)
  
ARO as of December 31, 2007
   $ 22,670  
Revision of previous estimates
     1,519  
Liabilities incurred during period
     1,428  
Accretion expense
     1,501  
ARO as of September 30, 2008
   $ 27,118  
 
Of the total ARO, approximately $1.3 million is classified as a current liability included in accrued liabilities on the Consolidated Balance Sheet at September 30, 2008.
 
(7)
Long-Term Debt
 
The Company’s credit facilities consist of a senior secured revolving line of credit (“Revolver”) up to $400.0 million with a borrowing base of $400.0 million, which was increased from $350.0 million in June 2008, and a five-year $75.0 million second lien term loan.
 
As of September 30, 2008, the Company had total outstanding borrowings and letters of credit of $245.0 million and $1.0 million, respectively.  At September 30, 2008, the Company’s weighted average borrowing rate was 4.69 %.  Net borrowing availability under the Revolver was $229.0 million at September 30, 2008.  The Company was in compliance with all covenants at September 30, 2008.
 
All amounts drawn under the Revolver are due and payable on April 5, 2010.  The principal balance associated with the second lien term loan is due and payable on July 7, 2010.
 
(8)
Income Taxes
 
The effective tax rate for the three and nine months ended September 30, 2008 was 37.2% and 38.6%, respectively.  The effective tax rate for the three and nine months ended September 30, 2007 was 37.8% and 37.9%, respectively.   The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes, tax credits and other permanent differences.
 
As of September 30, 2008, the Company had no unrealized tax benefits. There were no significant changes to the calculation since December 31, 2007. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlements of audits and the expiration of statue of limitations prior to September 30, 2009.
 

(9)
Commitments and Contingencies
 
The Company is party to various oil and natural gas litigation matters arising out of the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
 
Calpine Settlement
 
On December 20, 2005, Calpine Corporation and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (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 an adversary proceeding against the Company in the Bankruptcy Court (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, will (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 “PSA Agreement”) by which Calpine’s oil and gas business was conveyed to the Company thus resulting in the parties honoring their obligations under the PSA Agreement on a going-forward basis.  This Settlement Agreement, although executed by both parties, does not become effective until the Bankruptcy Court enters a final order authorizing the execution of the Settlement Agreement and the performance of the obligations set forth therein. The settlement consists of $12.4 million payable in cash to Calpine to resolve all outstanding legal disputes regarding various matters, including Calpine’s fraudulent conveyance lawsuit. In addition, the Company will pay $84.6 million to close the original acquisition transaction of the producing properties that were the subject of the lawsuit. This $84.6 million consists of $67.6 million which the Company withheld from the purchase price related to properties that were not conveyed to the Company, as well as $17.0 million for post-closing adjustments.
 
Unless the Bankruptcy Court declines to authorize Calpine to enter into the executed Settlement Agreement or a party objects to and appeals any order entered by the Bankruptcy Court approving the Settlement Agreement, the Company anticipates the Settlement Agreement and the execution of the obligations required thereunder will be completed by the parties on or before December 1, 2008, and if so, the Company will record the financial charges during the fourth quarter 2008. If the settlement closing does not occur by December 31, 2008, or any extended date as may be mutually agreed among the parties, if applicable, the Settlement Agreement expires.

Arbitration between Calpine Corp./the Company  and Pogo Producing Company
 
On October 27, 2008, the Company, Calpine and XTO Energy, Inc. (“XTO”), as the successor to Pogo Producing Company (“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 are being resolved within the framework of the Settlement Agreement with Calpine, which is subject to bankruptcy court approval.
 
(10)
Comprehensive Income
 
The Company’s total other comprehensive income (loss) is shown below:
 

   
Three Months Ended September 30,
    
Nine Months Ended September 30,
  
   
2008
    
2007
    
2008
    
2007
  
   
(In thousands)
  
Accumulated other comprehensive (loss) income beginning of period
         $ (96,756 )         $ (8,636 )         $ (7,225 )         $ 6,315  
Net (loss) income
     (99,375 )             12,713               (32,571 )             39,795          
                                                                 
Change in fair value of derivative hedging instruments
     142,431               19,723               (18,002 )             3,202          
Hedge settlements reclassed to income
     12,497               (10,333 )             30,251               (17,810 )        
Tax provision related to hedges
     (57,711 )             (3,539 )             (4,563 )             5,508          
Total other comprehensive income (loss)
     97,217       97,217       5,851       5,851       7,686       7,686       (9,100 )     (9,100 )
                                                                 
Comprehensive income (loss)
     (2,158 )             18,564               (24,885 )             30,695          
Accumulated other comprehensive income (loss)
           $ 461             $ (2,785 )           $ 461             $ (2,785 )

 
(11)
Earnings Per Share
 
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period.  Diluted earnings per share reflects the potential dilution that could occur if outstanding common stock awards and stock options were exercised at the end of the period.
 
The following is a calculation of basic and diluted weighted average shares outstanding:
 
   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
   
2008
    
2007
    
2008
    
2007
  
   
(In thousands)
  
Basic weighted average number of shares outstanding
     50,813       50,409       50,636       50,363  
Dilution effect of stock option and awards at the end of the period
     -       161       -       209  
Diluted weighted average number of shares outstanding
     50,813       50,570       50,636       50,572  
                                 
Anti-dilutive stock awards and shares
     611       415       617       403  
 
 
(12)
Geographic Area Information
 
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.”
 
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.
 

Oil and Natural Gas Revenue
 
   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
   
2008 (1)
    
2007 (1)
    
2008 (1)
    
2007 (1)
  
   
(In thousands)
  
California
   $ 38,310     $ 22,110     $ 118,898     $ 77,705  
Rocky Mountains
     6,993       2,463       23,400       6,749  
Mid-Continent
     615       494       1,878       1,851  
Lobo
     53,263       30,792       150,183       84,059  
Perdido
     6,678       5,951       24,514       19,289  
State Waters
     13,555       529       44,292       2,176  
Other Onshore
     11,424       5,473       35,564       14,795  
Gulf of Mexico
     11,323       11,573       43,527       27,954  
    $ 142,161     $ 79,385     $ 442,256     $ 234,578  
 
(1) Excludes the effects of hedging losses of $12.1 million and hedging gains of $10.3 million for the three months ended September 30, 2008 and 2007, respectively, and hedging losses of $29.4 million and hedging gains of $17.8 million for the nine months ended September 30, 2008 and 2007, respectively.
 
Oil and Natural Gas Properties
 
   
September 30, 2008
    
December 31, 2007
  
   
(In thousands)
  
California
   $ 578,132     $ 540,924  
Rocky Mountains
     131,392       76,343  
Mid-Continent
     14,620       14,698  
Lobo
     576,736       515,096  
Perdido
     89,426       76,259  
Texas State Waters
     64,430       55,918  
Other Onshore
     141,984       130,977  
Gulf of Mexico
     155,849       155,867  
Other
     7,738       6,393  
Total property and equipment
   $ 1,760,307     $ 1,572,475  
 
 
(13)
Subsequent Events
 
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, will (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 Rosetta’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 “PSA Agreement”) by which Calpine’s oil and gas business was conveyed to the Company thus resulting in the parties honoring their obligations under the PSA Agreement on a going-forward basis.  This Settlement Agreement, although executed by both parties, does not become effective until the Bankruptcy Court enters a final order authorizing the execution of the Settlement Agreement and the performance of the obligations set forth therein. The settlement consists of $12.4 million payable in cash to Calpine to resolve all outstanding legal disputes regarding various matters, including Calpine’s fraudulent conveyance lawsuit. In addition, the Company will pay $84.6 million to close the original acquisition transaction of the producing properties that were the subject of the lawsuit. This $84.6 million consists of $67.6 million which the Company withheld from the purchase price related to properties that were not conveyed to the Company, as well as $17.0 million for post-closing adjustments.
 
Unless the Bankruptcy Court declines to authorize Calpine to enter into the executed Settlement Agreement or a party objects to and appeals any order entered by the Bankruptcy Court approving the Settlement Agreement, Rosetta anticipates the Settlement Agreement and the execution of the obligations required thereunder will be completed by the parties on or before December 1, 2008.
 
On October 27, 2008, the Company, Calpine and XTO Energy, Inc. (“XTO”), as the successor to Pogo Producing Company (“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 are being resolved within the framework of the settlement agreement with Calpine, which is subject to bankruptcy court approval.
 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This report includes various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology.
 
The forward-looking statements contained in this report are largely based on our expectations for the future, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A, “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2007, as updated by this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances, or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:  
 
·
The supply and demand for natural gas and oil;
 
·
The price of natural gas and oil;  
 
·
Conditions in the energy and economic markets;
 
·
Changes or advances in technology;
 
·
Reserve levels;
 
·
Inflation;
 
·
The availability and cost of relevant raw materials, goods and services;
 
·
Commodity prices;
 
·
Future processing volumes and pipeline throughput;
 
·
The occurrence of property acquisitions or divestitures;
 
·
Drilling and exploration risks;
 
·
The availability and cost of processing and transportation;
 
·
Developments in oil-producing and natural gas-producing countries;
 
·
Competition in the oil and natural gas industry;
 
·
The ability and willingness of our current or potential counterparties or vendors to enter into transactions with us and/or to fulfill their obligations to us;
 
·
Our ability to access the capital markets on favorable terms or at all;
 
·
Our ability to obtain credit and/or capital in desired amounts and/or on favorable terms;

 
·
Failure of our joint interest partners to fund any or all of their portion of any capital program;
 
·
Present and possible future claims, litigation and enforcement actions;
 
·
Effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;
 
·
Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;
 
·
General economic conditions, either internationally, nationally or in jurisdictions affecting our business;
 
·
Failure of the bankruptcy court to approve the settlement agreement and if the court fails to approve the settlement agreement, the amount of resources expended in connection with Calpine’s bankruptcy and its fraudulent conveyance action, including significant ongoing costs for lawyers, consultants, experts and all related expenses, as well as all lost opportunity costs associated with our internal resources dedicated to these matters and possible impacts on our reputation;
 
·
Disputes with mineral lease and royalty owners regarding calculation and payment of royalties;
 
·
The weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; and
 
·
Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.
 
Overview
 
The following discussion addresses material changes in the results of operations for the three and nine months ended September 30, 2008 compared to the three and nine months ended September 30, 2007, and the material changes in financial condition since December 31, 2007.  It is presumed that readers have read or have access to our 2007 Annual Report on Form 10-K for the year ended December 31, 2007, which includes, as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations, disclosures regarding critical accounting policies.
 
The following summarizes our performance for the first nine months of 2008 as compared to the same period for 2007:
 
·
Production on an equivalent basis increased 27%;
 
·
Total revenue, including the effects of hedging, increased $160.4 million or 64%;
 
·
Impairment of oil and gas properties of $205.7 million pre-tax ($129.1 million net of tax) that includes the impact of unfavorable reserve revisions;
 
·
Net loss of $32.6 million; net income/loss, excluding the impairment charge of $129.1 million, would have increased $56.8 million or 143%;
 
·
Diluted loss per share of $0.64; diluted earnings/loss per share, excluding the impairment charge of $129.1 million, would have increased $1.10 or 139%;
 
·
Drilled 112 gross wells with a success rate of 86%; and
 
·
In mid September 2008, we sustained damage to our Sabine Lake and East Cameron 88/89 production facilities as a result of Hurricane Ike.  Repairs at Sabine Lake have now been completed and production resumed on October 28, 2008.  All critical long-lead equipment and materials have been secured for the commencement of repairs at the East Cameron facility and production is anticipated to resume there before the end of the year.
 
Since inception in July 2005, Rosetta has delivered top-line production growth by executing a business model based predominantly upon conventional exploration and exploitation. The Company actively pursued opportunities in conventional basins and plays characterized by high decline rates. In early 2008, we began a strategic shift toward a business model that we believed could generate more sustainable, predictable performance over time. Accordingly, we have been on a path to de-emphasize high-decline rate, conventional programs in the Gulf of Mexico and Texas State Waters, while focusing on building positions and programs in unconventional onshore domestic basins.  These basins are characterized by having lower risk project inventory and repeatable programs. Consistent with the nature of unconventional resources, we would expect annual growth rates to moderate compared to historical top-line growth rates as we shift to more resource-driven projects and focus on inventory generation. Our strategy shift will be accompanied by goals to deliver, over time, both acceptable rates of top-line growth and growth in proved, probable and possible reserves in excess of historical performance.
 

We believe we can successfully implement our strategy shift because of several factors. Of note, we believe our core existing onshore assets have upside that has not been fully analyzed through an unconventional resource lens. We think this approach could yield additional inventory for the Company over time. In addition, we have an experienced workforce and management team with background in unconventional resource operations. Finally, we have a balance sheet and cost structure that we believe allows us to adapt to the inevitable industry cycles and current economic downturn. These factors do not ensure our success in executing our strategy shift, but we believe they provide an advantage when coupled with a prudent investment approach.
 
Our plan for implementing the strategy shift that is underway is to pursue both organic and inorganic opportunities that meet Rosetta’s criteria for funding, particularly inventory potential and attractive financial returns.  In 2008, we began several studies to test organic concepts in areas where we currently have assets for the purpose of identifying possible upside and inventory. We also began studying new domestic basins where we believe Rosetta can compete successfully.  While we have a preference for organic opportunities, we are also expanding our capability to evaluate and pursue acquisition opportunities that make sense for Rosetta. We believe this balanced approach is needed for long-term success; however, it is not our intention or desire to pursue acquisitions for the sake of growth.
 
In the third quarter, our technical teams reviewed the first of several detailed field studies. Based upon these studies, and in coordination with our independent reserve engineers, we recently recognized a downward revision of 50 – 60 Bcfe of proved reserves, or approximately 12 – 14% of previously estimated reserves.  Of the revision, approximately 30 Bcfe is associated with the low pressure Emigh and Hamilton plays in the Sacramento Basin. The remainder of the revision is attributable to other existing properties, including the South Texas Lobo play.  These revisions, coupled with relatively low commodity prices at the end of the third quarter 2008, resulted in a ceiling test impairment of $129.1 million, net of tax. We expect to continue evaluating and testing additional unconventional concepts within our existing assets over the next several quarters.
 
On October 22, 2008, we signed a settlement agreement with Calpine Corporation (“Calpine”) which is subject to bankruptcy court approval and expires if not closed by December 31, 2008, or any extended date as may be mutually agreed among the parties, if any.  Under the terms of our settlement agreement, we have agreed with Calpine to effect a lump sum global settlement consisting of cash and other contractual consideration, subject to bankruptcy court approval. The settlement consists of $12.4 million payable in cash to Calpine to resolve all outstanding legal disputes regarding various matters, including Calpine’s fraudulent conveyance lawsuit. This settlement resolves all disputes between the parties, whether relating to the oil and gas property purchase, Rosetta’s proofs of claim in the bankruptcy and its counter claims, or otherwise and will be recorded as a charge to income upon approval from the Bankruptcy Court, which is expected in the fourth quarter of 2008.  In addition, we will pay $84.6 million to close the original 2005 acquisition transaction of the producing properties that were the subject of the lawsuit. This $84.6 million consists of $67.6 million which we withheld from the purchase price related to properties that were not conveyed to Rosetta, as well as $17.0 million for post-closing adjustments.
 
With the Calpine settlement awaiting bankruptcy court approval and known reserve revisions behind us, we are in a better position to execute our business plan and affect our desired goals. We believe that we now have greater operating control and latitude over critical activities, such as rationalizing our portfolio, attracting new technical talent, pursuing acquisitions that fit our strategy, and building sustainable capital project inventory. Given our relatively low leverage and our balance sheet, we believe we are in a favorable position to execute a sound capital program in 2009.  We are currently developing our capital expenditures budget for 2009 and expect to approve a budget that can be funded with operating cash flow. At gas prices of approximately $7 per Mcf or higher, we believe we can not only maintain production volumes at roughly current levels, but also fund additional identified organic and/or inorganic inventory growth programs. Within our core capital program, we will continue to focus on organic growth in onshore core areas and continue to minimize capital expenditures in offshore assets. We retain the discretion to adjust and allocate capital spending plans in response to market conditions, which could impact targets and performance.

We recognize that we are operating in one of the most challenging business environments in recent history and that the credit crisis, declining oil prices, lower natural gas prices and a weakening global economic outlook are all adversely impacting the business environment.  We are working with our lenders to effectively stay abreast of market and creditor conditions to ensure prudent and timely decisions should market conditions deteriorate further.  We believe that we have sufficient liquidity and operational flexibility to fund and actively manage our capital expenditures program, including, but not limited to, capping these expenditures in an annual period to the cash flows available from operating activities. Also of note, our capital expenditures are primarily in areas where Rosetta acts as operator and has high working interests. As a result, we do not believe we have significant exposure to joint interest partners who may be unable to fund their portion of any capital program, but we are monitoring partner situations in light of the current economic environment.
 
To the extent that capital expenditures or prudent acquisitions require cash flow in excess of available funds, we intend to draw on our unused capacity under our existing revolving credit facility. As of September 30, 2008, the undrawn credit available to us was $229.0 million.  We have not received any indication from our lenders that draws under the credit facility are restricted below current availability at this time and we are proactively communicating with them on a routine basis. We increased our borrowing base in the second quarter to $400.0 million and are currently in the process of affirming that borrowing base. We do not anticipate any significant change to the borrowing base as a result of the reaffirmation process, but we will advise the marketplace if such a change occurs.


Finally, 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 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.

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

Critical Accounting Policies and Estimates
 
In our Annual Report on Form 10-K for the year ended December 31, 2007, we identified our most critical accounting policies upon which our financial condition depends as those relating to oil and natural gas reserves, full cost method of accounting, derivative transactions and hedging activities, income taxes and stock-based compensation.
 
We assess the impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. If the net capitalized costs of oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, it would reduce earnings and impact shareholders’ equity in the period of occurrence and result in a lower depreciation, depletion and amortization expense in the future.
 
Our ceiling test was calculated using hedge adjusted market prices at September 30, 2008, which were 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). Cash flow hedges of natural gas production in place at September 30, 2008 increased the calculated ceiling value by approximately $23 million (net of tax). Based upon this analysis and as discussed above, a write-down of $129.1 million (net of tax) was recorded at September 30, 2008.  It is possible that another write-down of our oil and gas properties could occur in the future should natural gas prices continue to decline and/or we experience downward adjustments to our estimated proved reserves.
 
We have entered into financial fixed price swaps with prices ranging from $6.81 per MMBtu to $8.63 per MMBtu covering a portion of our 2008, 2009 and 2010 production of approximately 28.9 million MMBtu. We have also entered into costless collar transactions covering a portion of our 2008 and 2009 production of approximately 2.3 million MMBtu. The costless collars have an average floor price of $8.00 per MMBtu and an average ceiling price of $10.15 per MMBtu.   Approximately 93% of total hedged transactions represent hedged prices of commodities at PG&E Citygate and Houston Ship Channel.  Our current cash flow hedge positions are with counterparties who are lenders in our 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 our hedge related credit obligations.  As of September 30, 2008, we made no deposits for collateral.  Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of September 30, 2008.  Non performance risk was evaluated using current credit default swap values and default probabilities for each counterparty.
 
We utilize counterparty and third party broker quotes to determine the valuation of our derivative instruments and have used this valuation technique since adoption of  SFAS No. 157 on January 1, 2008 and we have made no changes or adjustments to our technique since then.  Fair values derived from counterparties and brokers are further verified using the closing price as of September 30,2008 for the relevant NYMEX futures contracts and Intercontinental Exchange traded contracts for each derivative settlement location.    We mark to market on a quarterly basis.
 

Recent Accounting Developments
 
For a discussion of recent accounting developments, see Note 2 to the Consolidated Financial Statements in Part I. Item 1. Financial Statements of this Form 10-Q.
 
Results of Operations
 
Revenues. Our revenues are derived from the sale of our oil and natural gas production, which includes the effects of qualifying hedge contracts.  Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold.  Total revenue for the first nine months of 2008 was $412.8 million, including the effects of hedging, which is an increase of $160.4 million, or 64%, from the nine months ended September 30, 2007. Natural gas sales, excluding the effects of hedging, increased by $184.5 million with $125.6 million attributable to a 47% increase in natural gas prices and $58.9 million attributable to a 28% increase in production volumes.  Oil sales increased by $23.2 million with $21.5 million associated with a 76% increase in the price of oil and $1.7 million associated with increased production.  Approximately 88% of revenue was attributable to natural gas sales on total volumes of 40.8 Bcfe.
 
The following table presents information regarding our revenues and production volumes:
 
   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
   
2008
    
2007
    
% Change Increase/ (Decrease)
    
2008
    
2007
    
% Change Increase/ (Decrease)
  
   
(In thousands, except percentages and per unit amounts)
  
Natural gas sales
   $ 114,308     $ 79,061       45 %   $ 362,894     $ 225,658       61 %
Oil sales
     15,728       10,657       48 %     49,941       26,730       87 %
Total revenues
   $ 130,036     $ 89,718       45 %   $ 412,835     $ 252,388       64 %
                                                 
Production:
                                                
Gas (Bcf)
     12.1       10.7       13 %     38.1       29.7       28 %
Oil (MBbls)
     130.3       141.4       (8 %)     436.2       410.7       6 %
Total Equivalents (Bcfe)
     12.9       11.6       11 %     40.8       32.2       27 %
                                                 
$ per unit:
                                                
Avg. Gas Price per Mcf
   $ 9.47     $ 7.39       28 %   $ 9.51     $ 7.60       25 %
Avg. Gas Price per Mcf, excluding Hedging
     10.47       6.42       63 %     10.28       7.00       47 %
Avg. Oil Price per Bbl
     120.66       75.37       60 %     114.48       65.08       76 %
Avg. Revenue per Mcfe
     10.08       7.73       30 %     10.12       7.84       29 %
 
Natural Gas.  For the three months ended September 30, 2008, natural gas revenue increased by 45% or $35.2 million, including the realized impact of derivative instruments, from the same period in 2007 to $114.3 million.  This is primarily due to an increase of 28% in the average gas price, including the effects of hedging, which increased by $2.08 from $7.39 per Mcf for the three months ended September 30, 2007 to $9.47 per Mcf for the same period in 2008.  In addition, production volumes increased overall by 13%, or 1.4 Bcfe, primarily through drilling new wells in the Rockies and production from Sabine Lake in Texas State Waters prior to hurricane impact in late September. The effect of gas hedging activities on natural gas revenue for the three months ended September 30, 2008 was a loss of $12.1 million or a decrease of $1.00 per Mcf as compared to a gain of $10.3 million for the three months ended September 30, 2007.

For the nine months ended September 30, 2008, natural gas revenue increased by 61% or $137.2 million, including the realized impact of derivative instruments, from the same period in 2007 to $362.9 million.  This increase was due to a higher average gas price and increased production volumes.  The average gas price, including the effects of hedging, increased by 25%, or $1.91, from $7.60 per Mcf for the nine months ended September 30, 2007 to $9.51 per Mcf for the same period in 2008.  The 2008 drilling program successfully increased the number of producing wells, which along with Sabine Lake coming online late 2007, contributed to production volumes increasing by 8.4 Bcfe, or 28%.  The effect of gas hedging activities on natural gas revenue for the nine months ended September 30, 2008 was a loss of $29.4 million or a decrease of $0.77 per Mcf as compared to a gain of $17.8 million for the nine months ended September 30, 2007.

Crude Oil.  For the three months ended September 30, 2008, oil revenue was $15.7 million, which is a 48% increase compared to $10.7 million for the same period in 2007.  This increase is primarily attributable to higher average oil prices of $120.66 per Bbl for the three months ended September 30, 2008 compared to $75.37 per Bbl for the same period in 2007.  Oil volumes decreased overall by 8% in 2008 with reductions in the Offshore and Onshore Other regions based upon our decision to shift capital investment away from these areas and toward more gas-prone, repeatable projects.  The reduction in these areas was partially offset by the production increase in Texas State Waters due to Sabine Lake operations.
 

For the nine months ended September 30, 2008, oil revenue increased by 87%, or $23.2 million compared to the same period in 2007.  This increase is primarily attributable to higher average oil prices of $114.48 per Bbl for the nine months ended September 30, 2008 compared to $65.08 per Bbl for the same period in 2007.  Oil volumes increased overall by 6% for the nine months ended September 30, 2008 compared to the same period in 2007 due an increase in production in Sabine Lake offset by decreases in production in the Offshore region compared to the same period in 2007.
 
Operating Expenses
 
The following table presents information regarding our operating expenses:
 
   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
   
2008
    
2007
    
% Change Increase/ (Decrease)
    
2008
    
2007
    
% Change Increase/ (Decrease)
  
   
(In thousands, except percentages and per unit amounts)
  
Lease operating expense
   $ 12,857     $ 11,912       8 %   $ 40,445     $ 33,274       22 %
Production taxes
     2,336       1,243       88 %     11,528       3,428       236 %
Depreciation, depletion and amortization
     46,951       38,186       23 %     150,103       105,079       43 %
Impairment of oil and gas properties
     205,659       -       100 %     205,659       -       100 %
General and administrative costs
     15,419       12,032       28 %     41,042       29,999       37 %
                                                 
$ per unit:
                                                
Avg. lease operating expense per Mcfe
   $ 1.00     $ 1.03       (3 %)   $ 0.99     $ 1.03       (4 %)
Avg. production taxes per Mcfe
     0.18       0.11       64 %     0.28       0.11       155 %
Avg. DD&A per Mcfe
     3.64       3.29       11 %     3.68       3.26       13 %
Avg. G&A per Mcfe
     1.19       1.04       14 %     1.01       0.93       9 %
 
Lease Operating Expense.  Lease operating expense increased $0.9 million for the three months ended September 30, 2008 as compared to the three months ended September 30, 2007.  The overall increase is due to higher costs in workover, direct lease operating expense and ad valorem taxes.  Workover expense increased by $0.8 million in 2008 due to a tropical storm insurance reimbursement offsetting expense for offshore in the third quarter of 2007.  Direct lease operating expense increased by $0.4 million due to an increase in the number of producing wells in the Rockies and several non-operated fields in Texas Other.  Ad valorem taxes increased by $0.2 million in 2008 primarily due to higher property appraisals in California that were not reflected in 2007 until the fourth quarter.  These increases were partially offset by a $0.5 million decrease in insurance expense based upon lower rates.  The average lease operating expense decreased to $1.00 per Mcfe for the three months ended September 30, 2008 from $1.03 per Mcfe for the three months ended September 30, 2007.
 
Lease operating expense increased $7.2 million for the nine months ended September 30, 2008 as compared to the nine months ended September 30, 2007.  The overall increase is due to a $4.9 million increase in direct lease operating expense primarily related to new drilled wells being put on production in the Rockies, Lobo and several Texas Other fields as well as a full nine months of Sabine Lake operations.  Expense workovers are up $1.7 million in 2008 compared to 2007 due to a hurricane reimbursement being received for offshore in 2007.  Additionally, ad valorem taxes increased by $0.8 million in 2008.
 
Production Taxes.  Production taxes increased $1.1 million for the three months ended September 30, 2008 as compared to the three months ended September 30, 2007 primarily due to a 11% increase in production volumes coupled with higher prices, as well as increased production in areas that do not qualify for the State of Texas high cost gas exemptions.


Production taxes increased $8.1 million for the nine months ended September 30, 2008 as compared to the nine months ended September 30, 2007 primarily due to a 27% increase in production volumes coupled with higher prices, as well as increased production in areas which do not qualify for the State of Texas high cost gas exemptions.
 
Depreciation, Depletion, and Amortization.  Depreciation, depletion and amortization (“DD&A”) expense increased $8.8 million for the three months ended September 30, 2008 as compared to the three months ended September 30, 2007.  This increase is due to an 11% increase in total production and a higher DD&A rate as compared to 2007.  The DD&A rate for the third quarter of 2008 was $3.64 per Mcfe while the DD&A rate for the third quarter of 2007 was $3.29 per Mcfe.
 
DD&A expense increased $45.0 million for the nine months ended September 30, 2008 as compared to the nine months ended September 30, 2007.  This increase is due to a 27% increase in total production and a higher DD&A rate as compared to 2007.  The DD&A rate for the respective period in 2008 was $3.68 per Mcfe while the DD&A rate for the same period in 2007 was $3.26 per Mcfe.
 
Impairment of Oil and Gas Properties.  Based upon the quarterly ceiling test computation using hedge adjusted market prices in effect at September 30, 2008, and in conjunction with the third quarter 2008 downward revision of a portion of the Company’s reserves, the net capitalized costs of oil and natural gas properties exceeded the cost center ceiling at September 30, 2008 and an impairment expense of $205.7 million, $129.1 million net of tax, was recorded.
 
General and Administrative Costs. General and administrative costs increased by $3.4 million for the three months ended September 30, 2008 as compared to the three months ended September 30, 2007. The higher cost is primarily due to the increase of $4.7 million in legal fees the majority of which are associated with the Calpine litigation and $1.1 million in higher benefit and bonus costs relating to the increase in the number of employees.  These increases were offset by a $2.5 million decrease in salaries and wages due to severance expense paid to the former CEO in the third quarter of 2007.
 
General and administrative costs increased by $11.0 million for the nine months ended September 30, 2008 as compared to the nine months ended September 30, 2007.   The higher cost is primarily due to the increase of $9.0 million in legal fees the majority of which are associated with the Calpine litigation and $2.1 million in higher bonus costs relating to the increase in the number of employees.
 
Total Other Expense
 
For the three months ended September 30, 2008, total other expense decreased by $1.4 million as compared to the three months ended September 30, 2007 primarily as a result of a reduction of interest expense of $1.4 million on debt due to lower LIBOR rates during the period offset by a decrease in capitalized interest of $0.2 million.  Interest income remained relatively flat period over period.

For the nine months ended September 30, 2008, total other expense decreased by $1.7 million as compared to the nine months ended September 30, 2007 primarily as a result of a reduction of interest expense of $2.7 million on debt due to lower LIBOR rates during the period offset by a decrease in capitalized interest of $0.6 million.  Interest income remained relatively flat period over period.  Interest income increased by $0.3 million due primarily to increased cash balances over the prior period.
 
Provision for Income Taxes
 
The effective tax rate for the three and nine months ended September 30, 2008 was 37.2% and 38.6%, respectively.  The effective tax rate for the three and nine months ended September 30, 2007 was 37.8% and 37.9%, respectively.   The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes, tax credits and other permanent differences.        
 
Liquidity and Capital Resources
 
Our primary source of liquidity and capital is our operating cash flow. We also maintain a committed revolving line of credit, which can be accessed as needed to supplement operating cash flow.  Based upon communication with our lead bank and information obtained from monitoring the status of our syndicated group, the Company currently knows of no circumstances that would limit access to our credit facility or require a change in our debt structure.


We believe that we have sufficient liquidity and operational flexibility to fund and actively manage our capital expenditures program to limit expenditures in an annual period to the cash flows available from operating activities. This policy has been in place throughout 2008. To the extent that capital expenditures or acquisitions require cash flow in excess of available funds, we intend to draw on our unused capacity under the existing revolving credit facility. As of September 30, 2008, the undrawn credit available to the Company was $229.0 million.  We have not received any indication from our lenders that draws under the credit facility are restricted below current availability at this time. We increased our borrowing base in the second quarter of 2008 to $400.0 million, and are currently in the process of affirming that borrowing base. We do not anticipate any significant change to the borrowing base as a result of the reaffirmation process, but we will advise the marketplace if such a change occurs.

Operating Cash Flow.  Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production, thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising natural gas prices. This derivative transaction activity will allow us the flexibility to continue to execute our capital plan if prices decline during the period in which our derivative transactions are in place.  The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities.  Based upon communications with these counterparties, the obligations under these transactions are expected to continue to be met.
 
Senior Secured Revolving Line of Credit.  In July 2005, BNP Paribas provided us 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, which initially was $275.0 million and was reset to $325.0 million in conjunction with the syndication.  The borrowing base is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements.  Accordingly, in May 2007, the borrowing base was adjusted to $350.0 million and in June 2008 was increased to $400.0 million.  Amounts outstanding under the Revolver bear interest at specified margins over the London Interbank Offered Rate (“LIBOR”) of 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 our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the SEC PV-10 pretax reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock 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. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At September 30, 2008, our current ratio was 3.1 to 1.0, as adjusted per current agreements, and our leverage ratio was 0.6 to 1.0.  In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties. We obtained a waiver of any breach of a loan covenant arising out of Calpine’s institution of Calpine’s fraudulent conveyance action against us and were in compliance with all covenants at September 30, 2008. All amounts drawn under the Revolver are due and payable on April 5, 2010.  Availability under the Revolver was $229.0 million at September 30, 2008.  At September 30, 2008, our weighted average borrowing rate was 4.69 %.
 
Second Lien Term Loan.   In July 2005, BNP Paribas provided us with a second lien term loan in the amount of $100.0 million (“Term Loan”). On September 27, 2005, we repaid $25.0 million of borrowings on the Term Loan, reducing the balance to $75.0 million and syndicated the Term Loan to a group of lenders including BNP Paribas. Borrowings under the Term Loan bore interest at LIBOR plus 4.00%.  The Term Loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We obtained a waiver of any breach of a loan covenant arising out of Calpine’s institution of Calpine’s fraudulent conveyance action against us and were in compliance with all covenants at September 30, 2008. The revised principal balance of the Term Loan is due and payable on July 7, 2010.
 
Cash Flows
 
The following table presents information regarding the change in our cash flow:
 
 
   
Nine Months Ended September 30,
  
   
2008
    
2007
  
   
(In thousands)
  
Cash flows provided by operating activities
   $ 326,301     $ 183,553  
Cash flows used in investing activities
     (197,172 )     (242,837 )
Cash flows provided by financing activities
     2,838       10,160  
Net increase (decrease) in cash and cash equivalents
   $ 131,967     $ (49,124 )
 
Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation and general and administrative expenses.  Net cash provided by operating activities (“Operating Cash Flow”) continued to be a primary source of liquidity and capital used to finance our capital program.
 
Cash flows provided by operating activities increased by $142.7 million for the nine months ended September 30, 2008 as compared to the same period for 2007.   The increase in 2008 primarily resulted from higher oil and gas production volumes and prices in 2008.  Our working capital increased from a deficit of $62.9 million to a positive $62.7 million and our cash balance increased $131.9 million over the same period in 2007 due to a decrease in capital spending of $66.0 million to $184.9 million, an increase in production of 8.6 Bcfe to 40.8 Bcfe from 32.2 Bcfe at September 30, 2007 and an increase in the average price per Mcfe of $2.28 to $10.12 per Mcfe from $7.84 per Mcfe at September 30, 2007.
 
Investing Activities.  The primary driver of cash used in investing activities is capital spending.
 
 Cash flows used in investing activities decreased by $45.7 million for the nine months ended September 30, 2008 as compared to the same period for 2007.  During the nine months ended September 30, 2008, we participated in the drilling of 112 gross wells as compared to the drilling of 149 gross wells in 2007.  Our capital spending in the nine months ended September 30, 2008 was approximately $155.3 million, primarily in our Lobo, Rockies and California regions and we acquired non-operating properties in the San Juan Basin for approximately $29.5 million.  Our capital spending during the same period in 2007 was $250.9 million, primarily in the Rocky Mountain and Lobo regions and an acquisition of properties located in the Sacramento Basin of approximately $38.7 million.
 
Financing Activities.  The primary driver of cash provided by financing activities are equity transactions associated with the exercise of stock options pursuant to the terms of our 2005 Long-Term Incentive Plan.  The repurchases of stock represented shares surrendered by certain employees to pay tax withholding upon vesting of restricted stock awards.  These repurchases are not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of common stock.
 
Capital Expenditures
 
Our capital expenditures for the nine months ended September 30, 2008 decreased by $66.0 million to $184.9 million, versus the same period in 2007.  During the nine months ended September 30, 2008, we participated in the drilling of 112 gross wells, spending approximately $155.4 million, with the majority of the wells being in the Lobo, Rockies and California regions and acquired non-operating properties in the San Juan Basin for approximately $29.5 million.
 
As discussed under Liquidity and Capital Resources, we expect that our positive operating cash flow, along with the availability under our Revolver, will be sufficient to fund our budgeted capital expenditures for 2008, which we currently project to be approximately $290 million.
 
We intend to be prudent and disciplined on our cost structure.  We are currently developing our capital expenditures budget for next year and will endeavor to maintain capital expenditures at a level that can be funded with operating cash flow.  In light of the current economic outlook and commodity prices, we expect to continue to focus on organic growth in core areas but shift capital expenditures from offshore assets to domestic onshore unconventional assets.  In the next year, we expect our production growth will be moderated by a priority on inventory generation.
 
Calpine Matters
 
On October 22, 2008, Calpine and the Company signed a Settlement Agreement which is subject to the Bankruptcy Court’s approval.  Under the terms of this Settlement Agreement, the parties have agreed to a global settlement resolving all disputes, in return for the payment of cash by Rosetta and the exchange of mutual consideration between the parties.  On October 24, 2008, Calpine filed a motion with the Bankruptcy Court requesting approval and authorization for its entry into the Settlement Agreement and the performance of its various obligations thereunder. The Settlement Agreement requires us to pay $12.4 million in cash to Calpine to resolve all outstanding legal disputes regarding various matters, including Calpine’s fraudulent conveyance lawsuit. The parties will exchange mutual releases which will resolve all pending disputes between the parties, whether relating to the oil and gas property purchase, Rosetta’s proofs of claim in the bankruptcy and its counter claims, Calpine’s obligation to convey remaining properties to Rosetta, or otherwise.

 
Also under the Settlement Agreement, we will pay the $84.6 million to close the original acquisition of the producing properties that Calpine had not yet conveyed to Rosetta and were also the subject of the Lawsuit. This $84.6 million is comprised of $67.6 million which we withheld from the July 2005 purchase price related to those properties that were not conveyed to Rosetta, as well as $17.0 million for post-closing adjustments that Rosetta had been prepared to pay in order to conclude all remaining conveyances.

In order to conclude the original transaction, Calpine will assume pursuant to Section 365 of the Bankruptcy Code the PSA Agreement as amended under the Settlement Agreement, to exclude certain preferential rights properties that were the subject of a dispute between Calpine and the third-party preferential right holders. Otherwise, the parties will fully complete our original acquisition of Calpine’s oil and gas business, including Calpine’s conveyance to us of all of the remaining oil and gas assets that were owned by Calpine as of May 1, 2005, including any such properties that were not listed on the schedules to the PSA Agreement.

In large part, the properties remaining to be conveyed to us consist of oil and gas properties which required consents from the lessors of those properties before being conveyed, but for which Calpine had not yet obtained consents prior to the July 7, 2005 closing.  As a result of the Settlement Agreement (if approved by the Bankruptcy Court), we will, in connection with these non-consent properties, retain the $35.2 million of estimated net revenues from these properties that had earlier been placed in suspense. Upon obtaining legal title to these properties, Rosetta will also add approximately 13 BCFE of proved reserves and 4 MMcfe/d of production.

Rosetta and Calpine have also agreed in the Settlement Agreement to convert Calpine’s right to extend its gas purchase agreement for the Company’s Sacramento Basin production for ten years (upon matching any offers of third parties) to a fixed, ten-year extension of that contract with certain cost adjustments in favor of Rosetta.  The Marketing Agreement by which Calpine Producer Services markets and sells Rosetta’s production, which was renewed and extended on July 1, 2007, will expire per its terms on or about June 30, 2009. The Marketing Agreement may be extended by up to 90 days to allow the Company to transition those services in-house or to another company.
 
Rosetta will use a portion of its excess cash from its 2008 operations to fund this settlement upon closing.  Closing is anticipated to occur by December 1, 2008, provided that the Bankruptcy Court approves Calpine’s motion to approve this settlement at the hearing scheduled for November 13, 2008, and no party objects to or appeals any order entered by the Bankruptcy Court approving the Settlement Agreement. If the settlement closing does not occur by December 31, 2008, or any extended date as may be mutually agreed among the parties, if applicable, the Settlement Agreement expires.
 
 
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
We are currently exposed to market risk primarily related to adverse changes in oil and natural gas prices and interest rates. We use derivative instruments to manage our commodity price risk caused by fluctuating prices.  We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosure About Market Risk” in our annual report filed on Form 10-K for the year ended December 31, 2007 and Note 4 included in Part I. Item 1. Financial Statements of this Form 10-Q.
 
For every $0.10 increase or decrease in natural gas prices, our earnings will be impacted by approximately $2.1 million, net of income taxes.  The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas”.  In addition, the majority of our capital expenditures is discretionary and could be curtailed if our cash flows decline from expected levels.
 
Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities.  Based upon communications with these counterparties, the obligations under these transactions are expected to continue to be met. Non performance risk was evaluated using current credit default swap values and default probabilities for each counterparty.  We currently know of no circumstances that would limit access to our credit facility or require a change in our debt or hedging structure.

 
Item 4.  Controls and Procedures
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2008.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2008, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
 
There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
PART II.  Other Information
Item 1.      Legal Proceedings
 
We are party to various oil and natural gas litigation matters arising out of the ordinary course of business.  While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the consolidated financial statements.

Calpine Bankruptcy
 
On December 20, 2005, Calpine Corporation and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (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 an adversary proceeding against the Company in the Bankruptcy Court (the “Lawsuit”).  Over the next fourteen months, Rosetta 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, will (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 Rosetta’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 “PSA Agreement”) by which Calpine’s oil and gas business was conveyed to the Company thus resulting in the parties honoring their obligations under the PSA Agreement on a going-forward basis.  This Settlement Agreement, although executed by both parties, does not become effective until the Bankruptcy Court enters a final order authorizing the execution of the Settlement Agreement and the performance of the obligations set forth therein. The settlement consists of $12.4 million payable in cash to Calpine to resolve all outstanding legal disputes regarding various matters, including Calpine’s fraudulent conveyance lawsuit. In addition, the Company will pay $84.6 million to close the original acquisition transaction of the producing properties that were the subject of the lawsuit. This $84.6 million consists of $67.6 million which the Company withheld from the purchase price related to properties that were not conveyed to the Company, as well as $17.0 million for post-closing adjustments.
 
Unless the Bankruptcy Court declines to authorize Calpine to enter into the executed Settlement Agreement or a party objects to and appeals any order entered by the Bankruptcy Court approving the Settlement Agreement, Rosetta anticipates the Settlement Agreement and the execution of the obligations required thereunder will be completed by the parties on or before December 1, 2008.  If the settlement closing does not occur by December 31, 2008, or any extended date as may be mutually agreed among the parties, if applicable, the Settlement Agreement expires.

Arbitration between Calpine/Rosetta and Pogo Producing Company
 
On October 27, 2008, the Company, Calpine and XTO Energy, Inc. (“XTO”), as the successor to Pogo Producing Company (“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 are being resolved within the framework of the settlement agreement with Calpine, which is subject to bankruptcy court approval.
 
Item 1A.  Risk Factors
 
Except for the risk factors set forth below, there have been no material changes in our risk factors from those disclosed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007.
 
Recent changes in the financial and credit markets may impact economic growth and oil and gas prices may continue to be adversely affected by general economic conditions.


Based on a number of economic indicators, it appears that growth in global economic activity has slowed substantially.  At the present time, the rate at which the global economy will slow has become increasingly uncertain.  A continued slowing of global economic growth, and, in particular, in the United States or China, will likely continue to reduce demand for oil and natural gas.  For example, on October 22, 2008, the price of oil on the New York Mercantile Exchange fell to $66.75 per barrel for December 2008 delivery, declining to a 16-month low and from a high of $147.27 per barrel in July 2008.  A reduction in the demand for, and the resulting lower prices of, oil and natural gas could adversely affect our results of operations.
 
We are subject to the full cost ceiling limitation and we may recognize downward revisions which will result in a write-down of our estimated net reserves and to our proved reserves in the future.
 
Under the full cost method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet.  If the net capitalized costs of our oil and gas properties exceed the cost ceiling, we are subject to a ceiling test write-down of our estimated net reserves to the extent of such excess.  If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower amortization expense in future periods.  For example, we recognized a ceiling test impairment of $129.1 million, net of tax, in the third quarter of 2008.
 
The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments.  However, the associated hedge adjusted market prices of oil and gas reserves that are included in the discounted present value of the reserves do not require judgment.  The ceiling calculation requires that prices and costs in effect as of the last day of the quarter be held constant.  However, we may not be subject to a write-down if prices increase subsequent to the end of a quarter in which a write-down might otherwise be required. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile.  Expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period.
 
In addition, write-downs of proved oil and natural gas properties may occur if we experience substantial downward adjustments to our estimated proved reserves.  For example, we recognized a downward revision to our proved reserves in the third quarter of 2008.   As we are continuing to evaluate and test our asset base, it is possible that we may recognize additional revisions to our proved reserves in the future.
 
The current deterioration in the credit markets, combined with a decline in commodity prices, may impact our capital expenditure level and also our counterparty risk.

While we seek to fund our capital expenditures primarily from cash flows from operating activities, we have in the past also drawn on unused capacity under our existing revolving credit facility for capital expenditures.  While we have not received any indication from our lenders that our ability to draw on our existing revolving credit facility has been restricted, it is possible that our borrowing base, which is based on our oil and gas reserves and is subject to review and adjustment on a semi-annual basis and other interim adjustments, may be reduced when it is reviewed.  A reduction in our ability to borrow under our existing revolving credit facility, combined with a reduction in cash flow from operating activities resulting from a decline in commodity prices, may require us to reduce our capital expenditures, which may in turn adversely affect our future growth prospects.  Furthermore, if we lack the resources to dedicate sufficient capital expenditures to our existing oil and gas leases, we may be unable to produce adequate quantities of oil and gas to retain these leases and they may expire due to a lack of production.  The loss of a sufficient number of leases could have a material adverse effect on our results of operations.
 
Additionally, while we believe that our existing production is adequately hedged with credit worthy counterparties, continued deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.
 
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended September 30, 2008
 
Period
  
Total Number of Shares Purchased (1)
    
Average Price Paid per Share
    
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
    
Maximum Number (or Approximate Dollar Value) of Shares that May yet Be Purchased Under the Plans or Programs
  
July 1 - July 31
     22,675     $ 24.98       -       -  
August 1 - August 31
     2,642       23.28       -       -  
September 1 - September 30
     4,520       20.55       -       -  
Total
     29,837     $ 24.16       -       -  
 
(1)
All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.  These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

 
Issuance of Unregistered Securities

None.
 
Item 3.   Defaults Upon Senior Securities
 
None.
 

Item 4.  Submission of Matters to a Vote of Security Holders
 
None.
 
Item 5.  Other Information
 
(a)
Rosetta reported on Form 8-K during the quarter covered by this report all information required to be reported on such form.
 
(b)
There have been no material changes to the procedures by which securities holders may recommend nominees to our board of directors since our most recent disclosure of such procedures contained in our Annual Report on Form 10-K for the year ended December 31, 2007 and our definitive proxy statement filed with respect to our 2008 annual meeting.
 

Item 6.  Exhibits
 
 
3.1
Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
 
 
3.2
Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
 
 
4.1
Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
 
31.1
Certification of Periodic Financial Reports by Randy L. Limbacher in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
31.2
Certification of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
32.1
Certification of Periodic Financial Reports by Randy L. Limbacher and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350
____________________________________


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
ROSETTA RESOURCES INC.
 
  
 
By:
/s/ MICHAEL J. ROSINSKI
  
 
Michael J. Rosinski
  
 
Executive Vice President and Chief Financial Officer
       
 
(Duly Authorized Officer and Principal Financial Officer)
 
Date: November 7, 2008


ROSETTA RESOURCES INC.
 
EXHIBIT INDEX
 
Exhibit Number
  
Description
 
Certification of Periodic Financial Reports by Randy L. Limbacher in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
Certification of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
Certification of Periodic Financial Reports by Randy L. Limbacher and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350
 
 
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