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 March 31, 2009

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o  No o
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
 
Large accelerated filer x
  
Accelerated filer o
     
Non-Accelerated filer o
  
Smaller Reporting Company o
(Do not check if smaller reporting company)
    
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o   No x
 
The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of May 6, 2009 was 52,270,286.
 

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

   
March 31,
2009
    
December 31,
2008
  
   
(Unaudited)
        
Assets
            
Current assets:
            
Cash and cash equivalents
   $ 32,971     $ 42,855  
Restricted cash
     1,421       1,421  
Accounts receivable
     29,774       41,885  
Derivative instruments
     56,572       34,742  
Prepaid expenses
     4,411       5,046  
Other current assets
     4,657       4,071  
Total current assets
     129,806       130,020  
Oil and natural gas properties, full cost method, of which $44.4 million at March 31, 2009 and $50.3 million at December 31, 2008 were excluded from amortization
     1,934,708       1,900,672  
Other fixed assets
     11,220       9,439  
      1,945,928       1,910,111  
Accumulated depreciation, depletion, and amortization, including impairment
     (1,359,096 )     (935,851 )
Total property and equipment, net
     586,832       974,260  
                 
Deferred loan fees
     956       1,168  
Deferred tax asset
     180,752       42,652  
Other assets
     8,333       6,278  
Total other assets
     190,041       50,098  
Total assets
   $ 906,679     $ 1,154,378  
                 
Liabilities and Stockholders' Equity
                
Current liabilities:
                
Accounts payable
   $ 1,797     $ 2,268  
Accrued liabilities
     21,169       48,824  
Royalties payable
     13,762       17,388  
Derivative instruments
     506       985  
Prepayment on gas sales
     9,846       19,382  
Deferred income taxes
     20,885       12,575  
Total current liabilities
     67,965       101,422  
Long-term liabilities:
                
Long-term debt
     305,000       300,000  
Asset retirement obligation
     29,886       26,584  
Total liabilities
     402,851       428,006  
                 
Commitments and contingencies (Note 9)
     -       -  
                 
Stockholders' equity:
                
Preferred stock,  $0.001 par value; authorized 5,000,000 shares; no shares issued in 2009 or 2008
     -       -  
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 51,134,787 shares and 51,031,481 shares at March 31, 2009 and December 31, 2008, respectively
     51       51  
Additional paid-in capital
     774,593       773,676  
Treasury stock, at cost; 179,003 and 155,790 shares at March 31, 2009 and December 31, 2008, respectively
     (3,219 )     (2,672 )
Accumulated other comprehensive income
     39,298       24,079  
Accumulated deficit
     (306,895 )     (68,762 )
Total stockholders' equity
     503,828       726,372  
Total liabilities and stockholders' equity
   $ 906,679     $ 1,154,378  


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

3

Rosetta Resources Inc.
Consolidated Statement of Operations
(In thousands, except per share amounts)
(Unaudited)

   
Three Months Ended
March 31,
  
   
2009
    
2008
  
Revenues:
            
Natural gas sales
   $ 74,223     $ 112,445  
Oil sales
     5,218       15,888  
Total revenues
     79,441       128,333  
Operating Costs and Expenses:
                
Lease operating expense
     18,041       13,414  
Depreciation, depletion, and amortization
     44,400       51,414  
Impairment of oil and gas properties
     379,462       -  
Treating and transportation
     1,702       1,305  
Marketing fees
     317       748  
Production taxes
     1,323       3,437  
General and administrative costs
     9,373       12,107  
Total operating costs and expenses
     454,618       82,425  
Operating income (loss)
     (375,177 )     45,908  
                 
Other (income) expense
                
Interest expense, net of interest capitalized
     2,535       3,554  
Interest income
     (51 )     (239 )
Other (income) expense, net
     (150 )     (41 )
Total other expense
     2,334       3,274  
                 
Income (loss) before provision for income taxes
     (377,511 )     42,634  
Income tax expense (benefit)
     (139,378 )     15,145  
Net income (loss)
   $ (238,133 )   $ 27,489  
                 
Earnings (loss) per share:
                
Basic
   $ (4.68 )   $ 0.54  
Diluted
   $ (4.68 )   $ 0.54  
                 
Weighted average shares outstanding:
                
Basic
     50,920       50,485  
Diluted
     50,920       50,719  


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

4

Rosetta Resources Inc.
Consolidated Statement of Cash Flows
(In thousands)
(Unaudited)
 
   
Three Months Ended
March 31,
  
   
2009
    
2008
  
Cash flows from operating activities
            
Net income (loss)
     (238,133 )     27,489  
Adjustments to reconcile net income to net cash from operating activities
                
Depreciation, depletion and amortization
     44,400       51,414  
Impairment of oil and gas properties
     379,462       -  
Deferred income taxes
     (138,826 )     15,145  
Amortization of deferred loan fees recorded as interest expense
     212       295  
Stock compensation expense
     917       273  
Change in operating assets and liabilities:
                
Accounts receivable
     12,111       (7,592 )
Prepaid expenses
     635       717  
Other current assets
     (586 )     162  
Other assets
     (107 )     187  
Accounts payable
     (471 )     3,332  
Accrued liabilities
     (6,910 )     720  
Royalties payable
     (13,162 )     11,103  
Net cash provided by operating activities
     39,542       103,245  
Cash flows from investing activities
                
Acquisition of oil and gas properties
     (3,844 )     -  
Purchases of oil and gas assets
     (50,018 )     (61,879 )
Other
     (16 )     2  
Net cash used in investing activities
     (53,878 )     (61,877 )
Cash flows from financing activities
                
Borrowings on revolving credit facility
     5,000       -  
Proceeds from stock options exercised
     -       1,488  
Purchases of treasury stock
     (548 )     (179 )
Net cash provided by financing activities
     4,452       1,309  
                 
Net increase (decrease) in cash
     (9,884 )     42,677  
Cash and cash equivalents, beginning of period
     42,855       3,216  
Cash and cash equivalents, end of period
   $ 32,971     $ 45,893  
                 
Supplemental non-cash disclosures:
                
Capital expenditures included in accrued liabilities
   $ 7,170     $ 19,254  


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

5

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

These interim financial statements have not been audited.  However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments necessary for a fair presentation of the financial statements have been included.  Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year.  In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America.  These financial statements and notes should be read in conjunction with the Company’s audited Consolidated Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 ("2008 Annual Report").

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

(2)  Summary of Significant Accounting Policies
 
The Company has provided a discussion of significant accounting policies, estimates and judgments in its Annual Report on Form 10-K for the year ended December 31, 2008.
 
Principles of Consolidation.  The accompanying consolidated financial statements as of March 31, 2009 and December 31, 2008 and for the three months ended March 31, 2009 and 2008 contain the accounts of the Company and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.
 
Recent Accounting Developments
 
The following recently issued accounting developments may impact the Company in future periods.

Business Combinations. In December 2007, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 141(R), “Business Combinations” (“SFAS No. 141(R)”).  SFAS No. 141(R) broadens the guidance of SFAS No. 141, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses.  It broadens the fair value measurement and recognition of assets acquired, liabilities assumed, and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed.  SFAS No. 141(R) also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases.  This could cause us to expense transaction costs for future oil and gas property purchases that we have historically capitalized.  Additionally, SFAS No. 141(R) expands the required disclosures to improve the statement users’ abilities to evaluate the nature and financial effects of business combinations.  SFAS No. 141(R) is effective for business combinations for which the acquisition date is on or after January 1, 2009.  The adoption of SFAS No. 141(R) did not have a significant impact on our consolidated financial position, results of operations or cash flows.

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 adoption of SFAS No. 160 did not have a significant impact on our consolidated financial position, results of operations or cash flows.  
 
Disclosures about Derivative Instruments and Hedging Activities.   In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (“SFAS No. 161”), which is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures.  This statement is effective for fiscal years beginning after November 15, 2008.  We adopted the disclosure requirements of SFAS No. 161 beginning January 1, 2009.  See Note 4 - Commodity Hedging Contracts and Other Derivatives.

6

Fair Value Measurements.  In February 2008, the FASB 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.  Beginning January 1, 2009, we implemented FSP No. 157-2 for nonfinancial assets and liabilities.  The adoption of FSP No. 157-2 did not have an impact on our consolidated financial position, results or operations or cash flows.  In October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP No. 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 No. 157-3 did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In April 2009, the FASB issued three FSPs to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157.  FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities.  These three FSPs are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  The Company is currently evaluating the impact of these FSPs and does not expect their adoption to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
 
Oil and Gas Reporting Requirements.  In December 2008, the SEC released Release No. 33-8995, “Modernization of Oil and Gas Reporting” (the “Release”).  The disclosure requirements under this Release will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes.  Companies will also be allowed to disclose probable and possible reserves in Securities and Exchange Commission ("SEC") filings.  In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit.  The new disclosure requirements become effective for the Company beginning with our annual report on Form 10-K for the year ending December 31, 2009.  We are currently evaluating the impact of this Release on our oil and gas accounting disclosures.

(3) Property, Plant and Equipment
 
The Company’s total property, plant and equipment consists of the following:

   
March 31,
2009
    
December 31,
2008
  
   
(In thousands)
  
Proved properties
   $ 1,852,461     $ 1,813,527  
Unproved/unevaluated properties
     44,387       50,252  
Gas gathering systems and compressor stations
     37,860       36,893  
Other
     11,220       9,439  
Total oil and natural gas properties
     1,945,928       1,910,111  
Less: Accumulated depreciation, depletion, and amortization, including impairment
     (1,359,096 )     (935,851 )
Total property and equipment, net
   $ 586,832     $ 974,260  


The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.0 million and $1.4 million of internal costs for the three months ended March 31, 2009 and 2008, respectively.
 
Included in the Company’s oil and gas properties are asset retirement costs of $24.6 million and $23.2 million at March 31, 2009 and December 31, 2008, respectively.

7

Oil and gas properties include costs of $44.4 million and $50.3 million at March 31, 2009 and December 31, 2008, respectively, which 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 March 31, 2009, which were based on a Henry Hub price of $3.63 per MMBtu and a West Texas Intermediate oil price of $46.00 per Bbl (adjusted for basis and quality differentials) compared to prices of $5.71 per MMBtu and $41.00 per Bbl at December 31, 2008. Cash flow hedges of natural gas production in place at March 31, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax).  Based upon this analysis, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009.  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 following financial fixed price swap and costless collar transactions were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations at March 31, 2009:

Settlement
Period
Derivative
Instrument
Hedge
Strategy
  
Notional Daily Volume
MMBtu
    
Total of Notional Volume
MMBtu
    
Average Floor/Fixed Prices
MMBtu
    
Average Ceiling Prices MMBtu
    
Natural Gas Production Hedged (1)
    
Fair Market Value
Asset/(Liability)
(In thousands)
  
2009
Swap
Cash flow
     52,141       14,338,775     $ 7.65     $ -       37 %   $ 49,019  
2009
Costless Collar
Cash flow
     5,000       1,375,000       8.00       10.05       4 %     5,061  
2010
Swap
Cash flow
     10,000       3,650,000       8.31       -       9 %     9,053  
                  19,363,775                             $ 63,133  

 
(1)
Estimated based on anticipated future gas production.

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

Settlement
Period
Derivative
Instrument
Hedge
Strategy
  
Average Fixed Rate
    
Fair Market Value
Asset/(Liability)
(In thousands)
  
2009
Swap
Cash flow
    
4.55%
     $ (506 )

The Company’s current cash flow hedge positions are with counterparties who are also lenders in the Company’s credit facilities.  This eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations.  As of March 31, 2009, the Company made no deposits for collateral.
 
The following table sets forth the results of hedge transaction settlements for the respective period for the Consolidated Statement of Operations:

   
Three Months Ended March 31,
  
Natural Gas
  
2009
    
2008
  
Quantity settled (MMBtu)
     5,142,690       6,156,216  
Increase (decrease) in natural gas sales revenue (In thousands)
   $ 15,357     $ (701 )
Interest Rate Swaps
                
(Increase) decrease in interest expense (In thousands)
   $ (512 )   $ 125  

 
The Company expects to reclassify gains of $56.1 million based on market pricing as of March 31, 2009 to earnings from the balance in accumulated other comprehensive income on the Consolidated Balance Sheet during the next twelve months.
 
At March 31, 2009, the Company had derivative assets of $63.1 million, of which $6.6 million is included in other assets on the Consolidated Balance Sheet.  The Company also had derivative liabilities of $0.5 million included in current liabilities on the Consolidated Balance Sheet at March 31, 2009.

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

SFAS No. 133 requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the statement of financial position.  In accordance with SFAS No. 133, the Company designates commodity forward contracts as cash flow hedges of forecasted sales of natural gas and oil production and interest rate swaps as cash flow hedges of interest rate payments due under variable-rate borrowings.

Additional Disclosures about Derivative Instruments and Hedging Activities

Cash Flow Hedges

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

As of March 31, 2009, the Company had the following outstanding commodity forward contracts that were entered into to hedge forecasted natural gas sales:

   
Notional Volume
Commodity
  
(MMBtu)
     
Natural gas
  
19,363,775


As of March 31, 2009, the total notional amount of the Company’s receive-variable/pay-fixed interest rate swaps was $50.0 million.  The Company includes the realized gain or loss on the hedged items (that is, variable-rate borrowings) in the same line item – interest expense, net of interest capitalized – as the offsetting gain or loss on the related interest rate swaps.

Information on the location and amounts of derivative fair values in the statement of financial position and derivative gains and losses in the statement of financial performance as of March 31, 2009 is as follows:

9
 
 
Fair Values of Derivative Instruments
  
 
Derivative Assets
      
Derivative Liabilities
  
 
March 31, 2009
      
March 31, 2009
  
 
Balance Sheet Location
  
Fair Value
      
Balance Sheet Location
  
Fair Value
  
Derivatives designated as hedging instruments under SFAS No. 133
    
(in thousands)
          
(in thousands)
  
Interest rate swap
Derivative Instruments
   $ -      
Derivative Instruments
   $ 506  
Commodity contracts
Derivative Instruments
     56,572      
Derivative Instruments
     -  
Commodity contracts
Other assets
     6,561      
Derivative Instruments
     -  
Total derivatives designated as hedging instruments under SFAS No. 133
     $ 63,133           $ 506  
Total derivatives not designated as hedging instruments under SFAS No. 133
     $ -           $ -  
Total derivatives
     $ 63,133           $ 506  



Derivatives in SFAS No. 133 Cash Flow Hedging Relationships
  
Amount of Gain or (Loss) Recognized
in OCI on Derivative
(Effective Portion) 
2009
 
Location of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
  
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income
(Effective Portion)
2009
  
               
Interest rate swap
   $ (33 )
Interest expense, net of interest capitalized
   $ (512 )
Commodity contracts
     39,133  
Natural gas sales
     15,357  
                   
Total
   $ 39,100       $ 14,845  
 
There were no gains or losses recognized in income representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness.

Subsequent Event

As of April 30, 2009, the Company has entered into a series of interest rate swap agreements to hedge the interest rates on $80.0 million of its outstanding debt from October 2009 through December 2010 at an average interest rate of 1.26%.
 
(5)  Fair Value Measurements
 
The Company adopted SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) effective January 1, 2008 for financial assets and liabilities and effective January 1, 2009 for non-financial assets and liabilities.  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. 

10

Level 3 instruments include money market funds, natural gas swaps, natural gas zero cost collars and interest rate swaps.  The Company’s money market funds represent cash equivalents whose investments are limited to United States Government Securities, securities backed by the United States Government, or securities of United States Government agencies.  The fair value represents cash held by the fund manager as of March 31, 2009.  The Company identified the money market funds as Level 3 instruments due to the fact that quoted prices for the underlying investments cannot be obtained and there is not an active market for the underlying investments.  The Company utilizes counterparty and third party broker quotes to determine the valuation of its derivative instruments.  Fair values derived from counterparties and brokers are further verified using the closing price as of March 31, 2009 for the relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location.  
 
The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009. 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 March 31, 2009
(In thousands)
  
   
Level 1
    
Level 2
    
Level 3
    
Total
  
Assets (Liabilities):
                        
Money market funds
     -       -       5,032       5,032  
Commodity derivative contracts
     -       -       63,133       63,133  
Interest rate swap contracts
     -       -       (506 )     (506 )
Total
     -       -       67,659       67,659  


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 of the assets and liabilities classified as Level 3 in the fair value hierarchy during the first quarter of 2009. Level 3 instruments presented in the table consist of net derivatives that, in management’s judgment, reflect the assumptions a marketplace participant would have used at March 31, 2009.

   
Derivatives Asset (Liability)
    
Money Market Funds
Asset (Liability)
    
Total
  
Balance as of January 1, 2009
   $ 38,372     $ 5,025     $ 43,397  
Total (gains) losses (realized or unrealized)
                        
included in earnings
     -       7       7  
included in other comprehensive income
     39,100       -       39,100  
Purchases, issuances and settlements
     (14,845 )     -       (14,845 )
Transfers in and out of Level 3
     -       -       -  
Balance as of March 31, 2009
   $ 62,627     $ 5,032     $ 67,659  
                         
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at March 31, 2009
   $ -     $ -     $ -  
 
The carrying amount of long-term debt reported in the consolidated balance sheet at March 31, 2009 is $305.0 million.  The Company adjusted the fair value measurement of its long-term debt as of March 31, 2009, in accordance with SFAS No. 157 using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality, and risk profile.  The Company has determined the fair market value of its debt to be $284.4 million at March 31, 2009. 

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(6)  Asset Retirement Obligation

Activity related to the Company’s asset retirement obligation (“ARO”) is as follows:
 
   
Three Months Ended
March 31, 2009
  
   
(In thousands)
  
ARO as of December 31, 2008
   $ 27,944  
Revision of previous estimates
     (394 )
Liabilities incurred during period
     1,734  
Liabilities settled during period
     -  
Accretion expense
     602  
ARO as of March 31, 2009
   $ 29,886  

(7)  Long-Term Debt
 
At March 31, 2009, the Company’s credit facilities consisted of a senior secured revolving line of credit (“Revolver”) of 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 (“Term Loan”).
 
As of March 31, 2009, the Company had total outstanding borrowings of $305.0 million.  At March 31, 2009, the Company’s weighted average borrowing rate was 2.93%.  Net borrowing availability under the Revolver was $170.0 million at March 31, 2009.  The Company was in compliance with all covenants at March 31, 2009.
 
As of March 31, 2009, all amounts drawn under the Revolver were due and payable on April 5, 2010.  The principal balance associated with the Term Loan was due and payable on July 7, 2010.
 
Subsequent Event
 
On April 9, 2009, the Company entered into an Amended and Restated Senior Revolving Credit Agreement with BNP Paribas, as Administrative Agent, and the other lenders identified therein (“Restated Revolver”) providing a senior secured revolving line of credit in the amount of up to $600.0 million, replacing the prior Revolver, and extending its term until July 1, 2012. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements. As extended, the borrowing base under the Restated Revolver is currently set at $375.0 million. The next borrowing base review is scheduled for the fall of 2009. Amounts outstanding under the Restated Revolver bear interest, as amended, at specified margins over London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of the Company’s domestic subsidiaries, and a pledge of 100% of the membership interests of domestic subsidiaries. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company paid a facility fee on the total commitment of $4.6 million. As of May 8, 2009, the Company has $165.0 million available for borrowing under the revolving line of credit.

On April 9, 2009, the Company also entered into an Amended and Restated Second Lien Term Loan Agreement with BNP Paribas, as Administrative Agent, and other lenders identified therein (“Restated Term Loan”) replacing the prior Term Loan extending its term until October 2, 2012. Borrowings under the Restated Term Loan were initially set at $75.0 million and bear interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%. The Restated Term Loan had an option to increase fixed and floating rate borrowings by up to $25.0 million to $100.0 million prior to May 9, 2009. The Company exercised this option on April 21, 2009 and the increased borrowings consisted of $5.0 million of floating rate borrowings and $20.0 million of fixed rate borrowings at 13.75%. The loan is collateralized by second priority liens on substantially all of the Company’s assets. The Company is subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly. In addition, the Company is subject to covenants, including limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company paid an original issue discount of $1.8 million and a facility fee of $0.7 million on the total commitment.

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(8)  Income Taxes

As of March 31, 2009, the Company had no unrealized tax benefits.  The effective tax rate for the three months ended March 31, 2009 was 36.9%.  The effective tax rate for the three months ended March 31, 2008 was 35.5%. 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.  The income tax benefit at March 31, 2009 includes a $1.0 million adjustment related to 2008 state taxes.
 
The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.  At March 31, 2009, the Company has a deferred tax asset of approximately $180.7 million resulting primarily from the difference between the recorded basis and tax basis of its oil and natural gas properties.  The Company believes this deferred tax asset will be realized through the generation of future taxable income.

(9)  Commitments and Contingencies

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

(10)  Comprehensive Income (Loss)

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

   
Three Months Ended March 31,
  
   
2009
    
2008
  
   
(In thousands)
  
Accumulated other comprehensive income (loss) beginning of period
         $ 24,079           $ (7,225 )
Net income (loss)
   $ (238,133 )           $ 27,489          
                                 
Change in fair value of derivative hedging instruments
     39,100               (66,665 )        
Hedge settlements reclassed to income
     (14,845 )             826          
Tax effect related to hedges
     (9,036 )             24,525          
Total other comprehensive income (loss)
     15,219       15,219       (41,314 )     (41,314 )
                                 
Comprehensive loss
     (222,914 )             (13,825 )        
Accumulated other comprehensive income (loss)
           $ 39,298             $ (48,539 )
 
(11)  Earnings (Loss) Per Share

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

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

   
Three Months Ended
March 31,
  
   
2009
    
2008
  
   
(In thousands)
  
Basic weighted average number of shares outstanding
     50,920       50,485  
Dilution effect of stock option and awards at the end of the period
     -       234  
Diluted weighted average number of shares outstanding
     50,920       50,719  
                 
Anti-dilutive stock awards and shares
     1,441       311  


Because the Company reported a loss from continuing operations for the quarter ended March 31, 2009, no unvested stock awards and options were included in computing loss per share because the effect was anti-dilutive.  In computing loss per share, no adjustments were made to reported net loss.

(12)  Stock-Based Compensation

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

Compensation expense associated with PSUs that continue to vest based on future performance is based on the grant-date fair value of the Company’s common stock. The compensation expense will be re-measured at the end of each reporting period through settlement using the quarter-end closing common stock prices to reflect the current fair value. Compensation expense is to be recognized ratably over the performance period based on the Company’s estimated achievement of the established performance metrics. Compensation expense will only be recognized for those awards for which it is probable that the performance metrics will be achieved and which are expected to vest. The compensation expense will be estimated based upon an assessment of the probability that the performance metrics will be achieved, current and historical forfeitures, and the Board’s anticipated vesting percentage.
 
A summary of the Company’s PSUs is presented in the table below.
 
   
Quarter Ended March 31, 2009
  
             
   
Units
    
Fair Value per Unit
  
Unvested, beginning of period
     -     $ -  
Granted
     350,698       5.27  
Vested
     -       -  
Forfeited
     -       -  
Unvested, end of period
     350,698     $ 5.27  

For the quarter ended March 31, 2009, the Company did not recognize any compensation expense associated with the new PSUs granted on March 3, 2009 with a three-year performance period.
 
(13)  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 six main geographic areas all within the United States or its territorial waters. Geographic revenue and property, plant and equipment information below are based on physical location of the assets at the end of each period.

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Oil and Natural Gas Revenue

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

   
Three Months Ended
March 31,
  
   
2009
    
2008
  
   
(In thousands)
  
California
   $ 19,180     $ 36,771  
Rockies
     6,610       6,850  
South Texas
     23,182       44,233  
Texas State Waters
     4,262       15,032  
Other Onshore
     6,026       11,280  
Gulf of Mexico
     4,824       14,868  
Gain (loss) on hedges
     15,357       (701 )
 Total revenue
   $ 79,441     $ 128,333  

Oil and Natural Gas Properties

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

   
March 31, 2009
    
December 31, 2008
  
   
(In thousands)
  
California
   $ 625,448     $ 619,593  
Rockies
     182,089       175,294  
South Texas
     733,534       712,464  
Texas State Waters
     65,758       65,085  
Other Onshore
     176,649       171,855  
Gulf of Mexico
     151,230       156,381  
Other
     11,220       9,439  
Total property and equipment
   $ 1,945,928     $ 1,910,111  

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking information regarding Rosetta that is intended to be covered by the “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology.
 
The forward-looking statements contained in this report are largely based on our expectations for the future, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. Risk Factors in Part II. of this report.  We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances, or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:  

–
conditions in the energy and economic markets;
 
 
–
the supply and demand for natural gas and oil;
 
 
–
the price of natural gas and oil;

–
potential reserve revisions;  
 
 
–
changes or advances in technology;
 
 
–
reserve levels;
 
 
–
inflation;
 
 
–
the availability and cost of relevant raw materials, goods and services;
 
 
–
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;

16

–
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;
 
 
–
lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;
 
 
–
the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; and
 
 
–
any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.

Overview

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

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

·
Production on an equivalent basis increased 4%;

·
Total revenue, including the effects of hedging, decreased $48.9 million;

·
Average realized gas prices including hedging decreased $3.28 per Mcf, or 38%, to $5.46 per Mcf at March 31, 2009 from $8.74 per Mcf at March 31, 2008 and average realized oil prices decreased $61.11 per Bbl, or 61%, to $38.99 per Bbl at March 31, 2009 from $100.10 per Bbl at March 31, 2008;

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

·
Net income decreased $265.6 million to a net loss of $238.1 million; net income excluding impairment would have decreased $27.5 million to a break-even position;

·
Diluted earnings per share decreased $5.22 to diluted loss per share of $4.68; diluted earnings per share excluding impairment would have decreased from $0.54 per share to a break-even position; and

·
21 gross and 16 net wells were drilled with a net success rate of 88%.

In early 2008, we began a strategic shift toward a business model that we believed could generate more sustainable, predictable performance over time by focusing on positions and programs in unconventional onshore domestic basins.  These basins are characterized by having lower hydrocarbon risk project inventory and repeatable programs.  Our strategy shift is accompanied by goals to deliver, over time, both acceptable rates of production growth, as well as growth in proved, probable and possible reserves in excess of historical performance.  The timing of and extent to which we can implement this strategy shift will depend on several factors, most notably commodity prices, availability of and access to credit, and ability to capture organic and inorganic opportunities.
 
Under commodity price scenarios of approximately $6.00 per Mcfe or greater, we believe we can successfully implement our strategy shift because of some inherent strengths. Of note, we believe our core existing onshore assets have upside that has not been fully analyzed through an unconventional resource approach. 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 financial and capital allocation approach that we believe allows us to adapt to the unpredictable industry cycles and manage through the current economic downturn. These factors do not ensure our success in executing our strategy shift, but we believe they provide a competitive advantage towards executing our strategy shift over the longer term.  Under an extended period of commodity prices below $5.00 per Mcfe, our ability to implement our business strategy would likely be constrained.

17

The current plan for implementing our business strategy is to pursue, over time, both organic and inorganic opportunities that meet the Company’s criteria for funding, particularly inventory potential and attractive financial returns.  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.  These studies are continuing in 2009.  We also actively study new domestic basins where we believe the Company can compete successfully.  While we have a preference for organic opportunities, we have expanded our capability to evaluate and pursue large and small acquisition opportunities that make sense for the Company. We believe this balanced approach is needed for long-term success.  Our ability to execute both organic and inorganic activities will depend on market conditions, including availability of acquisition opportunities, relative valuations, and access to funding sources that could include proceeds from non-core asset divestitures.  We continue to test the market for non-core divestitures, but are not driven to sell assets unless values are compelling.
 
We entered 2009 in a position to execute our business plan and effect our desired goals, subject to commodity prices and market factors.  These factors generally weakened during the first quarter of 2009.  The outlook for commodity prices continues to be uncertain due to a sluggish economic outlook for the year, which has resulted in reduced demand for natural gas and commodity oversupply.  Given this outlook, we continue to exercise prudence and caution with our capital spending in order to preserve liquidity and maximize the financial position of our company.  The priority for our 2009 organic spending is to spend less than our internally generated cash flow.  We have the discretion to adjust capital spending plans throughout the year in response to market conditions and the availability of proceeds from possible divestitures.  These adjustments may include shutting down our core area drilling programs until such time as services costs contract and/or commodity prices recover.  We expect our organic capital spending level, while in flux, will be significantly reduced compared to our preliminary 2009 budget and 2008 actual spending.  At this time, we intend to drill a limited number of Lobo wells in South Texas, continue a recompletion program in the Sacramento Basin, and test two new exploratory play concepts in the Bakken Shale in the Alberta Basin and the Eagle Ford Shale in South Texas.  Given the uncertainty in our capital program and possible divestiture results, it is not practical to provide definitive production guidance for 2009.  However, assuming $80.0 million of organic capital spending in 2009, we would expect to achieve between 130 – 140 MMcfe/d of full-year 2009 production, excluding acquisitions and divestitures.

We are operating in one of the most challenging business environments in recent history.  The credit crisis, declining oil prices, lower natural gas prices and a weakening global economic outlook are all adversely impacting the business environment.  We intend to work continuously with our lenders to effectively stay abreast of market and creditor conditions to ensure prudent and timely decisions should market conditions deteriorate further.  With the amendments and restatements of our credit agreements in April 2009, we extended the maturities of our credit facilities to 2012.  We believe that we have sufficient liquidity and operational flexibility to carry out a prudent organic capital expenditures program in 2009.  Future year capital programs will be determined by available cash flows from operating activities and access to liquidity.  We maintain the option to undertake property divestitures to generate cash and exit non-core areas.  Proceeds from these activities could be used for general purposes, which could include paying down debt or making acquisitions of assets of interest.  Our capital expenditures are primarily in areas where we act as operator and have high working interests. As a result, we do not believe we have significant exposure to joint interest partners who may be unable to fund their portion of any capital program, but we are monitoring partner situations in light of the current economic environment.  We are actively working with service companies and suppliers to mitigate costs, and we are examining all cash costs for improved efficiency.
 
To the extent that capital expenditures or prudent acquisitions require cash flow in excess of available funds, we would consider drawing on our unused capacity under our existing revolving credit facility. As of March 31, 2009, the undrawn credit available to us was $170.0 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 recently affirmed our borrowing base at $375.0 million reduced from $400.0 million. The next borrowing base review is scheduled for the fall of 2009. We also extended the terms of both our revolving credit facility and second lien term loan by over two years.  Additionally, we amended and restated our second lien term loan, which allowed us to increase our borrowings under the facility from $75.0 million to $100.0 million.  We believe these actions provide capacity and time for managing through the current downturn.

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

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

Critical Accounting Policies and Estimates

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

We assess the impairment for oil and natural gas properties for the full cost accounting method on a quarterly basis using a ceiling test to determine if impairment is necessary. If the net capitalized costs of oil and natural gas properties exceed the cost 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 of gas and oil at March 31, 2009, which were based on a Henry Hub price of $3.63 per MMBtu and a West Texas Intermediate oil price of $46.00 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax).  Based upon this analysis, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009.  Due to the volatility of commodity prices, should natural gas prices continue to decline in the future, it is possible that another write-down of our oil and gas properties could occur.

We have entered into financial fixed price swaps with prices ranging from $6.81 per MMBtu to $8.58 per MMBtu covering approximately 14.3 million MMBtu, or 37%, of our 2009 production and 3.7 million MMBtu, or 9%, of our 2010 production.  We have also entered into costless collar transactions covering approximately 1.4 million MMBtu of our 2009 production.  The costless collars have an average floor price of $8.00 per MMBtu and an average ceiling price of $10.05 per MMBtu.   Approximately 94% of total hedged transactions represent hedged prices of commodities at the PG&E Citygate and Houston Ship Channel.  Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities.  This arrangement eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with our hedge related credit obligations.  As of March 31, 2009, we made no deposits for collateral.  Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of March 31, 2009.   We evaluated non-performance risk using current credit default swap values and default probabilities for each counterparty and recorded a downward adjustment to the fair value of our derivative assets in the amount of $1.5 million at March 31, 2009.

We utilize counterparty and third party broker quotes to determine the valuation of our derivative instruments.  Fair values derived from counterparties and brokers are further verified using the settled price as of March 31, 2009 for NYMEX futures contracts and exchange traded contracts for each derivative settlement location.  We have used this valuation technique since the adoption of SFAS No. 157 on January 1, 2008 and we have made no changes or adjustments to our technique since then.  We mark to market on a quarterly basis.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 2 to the Consolidated Financial Statements in Part I. Item 1. Financial Statements of this Form 10-Q.

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 three months of 2009 was $79.4 million, including the effects of hedging, which is a decrease of $48.9 million, or (38%), from the three months ended March 31, 2008. Natural gas sales, excluding the effects of hedging, decreased by $54.3 million comprised of a $60.4 million decrease attributable to a 51% decrease in natural gas prices partially offset by $6.1 million increase attributable to a 5% increase in production volumes.  Oil sales decreased by $10.7 million of which $8.2 million was associated with a decrease in the price of oil and $2.5 million was associated with decreased production.  Approximately 93% of our revenue was attributable to natural gas sales on total volumes of 14.4 Bcfe in the first quarter of 2009.

19

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

   
Three Months Ended
March 31,
  
   
2009
    
2008
    
% Change
Increase/
(Decrease)
  
   
(In thousands, except percentages and per unit amounts)
  
Natural gas sales
   $ 74,223     $ 112,445       (34 %)
Oil sales
     5,218       15,888       (67 %)
Total revenues
   $ 79,441     $ 128,333       (38 %)
                         
Production:
                        
Gas (Bcf)
     13.6       12.9       5 %
Oil (MBbls)
     133.8       158.7       (16 %)
Total Equivalents (Bcfe)
     14.4       13.8       4 %
                         
$ per unit:
                        
Avg. Gas Price per Mcf
   $ 5.46     $ 8.74       (38 %)
Avg. Gas Price per Mcf excluding hedges
     4.33       8.80       (51 %)
Avg. Oil Price per Bbl
     38.99       100.10       (61 %)
Avg. Revenue per Mcfe including hedges
     5.52       9.29       (41 %)

Natural Gas.  For the three months ended March 31, 2009, natural gas revenue decreased by $38.2 million, including the realized impact of derivative instruments, from the comparable period in 2008, to $74.2 million from $112.4 million. This decrease is primarily due to the significant decline in commodity prices.  The average gas price, including the effects of hedging, also decreased by $3.28 per Mcf from $8.74 per Mcf for the three months ended March 31, 2008 to $5.46 per Mcf for the comparable period in 2009.  The effect of gas hedging activities on natural gas revenue for the three months ended March 31, 2009 was a gain of $15.4 million as compared to a loss of $0.7 million for the three months ended March 31, 2008.

Crude Oil.  For the three months ended March 31, 2009, oil revenue was $5.2 million as compared to $15.9 million for the comparable period in 2008.  This decrease is attributable to the average realized price decrease of $61.11 per Bbl from $100.10 per Bbl for the three months ended March 31, 2008 to $38.99 per Bbl for the three months ended March 31, 2009.   The decrease in oil production volumes was primarily due to a decline in well performance at our Sabine Lake property.

Operating Expenses
 
The following table presents information regarding our operating expenses:

   
Three Months Ended
March 31,
  
   
2009
    
2008
    
% Change
Increase/
(Decrease)
  
   
(In thousands, except percentages and per unit amounts)
  
Lease operating expense
   $ 18,041     $ 13,414       34 %
Production taxes
     1,323       3,437       (62 %)
Depreciation, depletion and amortization
     44,400       51,414       (14 %)
Impairment of oil and gas properties
     379,462       -       100 %
General and administrative costs
     9,373       12,107       (23 %)
                         
$ per unit:
                        
Avg. lease operating expense per Mcfe
   $ 1.25     $ 0.97       29 %
Avg. production taxes per Mcfe
     0.09       0.25       (64 %)
Avg. DD&A per Mcfe
     3.08       3.72       (17 %)
Avg. G&A per Mcfe
     0.65       0.88       (26 %)

 
Lease Operating Expense.  Lease operating expense increased $4.6 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008.   The overall increase is due primarily to a $1.9 million increase in direct lease operating expense, a $1.9 million increase in ad valorem tax, and a $1.1 million increase in workover expenses.  The increase in direct lease operating expense is due to increased operating expenses from newly acquired properties from the Petroflow and Constellation acquisitions, which occurred during the second and fourth quarters of 2008, respectively.  The increase in ad valorem expense is primarily due to higher property appraisals.  The increase in workover expenses is due to a planned workover program in California and unanticipated workovers in the Texas State Waters and the Gulf of Mexico.
 
Production Taxes.  Production taxes decreased primarily due to the 41% decrease in realized natural gas and oil prices.
 
Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization (“DD&A”) expense decreased $7.0 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008.  The decrease is due to the full cost ceiling test impairment charges recognized during the second half of 2008 which decreased the full cost pool and thus the DD&A rate.  The DD&A rate for the first quarter of 2009 was $3.08 per Mcfe while the rate for the first quarter of 2008 was $3.72 per Mcfe.  The decrease in the rate was due to a lower full cost asset base over a comparable reserve base in the first quarter of 2009 as compared to the same period in 2008.

Impairment of Oil and Gas Properties.  At March 31, 2009, the ceiling test computation was calculated using hedge adjusted market prices of gas and oil, which were based on a Henry Hub price of $3.63 per MMBtu and a West Texas Intermediate oil price of $46.00 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2009 increased the calculated ceiling value by approximately $79.7 million (pre-tax).  Based upon this analysis, a non-cash, pre-tax write-down of $379.5 million was recorded at March 31, 2009.  At March 31, 2008, the ceiling test computation was calculated using hedge adjusted market prices, which were based on a Henry Hub price of $9.37 per MMBtu and a West Texas Intermediate oil price of $105.63 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at March 31, 2008 decreased the calculated ceiling value by approximately $37.7 million (net of tax). There was no write-down required to be recorded at March 31, 2008. 
 
General and Administrative Costs.  General and administrative costs decreased by $2.7 million for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008.  This decrease is primarily due to the decrease of $4.3 million in legal expenses incurred during the first quarter of 2008 associated with the Calpine litigation, which settled during the fourth quarter of 2008.  This decrease was partially offset by increased salaries, wages and benefits expense due to an increase in headcount of 34 employees for the first quarter of 2009 compared to the first quarter of 2008.
 
 Total Other Expense
 
Other expense includes interest expense, interest income and other income/expense, net which decreased $0.9 million for the three months ended March 31, 2009 compared to the three months ended March 31, 2008.  The interest income is earned on cash balances, which were lower during the quarter ended March 31, 2009 compared to  March 31, 2008; however, there was a decrease in interest expense due to lower interest rates on our variable rate debt for the first quarter of 2009 versus the comparable period for 2008.
 
Provision for Income Taxes
 
The effective tax rate for the three months ended March 31, 2009 and 2008 was 36.9% and 35.5%, 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.  The income tax benefit at March 31, 2009 includes a $1.0 million adjustment related to 2008 state taxes.
 
We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.  At March 31, 2009, we have a deferred tax asset of approximately $180.7 million resulting primarily from the difference between the recorded basis and tax basis of its oil and natural gas properties.  We believe this deferred tax asset will be realized through the generation of future taxable income.

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Liquidity and Capital Resources
 
Our primary source of liquidity and capital is our operating cash flow. We also maintain a revolving line of credit, which can be accessed as needed to supplement operating cash flow.
 
Operating Cash Flow.  Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of a portion of our production, thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising natural gas prices. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas.”  The majority of our capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels.  Current economic conditions and lower commodity prices could adversely affect our cash flow and liquidity. We will continue to monitor our cash flow and liquidity and if appropriate, we may consider adjusting our capital expenditure program.
 
Senior Secured Revolving Line of Credit.  BNP Paribas, in July 2005, 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 and matures on April 5, 2010. Availability under the Revolver is restricted to the borrowing base.  The borrowing base is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements. In June 2008, the borrowing base was adjusted to $400.0 million and affirmed in December 2008.  Initial amounts outstanding under the Revolver bore interest, as amended, at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%. These rates over LIBOR were adjusted in June 2008 to be 1.125% to 1.875%.  Such margins will fluctuate based on the utilization of the facility. Borrowings under the Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of the membership interests of domestic subsidiaries and a lien on cash securing the Calpine gas purchase and sale contract. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information.   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 March 31, 2009, our current ratio was 3.6 and the leverage ratio was 0.9.  In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at March 31, 2009.  At March 31, 2009, all amounts drawn under the Revolver were due and payable on April 5, 2010.

On April 9, 2009, we entered into our Restated Revolver agreement providing a senior secured revolving line of credit in the amount of up to $600.0 million and extending its term until July 1, 2012.  As extended, the borrowing base under the Restated Revolver is currently set at $375.0 million.  Amounts outstanding under the Restated Revolver bear interest, as amended, at specified margins over LIBOR of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of our domestic subsidiaries, and a pledge of 100% of the membership interests of domestic subsidiaries.  We paid a facility fee on the total commitment of $4.6 million.  As of May 8, 2009, we have $165.0 million available for borrowing under our revolving line of credit.

 Second Lien Term Loan.   BNP Paribas, in July 2005, also provided us with a second lien term loan concurrent with the acquisition of oil and gas properties from Calpine (“Term Loan”).  Borrowings under the Term Loan were $75.0 million as of March 31, 2009.  Such borrowings are syndicated to a group of lenders including BNP Paribas.  Borrowings under the Term Loan bear interest at LIBOR plus 4.00%. The loan is collateralized by second priority liens on substantially all of our assets.  We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures.  At March 31, 2009, our asset coverage ratio was 3.1 and the leverage ratio was 0.9.  In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at March 31, 2009.  At March 31, 2009, the principal balance of the Term Loan was due and payable on July 7, 2010.

On April 9, 2009, we also entered into our Restated Term Loan agreement extending its term until October 2, 2012. Borrowings under the Restated Term Loan were initially set at $75.0 million and bear interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%.  The Restated Term Loan had an option to increase fixed and floating rate borrowings to $100.0 million within the first 30 days, which we exercised on April 21, 2009.  The $25.0 million of increased borrowings consists of $5.0 million of floating rate borrowings and $20.0 million of fixed rate borrowings at 13.75%.  The loan is collateralized by second priority liens on substantially all of our assets.  We paid an original issue discount of $1.8 million and a facility fee of $0.7 million on the total commitment.

22

Our current liquidity position is supported by our Restated Revolver, which matures on July 1, 2012. The Restated Revolver is subject to semi-annual borrowing base redeterminations, with the next redetermination scheduled for the fall of 2009. Our borrowing base is dependent on a number of factors including our level of reserves as well as the pricing outlook at the time of the redetermination. A reduction in capital spending could result in a reduced level of reserves thus causing a reduction in the borrowing base. Our ability to raise capital depends on the current state of the capital markets, which are subject to general economic and industry conditions. We will continue to monitor the financial markets as the availability and price of capital in these markets could negatively affect our liquidity position. 

Cash Flows

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

   
Three Months Ended March 31, 
  
     
2009 
      
2008 
  
     
(In thousands) 
  
Cash flows provided by operating activities
   $ 39,542     $ 103,245  
Cash flows used in investing activities
     (53,878 )     (61,877 )
Cash flows provided by financing activities
     4,452       1,309  
Net increase (decrease) in cash and cash equivalents
   $ (9,884 )   $ 42,677  


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 decreased by $63.7 million for the three months ended March 31, 2009 as compared to the same period for 2008.  The decrease in 2009 primarily resulted from lower realized average natural gas and oil prices.  In addition, at March 31, 2009, we had a working capital surplus of $61.8 million.  This surplus was primarily attributable to the increase in the derivative instruments and a decrease in accrued liabilities.
 
Investing Activities.  The primary driver of cash used in investing activities is capital spending.
 
Cash flows used in investing activities decreased by $8.0 million for the three months ended March 31, 2009 as compared to the same period for 2008.  During the three months ended March 31, 2009, we participated in the drilling of 21 gross wells as compared to the drilling of 36 wells in 2008.
 
Financing Activities.  The primary drivers of cash provided by financing activities are borrowings on the revolving credit facility and equity transactions associated with the exercise of stock options and vesting of restricted stock.
 
Cash flows provided by financing activities increased by $3.1 million as compared to the same period for 2008.  The net increase is primarily related to $5.0 million of borrowings on the revolving credit facility in the first quarter of 2009.
 
Capital Expenditures
 
Our capital expenditures for the three months ended March 31, 2009 decreased by $12.0 million to $34.5 million compared to the comparable period in 2008.  During the three months ended March 31, 2009, we participated in the drilling of 21 gross wells with the majority of these being in the Lobo and DJ Basin regions.  Our positive operating cash flow, along with the availability under our revolving credit facility, are projected to be sufficient to fund planned capital expenditures for 2009, which are projected to be $80.0 million.  We have the discretion to adjust capital spending plans throughout the year in response to market conditions and the availability of proceeds from possible divestitures.

Commodity Price Risk, Interest Rate Risk and Related Hedging Activities

The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management hedges oil and natural gas prices from time to time primarily through the use of certain derivative instruments including fixed price swaps, basis swaps, costless collars and put options. Although not risk free, we believe these activities will reduce our exposure to commodity price fluctuations and thereby achieve a more predictable cash flow. Consistent with this policy, we have entered into a series of natural gas fixed-price swaps, which are intended to establish a fixed price for a portion of our expected natural gas production through 2010. The fixed-price swap agreements we have entered into require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments were based on expected proved production from existing wells at inception of the hedge instruments.

23

The following table sets forth the results of commodity hedging transaction settlements for the period ended March 31, 2009:

   
Three Months Ended March 31,
  
Natural Gas
  
2009
    
2008
  
Quantity settled (MMBtu)
     5,142,690       6,156,216  
Increase (decrease) in natural gas sales revenue (In thousands)
   $ 15,357     $ (701 )
Interest Rate Swaps
                
(Increase) decrease in interest expense (In thousands)
   $ (512 )   $ 125  

As of March 31, 2009, borrowings under our Revolver and Term Loan mature on April 5, 2010 and July 7, 2010, respectively, and bear interest at a LIBOR-based rate. This exposes us to risk of earnings loss due to increases in market interest rates. To mitigate this exposure, as of March 31, 2009, we have entered into a series of interest rate swap agreements through June 2009.  Subsequently, in conjunction with the extended maturities of our Restated Revolver and Restated Term Loan, during April 2009, we entered into a series of interest rate swap agreements to hedge interest rates from October 2009 to December 2010.   If we determine the risk may become substantial and the costs are not prohibitive, we may enter into additional interest rate swap agreements in the future.
 
In accordance with SFAS No. 133, as amended, all derivative instruments, not designated as a normal purchase sale, are recorded on the balance sheet at fair market value and changes in the fair market value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair market value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions on a quarterly basis, consistent with documented risk management strategy for the particular hedging relationship. Changes in the fair market value of the ineffective portion of cash flow hedges, if any, are included in other income (expense).
 
Our current commodity and interest rate hedge positions are with counterparties that are lenders in our credit facilities. This allows us to secure any margin obligation resulting from a negative change in the fair market value of the derivative contracts in connection with our credit obligations and eliminate the need for independent collateral postings.  As of March 31, 2009, we had no deposits for collateral.
 
Capital Requirements
 
The historical capital expenditures summary table is included in Item 1. Business in our 2008 Annual Report and is incorporated herein by reference.
 
Our capital expenditures for the period ended March 31, 2009 were $34.5 million, and we have plans to carefully execute an organic capital program in 2009 that can be funded from internally generated cash flows.  We also have the discretion to use available cash, borrowings under our Restated Revolver, and proceeds from divestitures to fund capital expenditures, including acquisitions, that make sense for the Company.  However, our main priority for the foreseeable future is to preserve liquidity.

Commitments and Contingencies
 
As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.
 
We are party to various litigation matters and administrative claims arising out of the normal course of business. Although the ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operation or cash flows.

24

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 2008 Annual Report and Note 4 included in Part I. Item 1. Financial Statements of this Form 10-Q.
 
At March 31, 2009, we had open natural gas derivative hedges in an asset position with a fair value of $63.1 million.  A 10 percent increase in natural gas prices would reduce the fair value by approximately $8.5 million, while a 10 percent decrease in natural gas prices would increase the fair value by approximately $8.1 million.  These fair value changes assume volatility based on prevailing market parameters at March 31, 2009.  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. We evaluated non-performance risk using current credit default swap values and default probabilities for each counterparty and recorded a downward adjustment to the fair value of our derivative assets in the amount of $1.5 million at March 31, 2009.  We currently know of no circumstances that would limit access to our credit facility or require a change in our debt or hedging structure.

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 March 31, 2009.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2009, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
 
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 as well as administrative claims related to employment issues.  While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the consolidated financial statements.

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

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended March 31, 2009

25
 
Period
  
Total Number of Shares Purchased (1)
    
Average Price Paid per Share
    
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
    
Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
  
January 1 - January 31
     8,321     $ 7.36       -       -  
February 1 - February 28
     1,869       5.96       -       -  
March 1 - March 31
     13,023       4.83       -       -  
     Total
     23,213     $ 5.83       -       -  

(1)
All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.  These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

Issuance of Unregistered Securities

None.

Item 3.  Defaults Upon Senior Securities

None.

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

None.

Item 5.  Other Information

None.

26

Item 6.  Exhibits

Exhibit Number
  
Description
3.1
 
Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
3.2
  
Amended and Restated Bylaws (incorporated herin by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on December 10, 2008 (Registration No. 000-51801)).
4.1
  
Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
10.18
  
Amended and Restated Senior Revolving Credit Agreement (incorporated herin by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.19
  
Amended and Restated Second Lien Term Loan Agreement (incorporated herin by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
31.1
  
Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2
  
Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1
  
Certification of Periodic Financial Reports by Chief Executive Officer and Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

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

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

Date: May 8, 2009

28

ROSETTA RESOURCES INC.
 
EXHIBIT INDEX

Exhibit Number
  
Description
3.1
 
Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
3.2
  
Amended and Restated Bylaws (incorporated herin by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on December 10, 2008 (Registration No. 000-51801)).
4.1
  
Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed on October 7, 2005 (Registration No. 333-128888)).
10.18
  
Amended and Restated Senior Revolving Credit Agreement (incorporated herin by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
10.19
  
Amended and Restated Second Lien Term Loan Agreement (incorporated herin by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K filed on April 15, 2009 (Registration No. 000-51801)).
 
Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
Certification of Periodic Financial Reports by Chief Executive Officer and Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
 
 29