Form 10-Q 9/30/2006





UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM 10-Q


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

For The Quarterly Period Ended September 30, 2006

OR

[ ] Transition Report Pursuant To Section 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 [ ]
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934. Large accelerated filer [ ] Accelerated filer [ ] Non-Accelerated filer [X]
 
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
 
The number of shares of the registrant's Common Stock, $.001 par value per share, outstanding as of November 2, 2006 was 50,647,319.






 


   
     
     
 
 
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-2-


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


   
September 30,
2006
 
December 31,
2005
 
Assets
 
(Unaudited)
     
Current assets:
             
Cash and cash equivalents
 
$
78,743
 
$
99,724
 
Restricted cash
   
15,000
   
-
 
Accounts receivable
   
34,751
   
40,051
 
Derivative instruments
   
23,591
   
1,110
 
Deferred income taxes
   
-
   
10,962
 
Income tax receivable
   
-
   
6,000
 
Other current assets
   
9,696
   
9,411
 
Total current assets
   
161,781
   
167,258
 
Oil and natural gas properties, full cost method, of which $51.0 million at September 30,
2006 and $30.6 million at December 31, 2005 were excluded from amortization
   
1,134,754
   
973,185
 
Other
   
3,868
   
2,912
 
 
   
1,138,622
   
976,097
 
Accumulated depreciation, depletion, and amortization
   
(117,186
)
 
(40,161
)
Total property and equipment, net
   
1,021,436
   
935,936
 
Deferred loan fees
   
3,670
   
4,555
 
Deferred income taxes
   
-
   
8,594
 
Other assets
   
3,458
   
2,926
 
     
7,128
   
16,075
 
Total assets
 
$
1,190,345
 
$
1,119,269
 
               
Liabilities and Stockholders' Equity
             
Current liabilities:
             
Accounts payable
 
$
16,604
 
$
13,442
 
Accrued liabilities
   
42,604
   
28,397
 
Royalties payable
   
13,479
   
15,511
 
Derivative instruments
   
-
   
29,957
 
Prepayment on gas sales
   
10,599
   
14,528
 
Deferred income taxes
   
8,965
   
-
 
Total current liabilities
   
92,251
   
101,835
 
Long-term liabilities:
             
Derivative instruments
   
7,952
   
52,977
 
Long-term debt
   
240,000
   
240,000
 
Asset retirement obligation
   
9,698
   
9,034
 
Deferred income taxes
   
28,179
   
-
 
Total liabilities
   
378,080
   
403,846
 
Commitments and contingencies (Note 10)
             
Stockholders' equity:
   
       
Common stock, $0.001 par value, 150,000,000 shares authorized; 50,380,475 issued
   
50
   
50
 
Additional paid-in capital
   
754,002
   
748,569
 
Treasury stock, at cost; 83,881 and no shares at September 30, 2006 and
December 31, 2005, respectively
   
(1,526
)
 
-
 
Accumulated other comprehensive income (loss)
   
10,792
   
(50,731
)
Retained earnings
   
48,947
   
17,535
 
Total stockholders' equity
   
812,265
   
715,423
 
Total liabilities and stockholders' equity
 
$
1,190,345
 
$
1,119,269
 
               

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

-3-


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

   
Successor-Consolidated
 
Successor-Consolidated
   
Predecessor-Combined
 
   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
   
Six Months Ended June 30,
 
   
2006
 
2005
 
2006
   
2005
 
Revenues:
                   
Natural gas sales
 
$
61,366
 
$
51,661
 
$
171,783
   
$
13,713
 
Oil sales
   
9,831
   
6,204
   
27,339
     
8,166
 
Oil and natural gas sales to affiliates
   
-
   
-
   
-
     
81,952
 
Total revenues
   
71,197
   
57,865
   
199,122
     
103,831
 
Operating Costs and Expenses:
                           
Lease operating expense
   
9,449
   
8,849
   
27,330
     
16,629
 
Depreciation, depletion, and amortization
   
27,906
   
21,720
   
77,574
     
30,679
 
Exploration expense
   
-
   
-
   
-
     
2,355
 
Dry hole costs
   
-
   
-
   
-
     
1,962
 
Treating and transportation
   
317
   
552
   
2,043
     
1,998
 
Affiliated marketing fees
   
-
   
-
   
-
     
913
 
Marketing fees
   
526
   
678
   
1,634
     
-
 
Production taxes
   
2,153
   
1,946
   
5,476
     
2,755
 
General and administrative costs
   
8,316
   
6,880
   
24,645
     
9,677
 
Total operating costs and expenses
   
48,667
   
40,625
   
138,702
     
66,968
 
Operating income
   
22,530
   
17,240
   
60,420
     
36,863
 
                             
Other (income) expense
                           
Interest expense with affiliates, net of interest capitalized
   
-
   
-
   
-
     
6,995
 
Interest expense, net of interest capitalized
   
4,557
   
4,077
   
13,060
     
-
 
Interest (income) expense
   
(1,099
)
 
(874
)
 
(3,351
)
   
(516
)
Other (income) expense, net
   
(171
)
 
153
   
6
     
207
 
Total other expense
   
3,287
   
3,356
   
9,715
     
6,686
 
                             
Income before provision for income taxes
   
19,243
   
13,884
   
50,705
     
30,177
 
Provision for income taxes
   
7,321
   
5,677
   
19,293
     
11,496
 
Net income
 
$
11,922
 
$
8,207
 
$
31,412
   
$
18,681
 
                             
Earnings per share:
                           
Basic
 
$
0.24
 
$
0.16
 
$
0.63
   
$
0.37
 
Diluted
 
$
0.24
 
$
0.16
 
$
0.62
   
$
0.37
 
                             
Weighted average shares outstanding:
                           
Basic
   
50,282
   
50,000
   
50,211
     
50,000
 
Diluted
   
50,426
   
50,160
   
50,384
     
50,160
 


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

-4-


Rosetta Resources Inc.
Consolidated/Combined Statement of Cash Flows
(In thousands)
(Unaudited)
 

   
Successor-Consolidated
 
Successor-Consolidated
   
Predecessor-Combined
 
   
Nine Months Ended September 30,
 
Three Months Ended September 30,
   
Six Months Ended June 30,
 
   
2006
 
2005
   
2005
 
Cash flows from operating activities
               
Net income
 
$
31,412
 
$
8,207
   
$
18,681
 
Adjustments to reconcile net income to net cash from operating activities
             
Depreciation, depletion and amortization
   
77,574
   
21,720
     
30,679
 
Affiliate interest expense
   
-
   
-
     
(6,995
)
Deferred income taxes
   
18,991
   
3,406
     
2,874
 
Amortization of deferred loan fees recorded as interest expense
   
885
   
-
     
-
 
Income from unconsolidated investments
   
(168
)
 
(112
)
   
(161
)
Stock compensation expense
   
4,348
   
1,710
     
-
 
Other non-cash charges
   
-
   
-
     
99
 
Change in operating assets and liabilities:
                     
Accounts receivable
   
5,300
   
(33,570
)
   
2,378
 
Accounts receivable from affiliates
   
-
   
-
     
6,298
 
Income taxes receivable
   
6,000
   
-
     
-
 
Other assets
   
1,070
   
(5,412
)
   
2,563
 
Accounts payable
   
2,494
   
24,098
     
(4,494
)
Accrued liabilities
   
(324
)
 
8,019
     
241
 
Royalties payable
   
(5,961
)
 
32,913
     
(1,406
)
Income taxes payable
   
-
   
2,271
     
8,622
 
Net cash provided by operating activities
   
141,621
   
63,250
     
59,379
 
Cash flows from investing activities
                     
Acquisition, net of cash acquired
   
-
   
(910,064
)
   
-
 
Purchases of property and equipment
   
(147,243
)
 
(26,507
)
   
(32,202
)
Disposals of property and equipment
   
36
   
-
     
1,447
 
Deposits
   
50
   
(201
)
   
-
 
Investment in non-affiliated subsidiary
   
-
   
(820
)
   
-
 
Increase in restricted cash
   
(15,000
)
 
-
     
-
 
Other
   
(4
)
 
-
     
110
 
Net cash used in investing activities
   
(162,161
)
 
(937,592
)
   
(30,645
)
Cash flows from financing activities
                     
Equity offering proceeds
   
-
   
800,000
     
-
 
Equity offering transaction fees
   
268
   
(53,540
)
   
-
 
Borrowings on term loan
   
-
   
100,000
     
-
 
Payments on term loan
   
-
   
(25,000
)
   
-
 
Borrowings on revolving credit facility
   
-
   
225,000
     
-
 
Payments on revolving credit facility
   
-
   
(60,000
)
   
-
 
Loan fees
   
-
   
(5,145
)
   
-
 
Notes payable to affiliates
   
-
   
-
     
(27,239
)
Proceeds from issuances of common stock
   
515
   
-
     
-
 
Stock-based compensation excess tax benefit
   
302
   
-
     
-
 
Purchases of treasury stock
   
(1,526
)
 
-
     
-
 
Net cash (used in) provided by financing activities
   
(441
)
 
981,315
     
(27,239
)
                       
Net (decrease) increase in cash
   
(20,981
)
 
106,973
     
1,495
 
Cash and cash equivalents, beginning of period
   
99,724
   
     
-
 
Cash and cash equivalents, end of period
 
$
78,743
 
$
106,973
   
$
1,495
 
                       
Supplemental non-cash disclosures:
                     
Capital expenditures included in accrued liabilities
 
$
3,783
   
(1,670
)
   
-
 
Accrued purchase price adjustment     11,400                

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

-5-


Rosetta Resources Inc.
 
Notes to Consolidated/Combined Financial Statements (unaudited)
 
(1)
Organization and Operations of the Company
 
Nature of Operations.    Rosetta Resources Inc. (together with its consolidated subsidiaries, “the Company”) was formed in June 2005. The Company (“Successor”) 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 Lobo and Perdido Trends in South Texas, the Gulf of Mexico and the Rocky Mountains.
 
These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of the financial statements have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America.
 
These financial statements and notes should be read in conjunction with the Company’s audited consolidated/combined financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.
 
Certain reclassifications of prior year balances have been made to conform such amounts to corresponding 2006 classifications. These reclassifications have no impact on net income.
 
(2)
Acquisition of Calpine Oil and Natural Gas Business
 
On July 7, 2005, the Company acquired substantially all of the oil and natural gas business of Calpine Corporation and certain of its subsidiaries (collectively, “Calpine” or “Predecessor”), excluding certain non-consent properties described below, for approximately $910 million. This acquisition (the “Acquisition”) was funded with the issuance of common stock totaling $725 million and $325 million of debt from the Company’s credit facilities. The transaction was accounted for under the purchase method in accordance with Statement of Financial Accounting Standards (“SFAS”) No.141. The results of operations were included in the Company’s financial statements effective July 1, 2005 as the operating results in the intervening period were not significant. The purchase price in the Acquisition was calculated as follows (In thousands):
 

Cash from equity offering
 
$
725,000
 
Proceeds from revolver
   
225,000
 
Proceeds from term loan
   
100,000
 
Other purchase price costs
   
(53,389
)
Transaction adjustments (purchase price adjustments)
   
(11,556
)
Transaction adjustments (non-consent properties)
   
(74,991
)
Initial purchase price
 
$
910,064
 
         

Other purchase price costs relate primarily to professional fees of $3.9 million and other direct transaction costs of $49.5 million.
 
The transaction adjustments (purchase price adjustments) referred to above are an amount agreed upon by Calpine and the Company to cover potential costs and/or revenues to be adjusted to actual upon the final settlement.
 
Transaction adjustments (non-consent properties) referred to above relate to properties which Calpine determined required third party consents or waivers of preferential purchase rights in order to effect the transfer of title from Calpine to the Company or to Calpine entities acquired by the Company in the Acquisition (collectively, “Non-Consent Properties”). At July 7, 2005, the Company withheld approximately $75 million of the purchase price with respect to the Non-Consent Properties. A third party exercised a preferential right to purchase certain Non-Consent Properties. Assuming such preferential rights transaction is consummated, these properties will not be conveyed to the Company, and the purchase price of the remaining Non-Consent properties will be reduced by approximately $7.4 million. Despite Calpine’s bankruptcy filing, management believes that it remains likely that conveyance to the Company of substantially all of the remaining Non-Consent Properties will occur. Upon conveyance of the remaining Non-Consent Properties, approximately $68 million, the balance of the additional purchase price, will be paid to Calpine and will be incremental to the purchase price of $910 million. The Company has excluded the effects of the operating results for the Non-Consent Properties from the Company’s actual results for the three and nine months ended September 30, 2006. If the assignment of the remaining Non-Consent Properties does not occur, the portion of the purchase price the Company withheld pending obtaining consent or waivers for these properties will be available to the Company for general corporate purposes or to acquire other properties.
 
-6-

The following is the allocation of the purchase price to specific assets acquired and liabilities assumed based on estimates of the fair values and costs (In thousands). There was no goodwill associated with the transaction.
 

Current assets
 
$
1,794
 
Non-current assets
   
5,087
 
Properties, plant and equipment
   
925,141
 
Current liabilities
   
(14,390
)
Long-term liabilities
   
(7,568
)
   
$
910,064
 
         

The purchase price allocation is based upon the manner in which the parties expect to resolve the negotiation associated with the Company’s revised Final Settlement Statement pertaining to the Acquisition that was delivered to Calpine on May 12, 2006. In addition to the $68 million that will be payable to Calpine if and when title is obtained by the Company for the remaining Non-Consent Properties and Calpine provides the further assurances to eliminate any open issues on title to the remaining properties that may require further documentation, the Company’s revised Final Settlement Statement includes the proposed cash payment to Calpine of approximately $11 million arising from net revenues that were estimated and withheld at the closing of the Acquisition, which is recorded as an accrued liability on the Consolidated Balance Sheet as of September 30, 2006.
 
The unaudited pro forma information for the nine months ended September 30, 2005 assumes the acquisition of Calpine’s domestic oil and natural gas business and the related financings occurred on January 1, 2004. The Company believes the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to such transactions. The unaudited pro forma financial statements do not purport to represent what the Company’s results of operations would have been if such transactions had occurred on such date.
 

   
Nine Months Ended
September 30, 2005
 
   
(In thousands, except per share amounts)
 
   
(Unaudited)
 
Revenues
 
$
152,262
 
Net income
   
17,109
 
Basic earnings per common share
   
0.34
 
Diluted earnings per common share
 
$
0.34
 
 
(3)
Summary of Significant Accounting Policies
 
The Company has provided discussion of significant accounting policies, estimates and judgments in its Annual Report on Form 10-K for the year ended December 31, 2005.
 
Principles of Consolidation/Combination and Basis of Presentation.  The Predecessor combined financial statements for the six months ended June 30, 2005 have been prepared from the historical accounting records of the domestic oil and natural gas business of Calpine and are presented on a carve-out basis to include the historical operations of the domestic oil and natural gas business. The domestic oil and natural gas business of Calpine was separately accounted for and managed through direct and indirect subsidiaries of Calpine. The combined financial information included herein includes certain allocations based on the historical activity levels to reflect the combined financial statements in accordance with accounting principles generally accepted in the United States of America and may not necessarily reflect the financial position, results of operations and cash flows of the Company in the future or as if the Company had existed as a separate, stand-alone business during the period presented. The allocations consist of general and administrative expenses such as employee payroll and related benefit costs and building lease expense, which were incurred on behalf of Calpine. The allocations have been made on a reasonable basis and have been consistently applied for the periods presented.
 
The accompanying consolidated financial statements as of September 30, 2006 and December 31, 2005 and for the three and nine months ended September 30, 2006 and three months ended September 30, 2005 contain the accounts of Rosetta Resources Inc. and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.
 

-7-


Stock-Based Compensation. On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payments” (“SFAS No. 123R”). This statement applies to all awards granted, modified, repurchased or cancelled after January 1, 2006 and to the unvested portion of all awards granted prior to that date. The Company adopted this statement using the modified version of the prospective application (modified prospective application). Under the modified prospective application, compensation cost for the portion of awards for which the employee’s requisite service has not been rendered that are outstanding as of January 1, 2006 must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of awards shall be based on the original fair market value of those awards on the date of grant as calculated for recognition under SFAS No. 123 “Accounting for Stock-Based Compensation” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” (“SFAS No. 123”). The compensation cost for these earlier awards shall be attributed to periods beginning on or after January 1, 2006 using the attribution method that was used under SFAS 123.
 
The adoption of the new standard did not have a significant impact on the Consolidated Balance Sheet because of the requirement to decrease retained earnings with an offsetting increase in additional paid-in capital. On the Consolidated/Combined Statement of Operations, the adoption of SFAS No. 123R resulted in decreases in both income before income taxes and net income of $1.0 million and $0.6 million, respectively, for the three months ended September 30, 2006 and $4.3 million and $2.7 million, respectively, for the nine months ended September 30, 2006. The effect on net income per share for basic and diluted was a reduction $0.01 and $0.05 for the three and nine months ended September 30, 2006, respectively. See Note 12 of the notes to the Consolidated/Combined Financial Statements for additional disclosure.
 
Prior to the adoption of SFAS No. 123R, the Company presented all tax benefit deductions resulting from the exercise of stock options as operating cash flows in the accompanying Consolidated/Combined Statement of Cash Flows. SFAS No. 123R requires the cash flows that result from tax deductions in excess of the compensation expense recognized as an operating expense in 2006 and reported in pro forma disclosures prior to 2006 for those stock options (excess tax benefits) to be classified as financing cash flows. The excess tax benefit for the nine months ended September 30, 2006 was $0.3 million.
 
Recent Accounting Developments
 
Accounting Changes and Error Corrections. In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of Accounting Principles Board Opinion (“APB”) No. 20 and FASB Statement No. 3” (“SFAS No. 154”), which changes the requirements for the accounting for and the reporting of a change in accounting principle. This Statement applies to all voluntary changes in accounting principles. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of this Statement did not impact the Company’s consolidated financial position, results of operations, or cash flows.
 
Accounting for Certain Hybrid Financial Instruments. In February 2006 , the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Instruments - an amendment of FASB Statements 133 and 140”, which is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The statement improves financial reporting by eliminating the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. The statement also improves financial reporting by allowing a preparer to elect fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated, if the holder elects to account for the whole instrument on a fair value basis. The adoption of this statement is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
 
Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this Interpretation is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
 
Guidance for Quantifying Financial Statement Misstatement. In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which establishes an approach requiring the quantification of financial statement errors based on the effect of the error on each of the company’s financial statements and the related financial statement disclosures.  This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the “iron curtain” and “roll-over” methods.  The
 

-8-


roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements; however, its use can lead to the accumulation of misstatements in the balance sheet. The iron curtain method focuses primarily on the effect of correcting the period end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The Company currently uses the iron curtain method for quantifying financial statement misstatements. The Company will initially apply the provisions of SAB 108 in connection with the preparation of the Company’s annual financial statements for the year ending December 31, 2006. The use of the dual approach is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
 
Fair Value Measurements. In September 2006, the FASB issued FASB Statement No. 157,“Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. Although the disclosure requirements may be expanded where certain assets or liabilities are fair valued such as those related to stock compensation expense and hedging activities, the Company does not expect the adoption of SFAS No. 157 to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
 
(4)
Restricted Cash
 
In July 2006, the Company entered into a Deposit Account Control Agreement in order to provide a security interest under the terms of its senior secured revolving line of credit.  Under the terms of the Deposit Account Control Agreement, the Company was required to maintain $15.0 million on account to keep a borrowing base of $325.0 millionThe Company’s borrowing base is subject to review on a semi-annual basis under the terms of the senior secured revolving line of credit.  Based on this semi-annual review, a consent agreement was signed in October 2006 in which the borrowing base remained at $325.0 million and the Company was no longer required to maintain the $15.0 million balance pursuant to the Deposit Account Control Agreement.
 
(5)
Property, Plant and Equipment
 
In connection with the Company’s separation from Calpine, the Company adopted the full cost method of accounting for oil and natural gas properties beginning July 1, 2005. Under the full cost method, all costs incurred in acquiring, exploring and developing properties within a relatively large geopolitical cost center are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs, such as those associated with offshore U.S. operations, are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and natural gas producing activities are regarded as integral to the acquisition, discovery and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $0.9 million and $2.6 million of internal costs for the three and nine months ended September 30, 2006, respectively. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless a significant portion of the pool is sold.
 
The Company assesses the impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. If the net capitalized costs of oil and natural gas properties exceed the cost center ceiling, the Company is subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, it would reduce earnings and impact shareholders’ equity in the period of occurrence and result in a lower depreciation, depletion and amortization expense in the future.
 
The Company’s ceiling test computation was calculated using hedge adjusted market prices at September 30, 2006 which were based on a Henry Hub gas price of $4.18 per MMBtu and a West Texas Intermediate oil price of $62.91 per barrel. The use of these prices indicated a writedown of $142.1 million at September 30, 2006. Cash flow hedges of natural gas production in place at September 30, 2006 increased the calculated ceiling value by approximately $92.2 million (net of tax). However, subsequent to September 30, 2006 the market price for Henry Hub increased to $7.42 per MMBtu and the price for West Texas Intermediate decreased to $58.07 per barrel, and utilizing these prices, the Company’s net capitalized costs of oil and natural gas properties exceeded the ceiling amount. As a result no writedown was recorded for the quarter ended September 30, 2006. The ceiling value calculated using subsequent prices includes approximately $17.9 million related to the positive effects of future cash flow hedges of natural gas production. Due to the volatility of commodity prices, should natural gas and oil prices decline in the future, it is possible that a writedown could occur.
 

-9-


Calpine followed the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs were capitalized. Exploratory drilling costs were capitalized until the results were determined. If proved reserves were not discovered, the exploratory drilling costs were expensed. Other exploratory costs were expensed as incurred. Interest costs related to financing major oil and natural gas projects in progress were capitalized until the projects were evaluated or until the projects were substantially complete and ready for their intended use if the projects were evaluated as successful. Calpine also capitalized internal costs directly identified with acquisition, exploration and development activities and did not include any costs related to production, general corporate overhead or similar activities. The provision for depreciation, depletion, and amortization was based on the capitalized costs as determined above, plus future abandonment costs net of salvage value, using the unit of production method with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.
 
The Company’s total property, plant and equipment consists of the following:
 

   
September 30,
2006
 
December 31,
2005
 
   
(In thousands)
 
Proved properties
 
$
1,103,302
 
$
951,968
 
Unproved properties
   
31,452
   
21,217
 
Other
   
3,868
   
2,912
 
Total
   
1,138,622
   
976,097
 
Less: Accumulated depreciation, depletion, and amortization
   
(117,186
)
 
(40,161
)
   
$
1,021,436
 
$
935,936
 
               

 
Included in the Company’s oil and natural gas properties are asset retirement obligations of $9.2 million and $9.1 million as of September 30, 2006 and December 31, 2005, respectively.
 
At September 30, 2006 and December 31, 2005, the Company excluded the following capitalized costs from depreciation, depletion and amortization:
 

   
September 30,
2006
 
December 31,
2005
 
Onshore:
 
(In thousands)
Development cost
 
$
13,796
 
$
1,716
 
Exploration cost
   
3,939
   
5,212
 
Acquisition cost of undeveloped acreage
   
25,696
   
19,684
 
Capitalized interest
   
1,691
   
555
 
Total
   
45,122
   
27,167
 
               
Offshore:
             
Development cost
 
$
1,779
 
$
-
 
Exploration cost
   
-
   
2,407
 
Acquisition cost of undeveloped acreage
   
3,954
   
950
 
Capitalized interest
   
111
   
28
 
Total
   
5,844
   
3,385
 
               
Total costs excluded from depreciation, depletion, and amortization
 
$
50,966
 
$
30,552
 
               

 
In April 2006, the Company acquired certain oil and gas producing non-operated properties located in Duval, Zapata, and Jim Hogg Counties, Texas and Escambia County in Alabama from Contango Oil and Gas for $11.6 million in cash.
 
-10-

(6)
Commodity Hedging Contracts and Other Derivatives
 
In the third quarter of 2006, the Company entered into two additional financial fixed price swaps with prices ranging from $7.99 per MMBtu to $8.23 per MMBtu covering a portion of the Company’s 2007 and 2008 production. The following financial fixed price swaps were outstanding with average underlying prices that represent hedged prices of commodities at various market locations at September 30, 2006:

 
Settlement
Period
 
Derivative
Instrument
 
Hedge
Strategy
 
Notional Daily Volume
MMBtu
 
Total of Notional Volume
MMBtu
 
Average Underlying Prices
MMBtu
 
Total of Proved Natural Gas Production Hedged (1)
 
Fair Market Value
Gain/(Loss)
(In thousands)
 
2006
   
Swap
   
Cash flow
   
45,000
   
4,140,000
 
$
7.92
   
46
%
$
11,176
 
2007
   
Swap
   
Cash flow
   
45,341
   
16,549,500
   
7.87
   
41
%
 
7,593
 
2008
   
Swap
   
Cash flow
   
39,909
   
14,606,616
   
7.63
   
35
%
 
(2,060
)
2009
   
Swap
   
Cash flow
   
26,141
   
9,541,465
   
6.99
   
26
%
 
(4,398
)
                       
44,837,581
             
$
12,311
 
                                             

(1) Estimated based on net gas reserves presented in the December 31, 2005 Netherland, Sewell, & Associates, Inc. reserve report.
 
In the third quarter of 2006, the Company entered into two additional costless collar transactions with an average floor price of $7.19 per MMBtu and an average ceiling price of $10.03 per MMBtu covering a portion of the Company’s 2007 production. The following costless collar transactions were outstanding with associated notional volumes and contracted ceiling and floor prices that represent hedge prices at various market locations at September 30, 2006:
 
Settlement
Period
 
Derivative
Instrument
 
Hedge
Strategy
 
Notional Daily Volume
MMBtu
 
Total of Notional Volume
MMBtu
 
Average Floor Price
MMBtu
 
Average Ceiling Price
MMBtu
 
Fair Market Value
Gain/(Loss)
(In thousands)
 
                               
2006
   
Costless Collar
   
Cash flow
   
10,000
   
920,000
 
$
8.83
 
$
14.00
 
$
3,175
 
2007
   
Costless Collar
   
Cash flow
   
10,000
   
3,650,000
   
7.19
 
$
10.03
   
1,922
 
                       
4,570,000
             
$
5,097
 
                                             
 
The total of proved natural gas production hedged in 2006 and 2007 for the costless collars is approximately 10% and 9%, respectively, based on the December 31, 2005 reserve report prepared by Netherland, Sewell, & Associates, Inc. 
 
The Company’s current cash flow hedge positions are with counterparties who are lenders in the Company’s credit facilities. This eliminates the need for independent collateral postings with respect to any margin obligation resulting from a negative change in fair market value of the derivative contracts in connection with the Company’s hedge related credit obligations. As of September 30, 2006, the Company made no deposits for collateral.
 
The following table sets forth the results of third party hedge transactions for the respective period for the Consolidated Statement of Operations:
 
   
Three Months Ended September 30, 2006
 
Nine Months Ended September 30, 2006
 
Natural Gas
             
Quantity settled (MMBtu)
   
5,060,000
   
15,015,000
 
Increase in natural gas sales revenue (In thousands)
 
$
9,114
 
$
19,804
 

The Company expects to reclassify gains of $14.6 million based on market pricing as of September 30, 2006 to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.
 
At September 30, 2006, the Company had derivative assets of $25.4 million of which $1.8 million is included in other assets on the Consolidated Balance Sheet. The Company also had derivative liabilities of $8.0 million on the Consolidated Balance Sheet at September 30, 2006. The derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and market prices on hedged volumes of the commodities as of September 30, 2006. Hedging activities related to cash settlements on commodities increased revenues by $9.1 million and $19.8 million for the three and nine months ended September 30, 2006.
 
-11-

Gains and losses related to ineffectiveness and derivative instruments not designated as hedging instruments are included in other income (expense). There was no ineffectiveness related to cash-flow hedges recorded for the three and nine months ended September 30, 2006 or for the three months ended September 30, 2005. There were no gains or losses related to derivative instruments not designated as hedged instruments for the six months ended June 30, 2005 (Predecessor) as no derivative instruments existed.  
 
(7)
Accrued Liabilities
 
The Company’s accrued liabilities consists of the following:
 

   
September 30, 2006
 
December 31, 2005
 
   
(In thousands)
 
Accrued capital costs
 
$
19,201
 
$
17,607
 
Accrued Calpine settlement     11,400     -  
Accrued lease operating expense
   
7,658
   
3,202
 
Accrued payroll and employee incentive expense
   
2,181
   
2,696
 
Other
   
2,164
   
4,892
 
Total
 
$
42,604
 
$
28,397
 
               

 
(8)
Asset Retirement Obligation
 
Activity related to the Company’s asset retirement obligation (“ARO”) is as follows:
 

   
Nine Months Ended September 30, 2006
 
   
(In thousands)
 
ARO as of January 1, 2006
 
$
9,467
 
Liabilities incurred during period
   
115
 
Liabilities settled during period
   
(15
)
Accretion expense
   
587
 
Other Adjustments
   
(4
)
ARO as of September 30, 2006
 
$
10,150
 
         

 
Of the total ARO, approximately $0.5 million is classified as a current liability at September 30, 2006.
 
(9)
Long-Term Debt
 
The Company’s credit facilities consist of a four-year senior secured revolving line of credit of up to $400.0 million with a borrowing base of $325.0 million and a five-year $75.0 million senior second lien term loan. All amounts drawn under the revolver are due and payable on July 7, 2009. The principal balance associated with the senior secured lien term loan is due and payable on July 7, 2010.
 
On September 30, 2006, the Company had outstanding borrowings and letters of credit of $240.0 million and $1.0 million, respectively. Net borrowing availability was $159.0 million at September 30, 2006.  The Company was in compliance with all covenants at September 30, 2006.
 
(10)
Commitment 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 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.
 
-12-

Calpine Bankruptcy
 
Calpine Corporation and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (the “Court”) on December 20, 2005. Calpine Energy Services, L.P., which filed for bankruptcy, has continued to make the required deposits into the Company’s margin account and to timely pay for natural gas production it purchases from the Company’s subsidiaries under various natural gas supply agreements. As part of the Acquisition, Calpine and the Company entered into a Transition Services Agreement, pursuant to which both parties were to provide certain services for the other for various periods of time. Calpine’s obligation to provide services under the Transition Services Agreement ceased on July 6, 2006 and certain of Calpine’s services ceased prior to the conclusion of the contract, which in neither case had any material effect on the Company. Additionally, Calpine Producer Services, L.P., which filed for bankruptcy, generally is performing its obligations under the Marketing and Services Agreement with the Company.
 
There remains the possibility, however, that there will be issues between the Company and Calpine that could amount to material contingencies in relation to the Purchase and Sale Agreement and interrelated agreements concurrently executed therewith, dated July 7, 2005, by and among Calpine, the Company, and various other signatories thereto (collectively, the “Purchase Agreement”), including unasserted claims and assessments with respect to (i) the still pending Purchase Agreement and the amounts that will be payable in connection therewith, (ii) whether or not Calpine and its affiliated debtors will, in fact, perform their remaining obligations in connection with the Purchase Agreement; and (iii) the ultimate disposition of the remaining Non-Consent Properties (and related royalty revenues). Calpine has specific obligations to the Company under the Purchase Agreement relating to these matters, and also has “further assurances” duties to the Company under the Purchase Agreement.
 
In addition, as to certain of the other oil and natural gas properties the Company purchased from Calpine in the Acquisition and for which payment was made on July 7, 2005, the Company will seek additional documentation from Calpine to eliminate any open issues in the Company’s title or resolve any issues as to the clarity of the Company’s ownership. Requests for additional documentation are customary in connection with transactions similar to the Acquisition. In the Acquisition, certain of these properties require ministerial governmental action approving the Company as qualified assignee and operator, which is typically required even though in most cases Calpine has already conveyed the properties to the Company free and clear of mortgages and liens in favor of Calpine’s creditors. As to certain other properties, the documentation delivered by Calpine at closing under the Purchase Agreement was incomplete. The Company remains hopeful that Calpine will continue to work cooperatively with the Company to secure these ministerial governmental approvals and to accomplish the curative corrections for all of these properties. In addition, as to all properties acquired by the Company in the Acquisition, Calpine contractually agreed to provide the Company with such further assurances as the Company may reasonably request. Nevertheless, as a result of Calpine’s bankruptcy filing, it remains uncertain as to whether Calpine will respond cooperatively. If Calpine does not fulfill its contractual obligations and does not complete the documentation necessary to resolve these issues, the Company will pursue all available remedies, including but not limited to a declaratory judgment to enforce the Company’s rights and actions to quiet title. After pursuing these matters, if the Company experiences a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to the Company, an outcome the Company’s management considers to be remote, then the Company could experience losses which could have a material adverse effect on the Company’s financial condition, statement of operations and cash flows.
 
On June 29, 2006, Calpine filed a motion in connection with its pending bankruptcy proceeding in the Court seeking the entry of an order authorizing Calpine to assume certain oil and natural gas leases Calpine has previously sold or agreed to sell to the Company in the Acquisition, to the extent those leases constitute “unexpired leases of non-residential real property” and were not fully transferred to the Company at the time of Calpine’s filing for bankruptcy. According to this motion, Calpine filed the motion in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a statutory deadline. Calpine’s motion did not request that the Court determine whether these properties belong to the Company or Calpine, but the Company understands it was meant to allow Calpine to preserve and avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may possess, if any, in these oil and natural gas leases. The Company disputes Calpine’s contention that it may have an interest in any significant portion of these oil and natural gas leases and intends to take the necessary steps to protect all of the Company’s rights and interest in and to the leases. On July 7, 2006, the Company filed an objection in response to Calpine’s motion, wherein the Company asserted that oil and natural gas leases constitute interests in real property that are not subject to “assumption” under the Bankruptcy Code. In the objection the Company also requested that (a) the Court eliminate from the order certain Federal offshore leases from the Calpine motion because these properties were fully conveyed to the Company in July 2005, and the Minerals Management Service has subsequently recognized the Company as owner and operator of these properties, and (b) any order entered by the Court be without prejudice to, and fully preserve the Company's rights, claims and legal arguments regarding the characterization and ultimate disposition of the remaining described oil and natural gas properties. In the Company’s objection, the Company also urged the Court to require the parties to promptly address and resolve any remaining issues under the pre-bankruptcy definitive agreements with Calpine and proposed to the Court that the parties seek arbitration (or at least mediation) to complete the following:
 
 
·
Calpine’s conveyance of the Non-Consent Properties to the Company;
 
 
·
Calpine’s execution of all documents and performance of all tasks required under “further assurances” provisions of the Purchase Agreement with respect to certain of the oil and natural gas properties for which the Company has already paid Calpine; and
 

-13-


 
 
·
Resolution of the final amounts the Company is to pay Calpine, which the Company has concluded is approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations.
 
At a hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy took the following steps:
 
 
·
In response to an objection filed by the Department of Justice and asserted by the California State Lands Commission that the Debtors’ Motion to Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not allow adequate time for an appropriate response, Calpine withdrew from the list of Oil and Gas Leases that were the subject of the Motion those leases issued by the United States (and managed by the Minerals Management Service of the United States Department of Interior) (the “MMS Oil and Gas Leases”) and the State of California (and managed by the California State Lands Commission) (the “CSLC Leases”). Calpine and both the Department of Justice and the State of California agreed to an extension of the existing deadline to November 15, 2006 to assume or reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases are leases subject to Section 365. The effect of these actions was to render the objection of the Company inapplicable at that time; and
 
 
·
The Court also encouraged Calpine and the Company to arrive at a business solution to all remaining issues including approximately $68 million payable to Calpine for conveyance of the Non-Consent Properties.
 
On August 1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy asserting claims against a variety of Calpine debtors seeking recovery of $27.9 million in liquidated amounts and unliquidated damages in amounts that can not presently be determined. The Company continues to undertake to work with Calpine on a cooperative and expedited basis toward resolution of unresolved conveyance of properties and post closing adjustments under the Purchase Agreement.
 
By a proposed stipulation dated October 18, 2006, Calpine and the Department of Justice agreed to further extend the deadline to assume or reject the MMS Oil and Gas Leases under Section 365 of the Bankruptcy Code from November 15, 2006 to January 31, 2007, to the extent the MMS Oil and Gas Leases are “unexpired leases” subject to Section 365. The Company has filed an objection to this proposed stipulation requesting the Court condition its approval of the proposed stipulation on inclusion of appropriate language adequately reserving the Company’s rights with respect to the MMS Oil and Gas Leases and clarifying that the United States Department of Interior will not take regulatory action with respect to such leases without first seeking relief from the Court. On November 1, 2006, Calpine and the State of California submitted a similar proposed stipulation extending the deadline to assume or reject the CSLC Leases until January 31, 2007. The Company will take all necessary action to ensure its rights under the CSLC Leases are fully protected.
 
The Company continues to believe that it is unlikely that any challenges by the Calpine debtors or their creditors to the fairness of the Acquisition would be successful. However, there can be no assurance that Calpine, its creditors or interest holders may not challenge the fairness of some or all of the Acquisition. For a number of reasons, including the Company’s understanding of the process that Calpine followed in allowing market forces to set the purchase price for the Acquisition, the Company believes that it is unlikely that any challenge to the fairness of the Acquisition would be successful.
 
Environmental
 
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the cost can be reasonably estimated. The Company performed an environmental remediation study for two sites in California and correspondingly, recorded a liability, which at September 30, 2006 and December 31, 2005 was $0.1 million and $0.7 million, respectively. The Company does not expect that the outcome of our environmental matters discussed above will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
 
Participation in a Regional Carbon Sequestration Partnership 
 
The Company has made preliminary preparations in connection with its participating in the United States Department of Energy’s (“DOE”) Regional Carbon Sequestration Partnership program (“WESTCARB”) with the California Energy Commission and the University of California, Lawrence Berkeley Laboratory. The Company has been selected by the DOE for this project. Under WESTCARB, the Company would be required to drill a carbon injection well, recondition an idle well for use as an observation well and provide WESTCARB with certain proprietary well data and technical assistance related to the evaluation and injection of carbon
 

-14-

 
 
 
 
 
 
 
 
dioxide into a suitable natural gas reservoir in the Sacramento Basin. The Company’s maximum contribution to WESTCARB is $1.0 million and will be limited to 20% of the total contributions to the project. The Company will not have any obligation under the WESTCARB project until it has entered into an acceptable contract and the project has obtained proper and necessary local, state and federal regulatory approvals, land use authorizations and third party property rights. No accrual was recorded at September 30, 2006 as the study is still in the preliminary stage.
 
(11)
Comprehensive Income
 
The Company’s total comprehensive income (loss) is shown below. For the six months ended June 30, 2005, the Predecessor did not have transactions affecting comprehensive income.
 

   
Three Months Ended
September 30, 2006
 
Three Months Ended
September 30, 2005
 
Nine Months Ended
September 30, 2006
 
   
(In thousands)
 
Accumulated other comprehensive loss - beginning of period
$
(11,852
)
     
$
-
       
$
(50,731
)
Net income
   
11,922
         
8,207
         
31,412
       
                                       
Change in fair value of derivative hedging instruments
   
45,638
         
(109,392
)
       
119,036
       
Hedge settlements reclassed to income
   
(9,114
)
       
2,221
         
(19,804
)
     
Tax provision related to hedges
   
(13,880
)
       
40,725
         
(37,709
)
     
Total other comprehensive income (loss)
   
22,644
   
22,644
   
(66,446
)
 
(66,446
)
 
61,523
   
61,523
 
                                       
Comprehensive income
   
34,566
         
(58,239
)
       
92,935
       
Accumulated other comprehensive income (loss)
   
 
$
10,792
   
 
$
(66,446
)
 
 
$
10,792
 
                                       

 
(12)
Stock-Based Compensation
 
Adoption of SFAS-123R
 
On January 1, 2003, Calpine prospectively adopted the fair market value method of accounting for stock-based employee compensation pursuant to SFAS No. 123. Expense amounts included in the combined historical financial statements for the six months ended June 30, 2005 are based on stock based compensation granted to employees by Calpine. Stock options were granted at an option price equal to the quoted market price at the date of the grant or award.
 
In determining the Company’s accounting policies, the Company chose to apply the intrinsic value method pursuant to APB No. 25, “Stock Issued to Employees” (“APB No. 25”), effective July 1, 2005. Under APB No. 25, no compensation expense is recognized when the exercise price for options granted equals the fair value of the Company’s common stock on the date of the grant. Accordingly, the provisions of SFAS No. 123 permit the continued use of the method prescribed by APB No. 25 but require additional disclosures, including pro forma calculations of net income (loss) per share as if the fair value method of accounting prescribed by SFAS No. 123 had been applied.
 
Following is a summary of the Company’s net income and net income per share for the three months ended September 30, 2005 as reported and on a pro forma basis as if the fair value method prescribed by SFAS No. 123 had been applied.
 

-15-



   
Three Months Ended September 30, 2005
 
   
(In thousands)
 
Net income, as reported
 
$
8,207
 
Deduct: stock-based employee compensation expense determined under
the fair value method for all awards, net of related tax effects
   
(288
)
Pro forma net income
 
$
7,919
 
Net income per share:
       
Basic, as reported
 
$
0.16
 
Basic, pro forma
 
$
0.16
 
Diluted, as reported
 
$
0.16
 
Diluted, pro forma
 
$
0.16
 

 
Effective January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123R, whereby the Company records stock-based compensation expense based on the fair value of awards described below. Stock-based compensation expense recorded for all share-based payment arrangements for the three and nine months ended September 30, 2006 (Successor) was $1.0 million and $4.3 million, with a tax benefit of $0.4 million and $1.6 million, respectively. Stock-based compensation expense for the three months ended September 30, 2005 (Successor) was $1.7 million with a tax benefit of $0.7 million. For the six months ended June 30, 2005 (Predecessor), stock-based compensation expense recorded was $0.2 million with a tax benefit of $0.1 million. The remaining compensation expense associated with total unvested awards as of September 30, 2006 was $9.8 million.
 
Successor
 
2005 Long-Term Incentive Plan
 
In July 2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan whereby stock is granted to employees, officers and directors of the Company. The Plan allows for the grant of stock options, stock awards, restricted stock, restricted stock units, stock appreciation rights, performance awards and other incentive awards. Employees, non-employee directors and other service providers of the Company and its affiliates who, in the opinion of the Compensation Committee or another Committee of the Board of Directors (the “Committee”), are in a position to make a significant contribution to the success of the Company and the Company’s affiliates are eligible to participate in the Plan. The Plan provides for administration by the Committee, which determines the type and size of award and sets the terms, conditions, restrictions and limitations applicable to the award within the confines of the Plan’s terms. The maximum number of shares available for grant under the plan is 3,000,000 shares of common stock plus any shares of common stock that become available under the Plan for any reason other than exercise, such as shares traded for the related tax liabilities of employees. The maximum number of shares of common stock available for grant of awards under the Plan to any one participant is (i) 300,000 shares during any fiscal year in which the participant begins work for Rosetta and (ii) 200,000 shares during each fiscal year thereafter.
 
Stock Options
 
The Company has granted stock options under its 2005 Long-Term Incentive Plan. Options generally expire ten years from the date of grant. The exercise price of the options can not be less than the fair market value per share of the Company’s common stock on the grant date.
 
The weighted average fair value at date of grant for options granted during the nine months ended September 30, 2006 was $10.69 per share. The weighted average fair value at date of grant for options granted during the three months ended September 30, 2005 (Successor) was $9.53 per share and for the six months ended June 30, 2005 (Predecessor), the weighted average fair value at date of grant for options granted was $1.27 per share. The fair value of options granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:
 

-16-



   
Successor
 
Successor
   
Predecessor
 
   
Nine Months Ended
September 30, 2006
 
Three Months Ended
September 30, 2005
   
Six Months Ended
June 30, 2005
 
Expected option term (years)
   
6.5
   
6.5
     
2.5
 
Expected volatility
   
56.65
%
 
56.65
%
   
58.00
%
Expected dividend rate
   
0.00
%
 
0.00
%
   
0.00
%
Risk free interest rate
   
4.33% - 5.15
%
 
4.03% - 4.33
%
   
3.62
%

 
The Company has assumed an annual forfeiture rate of 5% for the awards granted in 2006 based on the Company’s history for this type of award to various employee groups. Compensation expense is recognized ratably over the requisite service period and immediately for retirement-eligible employees.
 
The following table summarizes information related to outstanding and exercisable options held by the Company’s employees at September 30, 2006:
 

   
Shares
 
Weighted Average Exercise Price
Per Share
 
Weighted Average Remaining Contractual Term
(In years)
 
Aggregate Intrinsic Value
(In thousands)
 
Outstanding at the December 31, 2005
   
706,550
 
$
16.28
             
Granted
   
245,950
   
17.83
             
Exercised
   
(32,000
)
 
16.10
             
Forfeited
   
(59,875
)
 
16.38
             
Outstanding at September 30, 2006
   
860,625
 
$
16.73
   
9.00
 
$
747
 
                           
Options Exercisable at September 30, 2006
   
349,649
 
$
16.29
   
8.87
 
$
393
 
                           

 
Stock-based compensation expense recorded for stock option awards for the three and nine months ended September 30, 2006 is $0.6 million and $2.1 million, respectively. There was no stock-based compensation expense for stock option awards for the three months ended September 30, 2005. Stock-based compensation expense recorded for stock option awards for the six months ended June 30, 2005 (Predecessor) is $0.2 million. Unrecognized expense as of September 30, 2006 for all outstanding stock options is $5.3 million and will be recognized over a weighted average period of 1.47 years.
 
The total intrinsic value of options exercised during the nine months ended September 30, 2006 was $0.1 million. For the six months ended June 30, 2005, the Predecessor did not have any options exercised. The fair value of awards vested for the nine months ended September 30, 2006 was $6.3 million.
 
Restricted Stock
 
The Company has granted stock under its 2005 Long-Term incentive Plan with a maximum contractual life of three years. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The Company also assumes an annual forfeiture rate of 5 % for these awards based on the Company’s history for this type of award to various employee groups.
 
-17-

The following table summarizes information concerning restricted stock held by the Company’s employees at September 30, 2006:
 
   
Shares
 
Weighted Average Grant Date Fair Value
 
Non-vested shares outstanding at December 31, 2005
   
581,900
 
$
16.27
 
Granted
   
129,800
   
17.70
 
Vested
   
(344,975
)
 
16.11
 
Forfeited
   
(35,125
)
 
16.18
 
Non-vested shares outstanding at September 30, 2006
   
331,600
 
$
17.00
 
               
 
The non-vested restricted stock outstanding at September 30, 2006 vests at a rate of 25% on the first anniversary of the date of grant, 25% on the second anniversary and 50% on the third anniversary. The restrictions on 270,000 shares lapsed on the day after the Company’s effective date of its recently completed initial public offering in February 2006 and therefore vested in the first quarter of 2006.
 
Stock-based compensation expense recorded for restricted stock awards for the three and nine months ended September 30, 2006 was $0.4 million and $2.2 million, respectively, and $1.7 million for the three months ended September 30, 2005. Unrecognized expense as of September 30, 2006 for all outstanding restricted stock awards is $4.5 million and will be recognized over a weighted average period of 1.58 years.
 
Predecessor
 
Retirement Savings Plan
 
The Predecessor had a defined contribution savings plan, under Section 401(a) and 501(a) of the Internal Revenue Code, in which the Predecessor’s employees were eligible to participate. The plan provided for tax deferred salary deductions and after-tax employee contributions. Employees were immediately eligible upon hire. Contributions included employee salary deferral contributions and employer profit-sharing contributions made entirely in cash of 4% of employees’ salaries, with employer contributions capped at $8,400 per year for 2005. There were no employer profit-sharing contributions for the six months ended June 30, 2005.
 
2000 Employee Stock Purchase Plan
 
The Predecessor adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000. The Predecessor’s eligible employees could, in the aggregate, purchase up to 28,000,000 shares of common stock at semi-annual intervals through periodic payroll deductions. Purchases were limited to either a maximum value of $25,000 per calendar year based on the IRS Code Section 423 limitation or limited to 2,400 shares per purchase interval. Shares were purchased on May 31 and November 30 of each year until termination of the plan on May 31, 2010. Under the ESPP, 36,817 shares were issued to Calpine’s employees at a weighted average fair market value of $2.53 per share, for the six months ended June 30, 2005. The purchase price was 85% of the lower of (i) the fair market value of the common stock on the participant’s entry date into the offering period, or (ii) the fair market value on the semi-annual purchase date. The purchase price discount was significant enough to cause the ESPP to be considered compensatory under SFAS No. 123. As a result, the ESPP was accounted for as stock-based compensation in accordance with SFAS No. 123 for the six months ended June 30, 2005. For the six months ended June 30, 2005, compensation expense of $0.2 million was recorded under the ESPP.
 
1996 Stock Incentive Plan
 
The Predecessor adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996 in which certain of the Company’s employees were eligible to participate. The SIP succeeded the Predecessor’s previously adopted stock option program. Under the SIP, the option exercise price generally equaled the stock’s fair market value on date of grant. The SIP options generally vested ratably over four years and expired after 10 years. As of June 30, 2005, the amount of shares outstanding under the 1996 incentive plan were 754,284.
 
(13)
Earnings Per Share
 
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if contracts to issue common stock and related stock options were exercised at the end of the period.
 
-18-

The following is a calculation of basic and diluted weighted average shares outstanding:
 
   
Successor
 
Successor
   
Predecessor
 
   
Three Months Ended
September 30,
 
Nine Months Ended September 30
   
Six Months Ended
June 30,
 
 
 
2006
 
2005
 
2006
   
2005
 
   
                                               (In thousands)
   
Basic weighted average number of shares outstanding
   
50,282
   
50,000
   
50,211
     
50,000
 
Dilution effect of stock option and awards at the end of
the period
   
144
   
160
   
173
     
160
 
Diluted weighted average number of shares outstanding
   
50,426
   
50,160
   
50,384
     
50,160
 
                             
Stock awards and shares excluded from diluted earnings
per share due to anti-dilutive effect
   
179
   
-
   
229
     
-
 
                             

 
(14)
Operating Segments
 
The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information”. See below for information by geographic location.
 
Geographic Area Information
 
The Company owns oil and natural gas interests in eight main geographic areas all within in the United States. Geographic revenue and property, plant and equipment information below for the three and nine months ended September 30, 2006, the three months ended September 30, 2005 and the six months ended June 30, 2005 are based on physical location of the assets at the end of each period.

 
   
Successor
 
Successor
   
Predecessor
 
   
Three Months Ended
September 30,
 
Nine Months Ended September 30,
   
Six Months Ended June 30,
 
   
2006 (1)
 
2005 (1)
 
2006 (1)
   
2005
 
Oil and Natural Gas Revenue
 
                                            (In thousands)
   
California
 
$
18,820
 
$
20,893
 
$
54,921
   
$
43,385
 
Lobo
   
21,009
   
18,888
   
50,090
     
26,474
 
Perdido
   
4,939
   
5,712
   
21,722
     
12,380
 
State Waters
   
1,750
   
2,964
   
7,039
     
2,345
 
Other Onshore
   
8,205
   
4,267
   
20,381
     
7,662
 
Gulf of Mexico
   
6,172
   
6,463
   
22,093
     
10,542
 
Rockies
   
591
   
126
   
1,555
     
161
 
Mid-Continent
   
596
   
767
   
1,506
     
842
 
Other
   
1
   
6
   
11
     
40
 
   
$
62,083
 
$
60,086
 
$
179,318
   
$
103,831
 
                             
 
 
(1)
Excludes the effects of hedging.
 

-19-



   
Successor
 
   
September 30,
 
December 31,
 
   
2006
 
2005
 
Oil and Natural Gas Properties (2)
 
(In thousands)
California
 
$
430,819
 
$
386,513
 
Lobo
   
398,754
   
368,276
 
Perdido
   
43,890
   
25,983
 
State Waters
   
21,894
   
12,067
 
Other Onshore
   
100,308
   
75,737
 
Gulf of Mexico
   
95,375
   
77,416
 
Rockies
   
35,038
   
21,224
 
Mid-Continent
   
8,676
   
5,969
 
Other
   
3,868
   
2,912
 
   
$
1,138,622
 
$
976,097
 
               
 
 
 
(2)
Oil and natural gas properties at September 30, 2006 and December 31, 2005 are reported gross. Under the full cost method of accounting for oil and natural gas properties, depreciation, depletion and amortization is not allocated to properties.
 

-20-


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
Various statements, other than statements of historical fact, included in this report, are forward-looking statements. In some cases, you can identify a forward-looking statement by terminology such as “may”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or other comparable terminology.
 
The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions 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. Management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties, see Item 1A. Risk Factors in our annual report on Form 10-K for the year ended December 31, 2005 and Item 1A. Risk Factors in this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events 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 the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to various factors, including:  
 
·
The timing and extent of changes in commodity prices, particularly natural gas;
 
·
Various drilling and exploration risks that may delay or prevent commercial operation of new wells;  
 
·
Economic slowdowns that can adversely affect consumption of oil and natural gas by businesses and consumers;
 
·
Resources expended in connection with Calpine’s bankruptcy including our increased costs for lawyers, consultant experts and related expenses, as well as the lost opportunity costs associated with our internal resources dedicated to these matters;
 
·
Uncertainties that actual costs may be higher than estimated;
 
·
Factors that impact the exploration of oil or natural gas resources, such as the geology of a resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas;
 
·
Uncertainties associated with estimates of oil and natural gas reserves;
 
·
Our ability to access the capital markets on attractive terms or at all;
 
·
Refusal by or inability of our current or potential counterparties or vendors to enter into transactions with us or fulfill their obligations to us;
 
·
Our inability to obtain credit or capital in desired amounts or on favorable terms;
 
·
Present and possible future claims, litigation and enforcement actions;
 
·
Effects of the application of regulations, including changes in regulations or the interpretation thereof;
 
·
Availability of processing and transportation;
 
·
Potential for disputes with mineral lease and royalty owners regarding calculation and payment of royalties, including basis of pricing, adjustment for quality, measurement and allowable costs and expenses;
 
·
Developments in oil-producing and natural gas-producing countries;
 
·
Competition in the oil and natural gas industry; and
 
·
Adverse weather conditions, hurricanes, tropical storms, earthquakes, mud slides, flooding and other natural disasters which may occur in areas of the United States in which we have operations, including the Federal waters of the Gulf of Mexico, as well as new energy package insurance coverage limitations related to any single named windstorm; and uncertainty with respect to potential environmental, health and safety liabilities.
 

-21-


ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
Rosetta Resources Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties in the United States. We were formed as a Delaware corporation in June 2005. In July 2005, we acquired the domestic oil and natural gas business of Calpine Corporation and its affiliates. Our main operations are concentrated in the Sacramento Basin of California, the Lobo and Perdido Trends in South Texas, the Gulf of Mexico and the Rocky Mountains.
 
In this section, we sometimes refer to Rosetta as “Successor”, and we sometimes refer to Calpine Corporation and its affiliates, from whom we acquired our initial domestic oil and natural gas business and associated oil and natural gas properties as “Predecessor”. Additionally, we sometimes refer to our acquisition of Calpine’s domestic oil and natural gas business as the “Acquisition”.
 
In the first nine months of 2006, relatively high oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. Given the inherent volatility of oil and natural gas prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production. Our future earnings will also be impacted by the changes in fair market value of hedges we executed to mitigate the volatility in the changes of oil and natural gas prices in future periods when such positions are settled as these instruments meet the criteria to be accounted for as cash flow hedges. Until settlement, the changes in fair market value of our hedges will be included as a component of stockholder’s equity to the extent effective. In periods of rising prices, these transactions will mitigate future earnings and in periods of declining prices will increase future earnings in the respective period the positions are settled.
 
Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce our reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. The permitting and approval process has been more difficult in recent years than in the past due to increased activism from environmental and other groups and has extended the time it takes us to receive permits. We can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs of foregone opportunities resulting from delays.
 
Financial Highlights
 
For the nine month period ended September 30, 2006, we produced 24.4 Bcfe with average revenue of $8.16 per Mcfe. Our natural gas production for the nine months ended September 30, 2006 was 21.9 Bcf and our oil production for the same period was 414.3 MBbls. Our average natural gas prices were $7.84 per Mcf, including the effects of hedging, and average oil prices for the same period were $65.99 per Bbl. For the nine months ended September 30, 2006, we had revenues of $199.1 million including the effects of hedging with net income of $31.4 million and diluted earnings per share of $0.62.
 
Calpine Bankruptcy
 
On December 20, 2005, Calpine and certain of its subsidiaries, including Calpine Fuels, filed for protection under federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (“the Court”). The filing raises certain concerns regarding aspects of our relationship with Calpine which we will closely monitor as the Calpine bankruptcy proceeds. The following are our principal areas of concern:
 
 
·
Calpine, its creditors or interest holders may challenge the fairness of some or all of the Acquisition. For a number of reasons, including our understanding of the process which Calpine followed in allowing market forces to set the purchase price for the Acquisition, we believe that it is unlikely that any challenge to the fairness of the Acquisition would be successful;
 

-22-


 
·
The bankruptcy proceeding may prevent, frustrate or delay our ability to receive record legal title to certain properties originally listed as determined to be Non-Consent Properties which we are entitled to obtain under the Purchase Agreement;
 
 
·
Additionally, the bankruptcy proceeding may prevent, frustrate or delay our ability to receive corrective documentation from Calpine for certain properties that we bought from Calpine and paid for, in cases where Calpine delivered incomplete documentation, including documentation related to certain ministerial governmental approvals; and
 
·      Calpine may stop purchasing gas from us under our gas purchase contracts with Calpine. Since the date of the bankruptcy filing, Calpine has continued buying natural gas from us and making timely payments. Calpine has sought and obtained bankruptcy court approval to continue payments to us for our delivery of natural gas under our gas purchase and sale contracts with Calpine. Under the terms of these contracts, in the event of Calpine’s default in making timely payments, we are entitled to suspend deliveries to Calpine and instead sell this gas to third parties at comparable prices and terms until Calpine cures any such default (Calpine having 60 days after notice to do so). In terms of the likely impact of Calpine’s default under these contracts, should this ever occur, we expect to be able to minimize our exposure for Calpine’s non-payment to four days of sales under these contracts, or approximately $1.5 million in lost sales at production rates and prices as of September 30, 2006. 
 
Transfers Pending at Calpine’s Bankruptcy
 
At the closing of the Acquisition on July 7, 2005, we retained approximately $75 million of the purchase price in respect to Non-Consent Properties identified by Calpine as requiring third party consents or waivers of preferential rights to purchase that were not received before closing. Those Non-Consent Properties were not included in conveyances delivered at the closing. Subsequent analysis determined that a portion of the Non-Consent Properties, with an approximate allocation value of $29 million under the Purchase Agreement did not require consents or waivers. For that portion of the Non-Consent Properties for which third party consents were in fact required (having an approximate value of $39 million under the Purchase Agreement) and for which we obtained the required consents or waivers, as well as for all Non-Consent Properties that did not require consents or waivers, we believe that Calpine was and is obligated to have transferred to us the record title, free of any mortgages and other liens.
 
The approximate allocated value under the Purchase Agreement for the portion of the Non-Consent Properties subject to a third party’s preferential right to purchase is $7.4 million. We have retained $7.1 million of the purchase price under the Purchase Agreement for the Non-Consent Properties subject to a third party’s preferential right to purchase, and, in addition, a post-closing adjustment is required to credit Rosetta for approximately $0.3 million for a property which was transferred to us but will be transferred to the appropriate third party under its exercised preferential purchase right upon Calpine’s performance of its obligations under the Purchase Agreement.
 
We believe all conditions precedent for our receipt of record title, free of any mortgages or other liens, for substantially all of the Non-Consent Properties (excluding that portion of these properties subject to a third party’s preferential right to purchase) were satisfied earlier, and certainly no later than December 15, 2005, when we tendered once again the amounts necessary to conclude the settlement of the Non-Consent Properties.
 
We believe we are the equitable owner of each of the Non-Consent Properties for which Calpine was and is obligated to have transferred to us the record title and that such properties are not part of Calpine’s bankruptcy estate. Upon our receipt from Calpine of record title, free of any mortgages or other liens, to these Non-Consent Properties and further assurances required to eliminate any open issues on title to the remaining properties discussed below, we are prepared to pay Calpine approximately $68 million, subject to appropriate adjustment for the associated net revenues and expenses through December 15, 2005. Our statement of operations for the nine months ended September 30, 2006 does not include any net revenues or production from any of the Non-Consent Properties.
 
If Calpine does not provide us with record title, free of any mortgages for all of these properties and other liens, to any of the Non-Consent Properties (excluding that portion of these properties subject to a third party’s preferential right to purchase), we will have a total of approximately $68 million available to us for general corporate purposes, including for the purpose of acquiring additional properties. We also have approximately $7.1 million, previously withheld for that portion of the Non-Consent Properties subject to a third party’s preferential right to purchase, which will also be available to us for general corporate purposes, including for the purpose of acquiring additional properties.
 
In addition, as to certain of the other oil and natural gas properties we purchased from Calpine in the Acquisition and for which payment was made on July 7, 2005, we will seek additional documentation from Calpine to eliminate any open issues in our title or resolve any issues as to the clarity of our ownership. Requests for additional documentation are customary in connection with transactions similar to the Acquisition. In the Acquisition, certain of these properties require ministerial governmental action approving us as qualified assignee and operator, which is typically required even though in most cases Calpine has already conveyed
 

-23-


the properties to us free and clear of mortgages and liens in favor of Calpine’s creditors. As to certain other properties, the documentation delivered by Calpine at closing under the Purchase Agreement was incomplete. We remain hopeful that Calpine will continue to work cooperatively with us to secure these ministerial governmental approvals and to accomplish the curative corrections for all of these properties. In addition, as to all properties acquired by us in the Acquisition, Calpine contractually agreed to provide us with such further assurances as we may reasonably request. Nevertheless, as a result of Calpine’s bankruptcy filing, it remains uncertain as to whether Calpine will respond cooperatively. If Calpine does not fulfill its contractual obligations and does not complete the documentation necessary to resolve these issues, we will pursue all available remedies, including but not limited to a declaratory judgment to enforce our rights and actions to quiet title. After pursuing these matters, if we experience a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to us, an outcome we consider to be remote, then we could experience losses which could have a material adverse effect on our financial condition, statement of operations and cash flows.
 
On June 29, 2006, Calpine filed a motion in connection with its pending bankruptcy proceeding in the Court seeking the entry of an order authorizing Calpine to assume certain oil and natural gas leases Calpine has previously sold or agreed to sell to us in the Acquisition, to the extent those leases constitute “unexpired leases of non-residential real property” and were not fully transferred to us at the time of Calpine’s filing for bankruptcy. According to this motion, Calpine filed the motion in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a statutory deadline. Calpine’s motion did not request that the Court determine whether these properties belong to us or Calpine, but we understand it was meant to allow Calpine to preserve and avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may possess, if any, in these oil and natural gas leases. We dispute Calpine’s contention that it may have an interest in any significant portion of these oil and natural gas leases and intend to take the necessary steps to protect all of our rights and interest in and to the leases. On July 7, 2006, we filed an objection in response to Calpine’s motion, wherein we asserted that oil and natural gas leases constitute interests in real property that are not subject to “assumption” under the Bankruptcy Code. The objection also requested that (a) the Court eliminate from the order certain Federal offshore leases from the Calpine motion because these properties were fully conveyed to us in July 2005, and the Minerals Management Service has subsequently recognized us as owner and operator of these properties and (b) any order entered by the Court be without prejudice to, and fully preserve our rights, claims and legal arguments regarding the characterization and ultimate disposition of the remaining described oil and natural gas properties. In our objection, we also urged the Court to require the parties to promptly address and resolve any remaining issues under the pre-bankruptcy Purchase Agreement with Calpine and proposed to the Court that the parties seek arbitration (or at least mediation) to complete the following:
 
 
·
Calpine’s conveyance of the Non-Consent Properties to us;
 
 
·
Calpine’s execution of all documents and performance of all tasks required under “further assurances” provisions of the Purchase Agreement with respect to certain of the oil and natural gas properties for which we have already paid Calpine; and
 
 
·
Resolution of the final amounts we are to pay Calpine, which we have concluded is approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations.
 
At a hearing held on July 12, 2006, the Court in Calpine Corporation’s bankruptcy took the following steps:
 
 
·
In response to an objection filed by the Department of Justice and asserted by the California State Lands Commission that the Debtors’ Motion to Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not allow adequate time for an appropriate response, Calpine withdrew from the list of Oil and Gas Leases that were the subject of the Motion those leases issued by the United States (and managed by the Minerals Management Service of the United States Department of Interior) (the “MMS Oil and Gas Leases”) and the State of California (and managed by the California State Lands Commission) (the “CSLC Leases”). Calpine and both the Department of Justice and the State of California agreed to an extension of the existing deadline to November 15, 2006 to assume or reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases are leases subject to Section 365. The effect of these actions was to render our objection inapplicable at that time; and
 
 
·
The Court also encouraged Calpine and us to arrive at a business solution to all remaining issues including approximately $68 million payable to Calpine for conveyance of the Non-Consent Properties.
 
On August 1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy asserting claims against a variety of Calpine debtors seeking recovery of $27.9 million in liquidated amounts and unliquidated damages in amounts that can not presently be determined.
 

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By a proposed stipulation dated October 18, 2006, Calpine and the Department of Justice agreed to further extend the deadline to assume or reject the MMS Oil and Gas Leases under Section 365 of the Bankruptcy Code from November 15, 2006 to January 31, 2007, to the extent the MMS Oil and Gas Leases are “unexpired leases” subject to Section 365. We have filed an objection to this proposed stipulation requesting the Court condition its approval of the proposed stipulation on inclusion of appropriate language adequately reserving our rights with respect to the MMS Oil and Gas Leases and clarifying that the United States Department of Interior will not take regulatory action with respect to such leases without first seeking relief from the Court. On November 1, 2006, Calpine and the State of California submitted a similar proposed stipulation extending the deadline to assume or reject the CSLC Leases until January 31, 2007. We will take all necessary action to ensure our rights under the CSLC Leases are fully protected.
 
We continue to undertake to work with Calpine on a cooperative and expedited basis toward resolution of unresolved conveyance of properties and post closing adjustments under the Purchase Agreement.
 
Critical Accounting Policies and Estimates
 
In our Annual Report on Form 10-K for the year ended December 31, 2005, 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, asset retirement obligations, income taxes and stock-based compensation.
 
We assess the impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. If the net capitalized costs of oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, it would reduce earnings and impact shareholders’ equity in the period of occurrence and result in a lower depreciation, depletion and amortization expense in the future.
 
Our ceiling test computation was calculated using hedge adjusted market prices at September 30, 2006 which were based on a Henry Hub gas price of $4.18 per MMBtu and a West Texas Intermediate oil price of $62.91 per barrel. The use of these prices resulted in a writedown of $182.1 million at September 30, 2006. Cash flow hedges of natural gas production in place at September 30, 2006 increased the calculated ceiling value by approximately $92.2 million (net of tax). However, subsequent to September 30, 2006 the market price for Henry Hub increased to $7.42 per MMBtu and the price for West Texas Intermediate decreased to $58.07 per barrel, and utilizing these prices, our net capitalized costs of oil and gas properties exceeded the ceiling amount. As a result no writedown was recorded for the quarter ended September 30, 2006. The ceiling value calculated using subsequent prices includes approximately $17.9 million related to the positive effects of future cash flow hedges of natural gas production. Due to the volatility of commodity prices, should natural gas and oil prices decline in the future, it is possible that a writedown could occur.
 
On January 1, 2006, we adopted the accounting policies described in Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004) “Share-Based Payments” (“SFAS No. 123R”). This statement applies to all awards granted, modified, repurchased or cancelled after January 1, 2006 and to the unvested portion of all awards granted prior to that date. We adopted this statement using the modified version of the prospective application (modified prospective application). Under this method, no prior year amounts have been restated. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by the Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees”.
 
With the adoption of SFAS No.123R, one of the differences in our method of accounting is that unvested stock options are now expensed as a component of stock-based compensation recorded in General and Administrative Costs in the Consolidated/Combined Statement of Operations. This expense is based on the fair value of the award at the original grant date and is recognized over the remaining vesting period. Prior to the adoption of SFAS No. 123R, this amount was included as a pro forma disclosure in the Notes to the Consolidated Financial Statements. Compensation expense for the three and nine months ended September 30, 2006 (Successor) was $1.0 million and $4.3 million, respectively.
 
In addition, the application of the forfeiture rate in calculating the fair value has changed with the adoption of SFAS No.123R. We are now required to estimate forfeitures on all equity-based compensation and adjust period expenses instead of recording the actual forfeitures as they occur. Furthermore, we are required to immediately expense certain awards to retirement eligible employees depending on the structure of each individual plan. The retirement eligibility provision only applies to new grants that were awarded after January 1, 2006.
 
Results of Operations
 
For the three months ended September 30, 2006, the results of operations have been compared to the amounts reported for the three months ended September 30, 2005. However, as we acquired the domestic oil and natural gas business of Calpine Corporation
 

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and affiliates in July 2005, the year-to-date results for the period ended September 30, 2006 and 2005 are not comparable and are noted as Successor for the three months ended September 30, 2005 and Predecessor for the six months ended June 30, 2005. These two year-to-date periods have not been compared because of differences in accounting principles, primarily the full cost method of accounting for oil and natural gas properties adopted by us and the successful efforts method of accounting for oil and natural gas properties followed by Calpine. In addition, Calpine adopted on January 1, 2003, SFAS No. 123, “Accounting for Stock-Based Compensation” to measure the cost of employee services received in exchange for an award of equity instruments, whereas we adopted the intrinsic value method of accounting for stock options and stock awards effective July 1, 2005, and as required, have adopted the guidance for stock-based compensation under SFAS No. 123R effective January 1, 2006. We believe comparative results for the nine months ended September 30, 2006 and 2005 would be misleading and, therefore, have chosen to present the periods separately.
 
Successor
 
Revenues. Our revenues are derived from the sale of our oil and natural gas production, which includes the effects of qualifying hedge contracts. Total revenue of $71.2 million for the third quarter consists primarily of natural gas sales comprising 86% of total revenue on total volumes of 8.7 Bcfe. For the nine months ended September 30, 2006, natural gas sales also comprised 86% of total revenue on total volumes of 24.4 Bcfe.
 

   
Successor-Consolidated
 
Successor-Consolidated
   
Predecessor-Combined
 
   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
   
Six Months Ended June 30,
 
   
2006
 
2005
 
2006
   
2005
 
   
                 (In thousands, except per unit amounts)
   
Total revenues
 
$
71,197
 
$
57,865
 
$
199,122
   
$
103,831
 
                             
Production:
                           
Gas (Bcf)
   
7.9
   
6.4
   
21.9
     
14.5
 
Oil (MBbls)
   
143.5
   
103.0
   
414.3
     
163.8
 
Total Equivalents (Bcfe)
   
8.7
   
7.1
   
24.4
     
15.5
 
                             
$ per unit:
                           
Avg. Gas Price per Mcf
 
$
7.77
 
$
8.03
 
$
7.84
   
$
6.59
 
Avg. Gas Price per Mcf excluding Hedging
   
6.61
   
8.38
   
6.94
     
-
 
Avg. Oil Price per Bbl
   
68.51
   
60.03
   
65.99
     
49.86
 
Avg. Revenue per Mcfe
 
$
8.18
 
$
8.20
 
$
8.16
   
$
6.70
 

 
Natural Gas. Natural gas sales revenue increased by $9.7 million, including the realized impact of derivative instruments, for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005. The increase is due to a gain on derivative instruments of $11.4 million offset by a decrease in natural gas sales of $1.7 million. The decrease in natural gas sales revenue is due to a 21% decrease in natural gas prices offset by an increase in gas production volumes. The largest increase in production volumes were in the Lobo, Other Onshore, and Perdido regions due to successful well completions. The average natural gas price decreased from $8.03 per Mcfe to $7.77 per Mcfe, including the effects of hedging, for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005.
 
Natural gas sales revenue was $171.8 million for the nine months ended September 30, 2006, including the effects of hedging, based on total gas production volumes of 21.9 Bcf. Approximately 80% of the production volumes were from the following three areas: California, Lobo and Perdido. Average natural gas prices were $7.84 per Mcf for the respective period. The effect of hedging on natural gas sales revenue was an increase of $19.8 million for an increase in total price from $6.94 to $7.84 per Mcf.
 
Natural gas sales revenue was $95.6 million with natural gas production volumes of 14.5 Bcf for the six months ended June 30, 2005. The production volumes were primarily from the Sacramento Basin with 6.5 Bcf or 44.8% and Lobo and Perdido with a combined production of 5.5 Bcf or 37.9%. Production volumes were lower than expected due to capital expenditure constraints resulting in reduced drilling activity. The average price for natural gas was $6.59 per Mcf. There was no hedging activity for the six months ended June 30, 2005.
 
Crude Oil. Oil sales revenue increased by $3.6 million for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005. The increase is due to a 39% increase in oil production volumes with a 14% increase in oil prices. Total oil production volumes increased from 103.0 MBbls for the three months ended 2005 to 143.5 MBbls for the three months ended September 30, 2006, primarily due to increases in the Offshore and Other Onshore regions. The average oil price increased to $68.51 for the three months ended September 30, 2006 from $60.03 for the comparable period in the prior year.
 

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Oil sales revenue was $27.3 million for the nine months ended September 30, 2006 with oil production volumes of 414.3 MBbls. The oil production volumes were primarily in the Offshore and Other Onshore regions with approximately 77% of the total production volumes. The average oil price was $65.99 per Bbl for the nine months ended September 30, 2006.
 
For the six months ended June 30, 2005, crude oil sales revenue was $8.2 million based on production volumes of 163.8 MBbls. Production volumes were primarily from the Gulf of Mexico region which produced 72.7 MBbls or 44% of the total oil production. The average price of oil was $49.86 per Bbl for the six months ended June 30, 2005.
 
Operating Expenses
 
The following table presents information about our operating expenses for the three and nine months ended September 30, 2006.
 
   
Successor-Consolidated
 
Successor-Consolidated
   
Predecessor-Combined
 
   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
   
Six Months Ended June 30,
 
   
2006
 
2005
 
2006
   
2005
 
   
             (In thousands, except per unit amounts)
   
Lease operating expense
 
$
9,449
 
$
8,849
 
$
27,330
   
$
16,629
 
Depreciation, depletion and amortization
   
27,906
   
21,720
   
77,574
     
30,679
 
General and administrative costs
 
$
8,316
 
$
6,880
 
$
24,645
   
$
9,677
 
                             
$ per unit:
                           
Avg. lease operating expense per Mcfe
 
$
1.09
 
$
1.25
 
$
1.12
   
$
1.08
 
Avg. DD&A per Mcfe
   
3.21
   
3.08
   
3.18
     
1.98
 
Avg. G&A per Mcfe
 
$
0.96
 
$
0.83
 
$
1.01
   
$
0.63
 
 
Our operating expenses for the three and nine months ended September 30, 2006 are primarily related to the following items:
 
 
·
Lease Operating Expense. Lease operating expense increased $0.6 million from the three months ended September 30, 2005 to the three months ended September 30, 2006. The overall increase is due to an increase in lease expense and ad valorem tax of $2.3 million offset by a decrease in work over expense of $1.7 million primarily due to insurance reimbursement for claims submitted as a result of Hurricane Rita. The average lease operating expense decreased to $1.09 per Mcfe for the three months ended September 30, 2006 from $1.25 per Mcfe for the comparable period in the prior year.
 
Lease operating expense of $27.3 million related directly to oil and natural gas volumes which totaled 24.4 Bcfe for the nine months ended September 30, 2006 or costs of $1.12 per Mcfe. Lease operating costs were affected by wells that came on-line in South Texas.
 
For the six months ended June 30, 2005, lease operating expense was $16.6 million related to total oil and gas volumes of 15.5 Bcfe or $1.08 per Mcfe. The costs include work over cost of $0.22 per Mcfe, ad valorem taxes of $0.22 per Mcfe and insurance of $0.06 per Mcfe.
 
 
·
Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization expense increased by $6.2 million from the three months ended September 30, 2005 as compared to the three months ended September 30, 2006 due to increased production volumes and a higher rate. The depletion rate increased from $2.97 per Mcfe to $3.13 per Mcfe.
 
Depreciation, depletion, and amortization expense was $77.6 million for the nine months ended September 30, 2006 under the full cost method of accounting for oil and natural gas properties.
 
For the six months ended June 30, 2005, depreciation, depletion, and amortization expense was $30.7 million. The predecessor used the successful efforts method of accounting for oil and natural gas properties. The depletion rate was $1.97 per Mcfe for the six months ended June 30, 2005.
 
 
·
General and Administrative Costs. General and administrative costs for the three months ended September 30, 2006
 

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        were $8.3 million compared to $6.9 million for the same period in 2005, which represents a 21% increase over the prior year. The increase was due to an increase in outside legal and consulting fees relating to the Calpine bankruptcy and increased Sarbanes Oxley costs due to the hiring of a consulting firm to assist with the Sarbanes Oxley implementation.
 
For the nine months ended September 30, 2006, general and administrative costs were $24.6 million, net of capitalization of certain general and administrative costs of $2.6 million under the full cost method of accounting for oil and natural gas properties. General and administrative costs include salary and employee benefits as well as legal, consulting, and auditing fees. In addition, stock compensation expense for the nine months ended September 30, 2006 was $4.3 million and is included in general and administrative costs.
 
General and administrative costs for the six months ended June 30, 2005 were $9.7 million, which is net of capitalized general and administrative costs of $3.6 million. General and administrative costs are comprised of items such as salaries and employee benefits, legal fees, and contract fees. For the six months ended June 30, 2005, of the $9.7 million in total general and administrative costs, $5.9 million relates to salary and employee benefits. In addition, $1.3 million are legal costs and $1.7 million are merger and acquisition costs, which relate to the sale of the oil and natural gas business to the Company.
 
Total Other expense. Other expense decreased from the third quarter in 2005 to the third quarter in 2006 by $0.1 million due to a litigation accrual that was settled in the third quarter of 2006.
 
For the nine months ended September 30, 2006, other expense was $9.7 million composed of interest expense of $13.1 million offset by interest income of $3.4 million. The interest expense is associated with the senior secured revolving line of credit and second lien term loan and interest income is related to the interest earned on the overnight investments of our cash balances.
 
For the six months ended June 30, 2005, other expense of $7.0 million was associated with the intercompany debt with Calpine Corporation.
 
Provision for Income Taxes. The effective tax rate for the three and nine months ended September 30, 2006 was 38.0%. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state taxes, tax credits and other permanent differences. The effective tax rate for six months ended June 30, 2005 was 38.1%.
 
Liquidity and Capital Resources
 
Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising natural gas prices. This derivative transaction activity will allow us the flexibility to continue to execute our capital plan if prices decline during the period our derivative transactions are in place. In addition, the majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels. In connection with entering into our credit facilities in July 2005, we entered into a series of natural gas fixed-price swaps for a significant portion of our expected production through 2009. In addition, in the third quarter of 2006, we entered into two additional fixed-price swaps for a total of 9,041 MMBtu per day for 2007 and 2008. Consistent with our hedge policy, in December  2005, we entered into two costless collar transactions, which are intended to establish a floor price and ceiling price for approximately 10,000 MMBtu per day which represents approximately 10% of our 2006 natural gas production based on a third party reserve report at December 31, 2005. In the third quarter of 2006, we also entered into two additional costless collar transactions for a total of 10,000 MMBtu per day for 2007. The effects of these derivative transactions on our financial statements are discussed above under “Results of Operations - Natural Gas”. Additionally, we may enter into other agreements including fixed-price, forward price, physical purchase and sales contracts, futures, financial swaps, option contracts and put options.
 
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. This revolving line of credit was syndicated to a group of lenders on September 27, 2005. Availability under the revolver is restricted to the borrowing base, which initially was $275.0 million and was reset to $325.0 million, upon amendment, as a result of the hedges put in place in July 2005 and the favorable effects of the exercise of the over-allotment option we granted in our private equity offering in July 2005 through which we received $70.0 million of funds (net of transaction fees). In July 2005, we repaid $60.0 million of the $225.0 million in original borrowings on the Revolver. 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. Amounts outstanding under the revolver bear interest, as amended, at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%. 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 PV-10 reserve value, a guaranty by all of
 

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our domestic subsidiaries, a pledge of 100% of the stock of domestic subsidiaries and a lien on cash securing the Calpine gas purchase and sale contract. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At September 30, 2006, our current ratio was 3.7 and our leverage ratio was 1.3. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at September 30, 2006. All amounts drawn under the revolver are due and payable on July 7, 2009. Availability under the revolving line of credit was $159.0 million at September 30, 2006.
 
In July 2006, we entered into a Deposit Account Control Agreement in order to provide a security interest under the terms of our senior secured revolving line of credit. Under the terms of the Deposit Account Control Agreement, we were required to maintain $15.0 million on account to keep a borrowing base of $325.0 million.  Based on the semi-annual review of our borrowing base, a consent agreement was signed in October 2006 in which the borrowing base remained at $325.0 million and we were no longer required to maintain the $15.0 million balance pursuant to the Deposit Account Control Agreement
 
Second Lien Term Loan.   BNP Paribas, in July 2005, also provided us with a second lien term loan concurrent with the acquisition, in the amount of $100.0 million. On September 27, 2005, we repaid $25.0 million of borrowings on the term loan, reducing the balance to $75.0 million and syndicated the loan to a group of lenders including BNP Paribas. Borrowings under the term loan initially bore interest at LIBOR plus 5.00%. As a result of the hedges put in place in July 2005 and the favorable effects of our private equity placement, as described above, the interest rate for the second lien term loan has been reduced to 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. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at September 30, 2006. The revised principal balance is due and payable on July 7, 2010.
 
Cash Flows
 
   
Successor
 
Successor
   
Predecessor
 
   
Nine months ended September 30,
 
Three months ended September 30,
   
Six months ended June 30,
 
   
2006
 
2005
   
2005
 
(In thousands)
   
Cash flows provided by operating activities
 
$
141,621
 
$
63,250
   
$
59,379
 
Cash flows used in investing activities
   
(162,161
)
 
(937,592
)
   
(30,645
)
Cash flows provided by (used in) financing activities
   
(441
)
 
981,315
     
(27,239
)
Net (decrease) increase in cash and cash equivalents
 
$
(20,981
)
$
106,973
   
$
1,495
 
                       
 
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 expense and administrative expenses.
 
Net cash provided by operating activities for the nine months ended September 30, 2006 was $141.6 million generated from total production of 24.4 Bcfe with revenue of $199.1 million and net income before income tax of $50.7 million. Natural gas averaged $7.84 per Mcf, including the effects of hedging and oil averaged $65.99 per Bbl during this period. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures.
 
Net cash provided from operations for the three months ended September 30, 2005 was $63.3 million generated from total production of 7.1 Bcfe. Natural gas prices averaged $8.03 per Mcf, including the effects of hedging, and oil averaged $60.03 per Bbl during this period.
 
Net cash provided from operations for the six months ended June 30, 2005 was $59.4 million generated from total production of 15.5 Bcfe with revenue of $103.8 million and net income of $30.2 million before tax. Natural gas prices averaged $6.59 per Mcf and oil averaged $49.86 per Bbl during the quarter.
 

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Investing Activities. The primary driver of cash used in investing activities is capital spending.
 
Cash used in investing activities for the nine months ended September 30, 2006 was $162.2 million and primarily related to the purchases of property and equipment with additional capital expenditures accrued for at quarter end as well as the restrictions placed on the cash balance of $15 million associated with the Deposit Account Control Agreement
 
Cash used in investing activities for the three months ended September 30, 2005 was $937.6 million due to the acquisition of the domestic oil and natural gas business of Calpine in the amount of $910 million in total capital expenditures.
 
Cash used in investing activities for the six months ended June 30, 2005 was $30.6 million related to drilling and completion work and lease acquisitions less sale of assets.
 
Financing Activities. The primary driver of cash used in financing activities is equity transactions, the acquisition of new debt facilities or increase in intercompany notes payable and corresponding repayments of debt.
 
Net cash used in financing activities for the nine months ended September 30, 2006 was $0.4 million and primarily related to the equity offering transaction fees, proceeds from issuances of common stock and stock-compensation excess tax benefit.
 
Net cash provided by financing activities for the three months ended September 30, 2005 was $981.3 million. This was due to $800 million in equity offering proceeds net of $54.0 million in transaction fees and $325 million in our senior credit facility for the acquisition of the domestic oil and natural gas business of Calpine and operating needs offset by repayment of $85.0 million of long-term debt and $5.1 million of deferred loan costs.
 
Net cash used in financing activities for the six months ended June 30, 2005 was comprised of repayments of notes to affiliates totaling $27.2 million.
 
Capital Expenditures
 
Our capital expenditures for the nine months ended September 30, 2006 were $151.0 million and we currently expect to expend approximately $40 million during the fourth quarter of 2006. These capital expenditures were primarily associated with increased drilling activity in California and South Texas. We believe we have adequate expected cash flows from operations and available borrowings under our revolving credit facility to cover our budgeted capital expenditures.
 
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 Risks” in our annual report filed on Form 10-K for the year ended December 31, 2005. There have been no significant changes in our market risk from what was disclosed in the Form 10-K for the year ended December 31, 2005.
 
Item 4. Controls and Procedures
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2006. Disclosure controls and procedures are those controls and procedures designed to provide reasonable assurance that the information required to be disclosed in our Exchange Act filings is (1) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission’s rules and forms, and (2) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
 
Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2006, our disclosure controls and procedures were not effective, at the reasonable assurance level, due to the identification of the material weaknesses in internal control over financial reporting described below. Notwithstanding the material weaknesses described below, we believe our unaudited consolidated financial statements included in this quarterly filing on Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles as applicable to interim reporting.
 
In preparing our Exchange Act filings, including this quarterly filing on Form 10-Q, we implemented processes and procedures to provide reasonable assurance that the identified material weaknesses in our internal control over financial reporting were mitigated
 

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