form10q.htm


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


FORM 10-Q


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

For The Quarterly Period Ended June 30,2007

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 August 2, 2007 was 50,776,158.
 



 
Table of Contents
 
Part I –
Financial Information
 
 
3
 
18
 
22
 
23
Part II–
Other Information
 
 
23
 
27
 
28
 
29
 
29
 
29
 
30
31
32
Rule 13a-14(a) Certification executed by Charles F. Chambers
 
Rule 13a-14(a) Certification executed by Michael J. Rosinski
 
Section 1350 Certification
 


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

   
June 30,
   
December 31,
 
   
2007
   
2006
 
   
(Unaudited)
       
Assets
           
Current assets:
           
Cash and cash equivalents
  $
11,769
    $
62,780
 
Accounts receivable
   
37,900
     
36,408
 
Derivative instruments
   
4,035
     
20,538
 
Prepaid expenses
   
19,585
     
8,761
 
Other current assets
   
3,800
     
2,965
 
Total current assets
   
77,089
     
131,452
 
Oil and natural gas properties, full cost method, of which $41.2 million at June 30, 2007 and $37.8 million at December 31, 2006 were excluded from amortization
   
1,399,194
     
1,223,337
 
Other fixed assets
   
5,378
     
4,562
 
     
1,404,572
     
1,227,899
 
Accumulated depreciation, depletion, and amortization
    (210,712 )     (145,289 )
Total property and equipment, net
   
1,193,860
     
1,082,610
 
Deferred loan fees
   
2,785
     
3,375
 
Other assets
   
1,094
     
1,968
 
Total other assets
   
3,879
     
5,343
 
Total assets
  $
1,274,828
    $
1,219,405
 
                 
Liabilities and Stockholders' Equity
               
Current liabilities:
               
Accounts payable
  $
30,385
    $
23,040
 
Accrued liabilities
   
51,470
     
43,099
 
Royalties payable
   
12,272
     
9,010
 
Prepayment on gas sales
   
22,488
     
17,868
 
Deferred income taxes
   
1,521
     
7,743
 
Total current liabilities
   
118,136
     
100,760
 
Long-term liabilities:
               
Derivative instruments
   
17,905
     
11,014
 
Long-term debt
   
240,000
     
240,000
 
Asset retirement obligation
   
11,989
     
10,253
 
Deferred income taxes
   
48,744
     
35,089
 
Total liabilities
   
436,774
     
397,116
 
Commitments and contingencies (Note 8)
               
Stockholders' equity:
               
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 50,466,973 shares and 50,405,794 shares at June 30, 2007 and December 31, 2006, respectively
   
50
     
50
 
Additional paid-in capital
   
759,090
     
755,343
 
Treasury stock, at cost; 91,217 and 85,788 shares at June 30, 2007 and December 31, 2006, respectively
    (1,675 )     (1,562 )
Accumulated other comprehensive (loss) income
    (8,636 )    
6,315
 
Retained earnings
   
89,225
     
62,143
 
Total stockholders' equity
   
838,054
     
822,289
 
Total liabilities and stockholders' equity
  $
1,274,828
    $
1,219,405
 

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


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

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2007
   
2006
   
2007
   
2006
 
Revenues:
                       
Natural gas sales
  $
77,436
    $
53,682
    $
146,597
    $
110,417
 
Oil sales
   
9,438
     
9,699
     
16,073
     
17,508
 
Total revenues
   
86,874
     
63,381
     
162,670
     
127,925
 
Operating Costs and Expenses:
                               
Lease operating expense
   
12,566
     
8,323
     
21,362
     
17,881
 
Depreciation, depletion, and amortization
   
36,342
     
25,601
     
66,893
     
49,668
 
Treating and transportation
   
882
     
831
     
1,645
     
1,726
 
Marketing fees
   
669
     
484
     
1,332
     
1,108
 
Production taxes
   
1,200
     
1,626
     
2,185
     
3,323
 
General and administrative costs
   
9,898
     
7,078
     
17,967
     
16,329
 
Total operating costs and expenses
   
61,557
     
43,943
     
111,384
     
90,035
 
Operating income
   
25,317
     
19,438
     
51,286
     
37,890
 
                                 
Other (income) expense
                               
Interest expense, net of interest capitalized
   
4,680
     
4,371
     
9,050
     
8,503
 
Interest income
    (257 )     (1,115 )     (1,229 )     (2,252 )
Other (income) expense, net
    (182 )    
152
      (182 )    
177
 
Total other expense
   
4,241
     
3,408
     
7,639
     
6,428
 
                                 
Income before provision for income taxes
   
21,076
     
16,030
     
43,647
     
31,462
 
Provision for income taxes
   
7,985
     
6,066
     
16,565
     
11,972
 
Net income
  $
13,091
    $
9,964
    $
27,082
    $
19,490
 
                                 
Earnings per share:
                               
Basic
  $
0.26
    $
0.20
    $
0.54
    $
0.39
 
Diluted
  $
0.26
    $
0.20
    $
0.54
    $
0.39
 
                                 
Weighted average shares outstanding:
                               
Basic
   
50,354
     
50,229
     
50,340
     
50,175
 
Diluted
   
50,625
     
50,370
     
50,565
     
50,361
 
 
The accompanying notes to the financial statements are an integral part hereof.


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

   
Six Months Ended
 
   
June 30,
 
   
2007
   
2006
 
Cash flows from operating activities
           
Net income
  $
27,082
    $
19,490
 
Adjustments to reconcile net income to net cash from operating activities
               
Depreciation, depletion and amortization
   
66,893
     
49,668
 
Deferred income taxes
   
16,479
     
11,723
 
Amortization of deferred loan fees recorded as interest expense
   
590
     
590
 
Income from unconsolidated investments
    (85 )     (112 )
Stock compensation expense
   
3,176
     
3,322
 
Change in operating assets and liabilities:
               
Accounts receivable
    (1,492 )    
15,121
 
Income taxes receivable
   
-
     
6,000
 
Other current assets
    (11,659 )     (2,624 )
Other assets
    331       934  
Accounts payable
   
7,345
     
3,411
 
Accrued liabilities
    (2,247 )     (5,385 )
Royalties payable
   
7,882
      (8,707 )
Net cash provided by operating activities
   
114,295
     
93,431
 
Cash flows from investing activities
               
Acquisition of oil and gas properties
    (38,656 )     (11,580 )
Purchases of property and equipment
    (128,139 )     (87,983 )
Disposals of property and equipment
   
1,005
     
36
 
Deposits
   
25
     
25
 
Other
   
1
      (14 )
Net cash used in investing activities
    (165,764 )     (99,516 )
Cash flows from financing activities
               
Equity offering transaction fees
   
-
     
268
 
Proceeds from issuances of common stock
   
571
     
296
 
Stock-based compensation excess tax benefit
   
-
     
249
 
Purchases of treasury stock
    (113 )     (1,246 )
Net cash provided by (used in) financing activities
   
458
      (433 )
                 
Net decrease in cash
    (51,011 )     (6,518 )
Cash and cash equivalents, beginning of period
   
62,780
     
99,724
 
Cash and cash equivalents, end of period
  $
11,769
    $
93,206
 
                 
Supplemental non-cash disclosures:
               
Capital expenditures included in accrued liabilities
  $
6,020
    $
2,281
 
 
The accompanying notes to the financial statements are an integral part hereof.


Rosetta Resources Inc.
 
Notes to Consolidated Financial Statements (unaudited)
 
(1)
Organization and Operations of the Company
 
Nature of Operations.    Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) was formed in June 2005 to acquire Calpine Natural Gas L.P., the domestic oil and natural gas business formerly owned by Calpine Corporation and affiliates (“Calpine”). The Company acquired Calpine Natural Gas L.P. in July 2005 (hereinafter, the “Acquisition”) and together with all subsequently acquired oil and natural gas properties is engaged in oil and natural gas exploration, development, production and acquisition activities in 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 State Waters of 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, 2006.
 
Certain reclassifications of prior year balances have been made to conform such amounts to corresponding 2007 classifications.  These reclassifications have no impact on net income.
 
(2)
Summary of Significant Accounting Policies
 
The Company has provided a discussion of significant accounting policies, estimates and judgments in its Annual Report on Form 10-K for the year ended December 31, 2006.
 
Principles of Consolidation.  The accompanying consolidated financial statements as of June 30, 2007 and December 31, 2006 and for the three and six months ended June 30, 2007 and 2006 contain the accounts of Rosetta Resources Inc. and its majority owned subsidiaries after eliminating all significant intercompany balances and transactions.
 
Recent Accounting Developments
 
The Fair Value Option for Financial Assets and Financial Liabilities.  In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option For Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (“SFAS No. 159”), which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the potential impact of this standard.
 
Fair Value Measurements. In September 2006, the FASB issued SFAS 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. The Company does not expect the adoption of this standard 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 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing FIN 48. For additional information see Note 7 to the Consolidated Financial Statements. 
 

(3)
Property, Plant and Equipment
 
The Company’s total property, plant and equipment consists of the following:
 
   
June 30,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
Proved properties
  $
1,342,654
    $
1,170,223
 
Unproved properties
   
32,796
     
35,178
 
Gas gathering systems and compressor stations
   
23,744
     
17,936
 
Other
   
5,378
     
4,562
 
Total
   
1,404,572
     
1,227,899
 
Less: Accumulated depreciation, depletion, and amortization
    (210,712 )     (145,289 )
    $
1,193,860
    $
1,082,610
 

 
The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $1.1 million and $2.4 million of internal costs for the three and six months ended June 30, 2007, respectively, and $0.9 million and $1.7 million for the three and six months ended June 30, 2006, respectively.
 
Included in the Company’s oil and gas properties are asset retirement obligations of $15.3 million and $9.6 million as of June 30, 2007 and December 31, 2006, respectively.
 
Oil and gas properties include costs of $41.2 million and $37.8 million at June 30, 2007 and December 31, 2006, respectively, which were excluded from capitalized costs being amortized.  These amounts primarily represent unproved properties and unevaluated exploration projects in which the Company owns a direct interest.  The increase in costs excluded during 2007 is primarily related to the increase in exploration activities in the Offshore and Texas State Waters regions.
 
The Company’s ceiling test computation was calculated using hedge adjusted market prices at June 30, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and a West Texas Intermediate oil price of $69.63 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2007 increased the calculated ceiling value by approximately $21.7 million (net of tax). There was no write-down recorded at June 30, 2007. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a write-down could occur.
 
In April 2007, the Company acquired properties located in the Sacramento Basin from Output Exploration, LLC and OPEX Energy, LLC at a total purchase price of $38.7 million, subject to final adjustments.
 
(4)
Commodity Hedging Contracts and Other Derivatives
 
In the second quarter of 2007, the Company entered into additional 5,000 MMBtu per day of financial fixed price swaps with an average underlying price of $8.08 per MMBtu covering a portion of the Company’s 2008 production. The following financial fixed price swaps were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations at June 30, 2007:
 
                         
Total of
       
       
Notional
   
Total of
   
Average
   
Proved
   
Fair Market
 
       
Daily
   
Notional
   
Underlying
   
Natural Gas
   
Value
 
Settlement
Derivative
Hedge
 
Volume
   
Volume
   
Prices
   
Production
   
Gain/(Loss)
 
Period
Instrument
Strategy
 
MMBtu
   
MMBtu
   
MMBtu
   
Hedged (1)
   
(In thousands)
 
2007
Swap
Cash flow
 
55,316
     
10,178,200
   
7.80
   
45%
     
7,231
 
2008
Swap
Cash flow
 
54,909
     
20,096,616
   
7.66
   
48%
      (9,898 )
2009
Swap
Cash flow
 
26,141
     
9,541,465
   
6.99
   
26%
      (12,221 )
                 
39,816,281
     
 
            $ (14,888 )
                      
(1) Estimated based on net gas reserves presented in the December 31, 2006 Netherland, Sewell, & Associates, Inc. reserve report.
 

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 June 30, 2007:
 
                               
Total of
   
Fair
 
 
 
   
Notional
   
Total of
   
Average
   
Average
   
Proved
   
Market
 
       
Daily
   
Notional
   
Floor
   
Ceiling
   
Natural Gas
   
Value
 
Settlement
Derivative
Hedge
 
Volume
   
Volume
   
Price
   
Price
   
Production
   
Gain/(Loss)
 
Period
Instrument
Strategy
 
MMBtu
   
MMBtu
   
MMBtu
   
MMBtu
   
Hedged (1)
   
(In thousands)
 
2007
Costless Collar
Cash flow
 
10,000
     
1,840,000
    $
7.19
    $
10.03
   
8%
    $
1,026
 
                 
1,840,000
                            $
1,026
 
(1) Estimated based on net gas reserves presented in the December 31, 2006 Netherland, Sewell, & Associates, Inc. reserve report.
 
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 June 30, 2007, 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 June 30,
   
Six Months Ended June 30,
 
Natural Gas
 
2007
   
2006
   
2007
   
2006
 
Quantity settled (MMBtu)
   
5,946,800
     
5,005,000
     
11,471,300
     
9,955,000
 
Increase in natural gas sales revenue (In thousands)
  $
2,433
    $
9,127
    $
7,477
    $
10,690
 
 
 
The Company expects to reclassify losses of $2.5 million based on market pricing as of June 30, 2007 to earnings from the balance in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet during the next twelve months.
 
At June 30, 2007, the Company had derivative assets of $4.0 million on the Consolidated Balance Sheet.  The Company also had derivative liabilities of $17.9 million which was included in long-term liabilities on the Consolidated Balance Sheet at June 30, 2007.  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 June 30, 2007.
 
Gains and losses related to ineffectiveness and derivative instruments not designated as hedging instruments are included in other income (expense) and were immaterial for the three and six months ended June 30, 2007 and 2006.
 
(5)
Asset Retirement Obligation
 
Activity related to the Company’s asset retirement obligation (“ARO”) is as follows:
 
   
Six Months Ended
 
   
June 30, 2007
 
   
(In thousands)
 
ARO as of January 1, 2007
  $
10,689
 
Revision of previous estimates
   
4,697
 
Liabilities incurred during period
   
1,031
 
Accretion expense
   
605
 
ARO as of June 30, 2007
  $
17,022
 

 
Of the total ARO, approximately $5.0 million is classified as a current liability included in accrued liabilities on the Consolidated Balance Sheet at June 30, 2007.
 
(6)
Long-Term Debt
 

The Company’s credit facilities consist of a four-year senior secured revolving line of credit (“Revolver”) of up to $400.0 million with a borrowing base which was adjusted in May 2007 to $350.0 million and a five-year $75.0 million second lien term loan.
 
On June 30, 2007, the Company had outstanding borrowings and letters of credit of $240.0 million and $1.0 million, respectively.  Net borrowing availability under the Revolver was $184.0 million at June 30, 2007.  The Company was in compliance with all covenants at June 30, 2007.
 
All amounts drawn under the Revolver are due and payable on July 7, 2009.  The principal balance associated with the second lien term loan is due and payable on July 7, 2010.
 
(7)
Income Tax
 
The Company did not have any unrecognized tax benefits and there was no effect on the Company’s financial condition, results of operations or cash flows as a result of implementing FIN 48. The amount of unrecognized tax benefits did not materially change as of June 30, 2007.
 
Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statement of Operations. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter.
 
The Company’s effective tax rate differs from the federal statutory rate primarily due to state taxes, tax credits and other permanent differences.  The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to June 30, 2008.
 
(8)
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 for with respect to such matters. Management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
 
Calpine Bankruptcy
 
On December 20, 2005, Calpine and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (the “Bankruptcy Court”).
 
Calpine’s Lawsuit Against Rosetta
 
On June 29, 2007, Calpine filed an adversary proceeding against the Company in the Bankruptcy Court.  The complaint alleges that the purchase by the Company of the domestic oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for bankruptcy, was completed when Calpine was insolvent and was for less than a reasonably equivalent value.  Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for these assets which it estimates to be approximately $400 million dollars, plus interest, or (ii) in the alternative, return of the Assets from the Company.  The Company believes that these allegations are wholly baseless, intends to vigorously defend against all claims made by Calpine and is further considering additional steps it may take to fully protect the Company's interests.  The Company continues to believe that it is unlikely that this challenge by the Calpine debtors to the fairness of the Acquisition will be successful upon ultimate disposition after appeals, if any.  The deadline for the Company to answer or file its responsive pleading is September 10, 2007, and the Company has advised the Bankruptcy Court that it intends to file a motion to dismiss the complaint on or before the answer date. Calpine has requested a trial date in December 2007, but at the present time, no trial date has been set by the Bankruptcy Court.
 
Remaining Issues with Respect to the Acquisition
 
Separate from the Calpine lawsuit, Calpine has taken the position that 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”) are “executory contracts”, which Calpine may assume or reject.  Following the July 7, 2005 closing of the Acquisition and as of the date of Calpine’s bankruptcy filing, there were open issues regarding legal title to certain properties included in the Purchase Agreement.  On June 20, 2007, Calpine filed with the Bankruptcy Court its proposed Plan of Reorganization under Chapter 11 of the Bankruptcy Code, together with the accompanying Disclosure Statement, in which Calpine revealed it had not yet made a decision as to whether to assume or reject its remaining duties and obligations under the Purchase Agreement.  If the Court were to determine that the Purchase Agreement is an executory contract, the various agreements entered into as part of the transaction constitute a single contract for purposes of assumption or rejection under the Bankruptcy Code, and the Company contends that Calpine cannot choose to assume certain of the agreements and to reject others.  This issue may be contested by Calpine.  If the Purchase Agreement is held to be executory, the deadline by when Calpine must exercise its decision to assume or reject the Purchase Agreement and the further duties and obligations required therein is the date on which Calpine’s Plan of Reorganization is confirmed.
 

Open Issues Regarding Legal Title to Certain Properties
 
Under the Purchase Agreement, Calpine is required to resolve the open issues regarding legal title to certain properties.  At the closing of the Acquisition on July 7, 2005, the Company 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 by the parties before closing ("Non-Consent Properties").  Those Non-Consent Properties were therefore not included in the conveyances delivered at the closing.  Subsequent analysis determined that a significant portion of the Non-Consent Properties did not require consents or waivers.  For that portion of the Non-Consent Properties for which third-party consents were in fact required and for which either the Company or Calpine obtained the required consents or waivers, as well as for all Non-Consent Properties that did not require consents or waivers, the Company contends Calpine was and is obligated to have transferred to it 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.  The Company has retained $7.1 million of the purchase price under the Purchase Agreement for the Non-Consent Properties subject to the third-party preferential right, and, in addition, a post-closing adjustment is required to credit the Company for approximately $0.3 million for a property which was transferred to it but, if necessary, 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.
 
The Company believes all conditions precedent for its 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 the third-party preferential right) were satisfied earlier, and certainly no later, than December 15, 2005, when the Company tendered once again the amounts necessary to conclude the settlement of the Non-Consent Properties.
 
The Company believes it is the equitable owner of each of the Non-Consent Properties for which Calpine was and is obligated to have transferred the record title and that such properties are not part of Calpine’s bankruptcy estate.  Upon the Company’s 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, the Company is prepared to pay Calpine approximately $68 million, subject to appropriate adjustment, if any.  The Company’s statement of operations for the six months ended June 30, 2007, the year ended December 31, 2006 and six months ended December 31, 2005, does not include any net revenues or production from any of the Non-Consent Properties, including those properties subject to preferential rights.
 
If Calpine does not provide the Company 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 validly exercised third party’s preferential right to purchase), the Company will have a total of approximately $68 million available to them for general corporate purposes, including for the purpose of acquiring additional properties.  The Company also has 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 for general corporate purposes, including for the purpose of acquiring additional properties should that third party properly exercise the preferential rights.
 
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 is seeking 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 by 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 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 (as a result of rejection of the Purchase Agreement or otherwise) 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 unlikely upon ultimate disposition, including appeals, if any, 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.
 

Sale of Natural Gas to Calpine
 
In addition, the issues involving legal title to certain properties, the Company executed, as part of the interrelated agreements that constitute the Purchase Agreement, certain natural gas supply agreements with Calpine Energy Services, L.P. (“CES”), which also filed for bankruptcy on December 20, 2005.  During the period following Calpine’s filing for bankruptcy, CES 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 these various natural gas supply agreements.  Although Calpine has indicated in a supplement to its recently proposed plan of reorganization that it intends to assume the CES natural gas supply agreements with the Company, the Company disagrees that Calpine may assume anything less than the entire Purchase Agreement and intends to oppose any effort by Calpine to do less.
 
Calpine’s Marketing of the Company’s Production
 
Additionally, Calpine Producer Services, L.P. (“CPS”), which also filed for bankruptcy, entered into a Marketing and Services Agreement (“MSA”) with the Company as part of the interrelated agreements that constitute the Purchase Agreement.  Under the MSA, CPS provided marketing and sales of the Company’s natural gas production to third-parties and charged the Company a fee.  The MSA, however, expired by its terms on June 30, 2007.  Through a recently executed letter agreement, CPS and the Company agreed to extend the MSA until September 30, 2007, subject to and to enable the parties to negotiate and execute a New Marketing and Services Agreement (“New MSA”).  On August 3, 2007, as part of the Partial Transfer and Release Agreement, discussed in greater detail below, the Company and CPS concurrently executed the New MSA, which, if approved by the Bankruptcy Court, will be effective as of July 1, 2007 and extend CPS’ obligation to provide such services until June 30, 2009.  The New MSA is subject to earlier termination by the Company upon the occurrence of certain events.  In the interim, CPS is generally performing its obligations under the MSA.
 
Events Within Calpine’s Bankruptcy Case
 
On June 29, 2006, Calpine filed a motion in connection with its pending bankruptcy proceeding in the Bankruptcy Court seeking the entry of an order authorizing Calpine to assume certain oil and natural gas leases that Calpine had 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.  The oil and gas leases identified in Calpine’s motion are, in large part, those properties with open issues in regards to their legal title in which Calpine contends it may possess some legal interest.  According to this motion, Calpine filed it in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a bankruptcy code deadline.  Calpine’s motion did not request that the Bankruptcy 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 Bankruptcy 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 all but three of these properties, and (b) any order entered by the Bankruptcy 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 Bankruptcy 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 Bankruptcy Court that the parties could seek 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
 

 
·
Resolution of the final amounts the Company is to pay Calpine, which the Company had at that time concluded was approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations. The Company is currently updating these calculations.
 
At a hearing held on July 12, 2006, the Bankruptcy Court 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 Bankruptcy 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 as well as unliquidated damages in amounts that can not presently be determined.  In the event that Calpine elects to reject the Purchase Agreement or otherwise refuses to perform its remaining obligations therein, the Company anticipates it will be allowed to amend its proofs of claim to assert any additional damages it suffers as a result of the ultimate impact of Calpine’s refusal or failure to perform under the Purchase Agreement.  In the bankruptcy, Calpine may elect to contest or dispute the amount of damages the Company seeks in its proofs of claim.  The Company will assert all right to offset any of its damages against any funds it possesses that may be owed to Calpine.  Until the allowed amount of the Company’s claims are finally established and the Bankruptcy Court issues its rulings with respect to Calpine’s plan confirmation, the Company can not predict what amounts it may recover from the Calpine bankruptcy should Calpine reject or refuse to perform under the Purchase Agreement.
 
With respect to the stipulations between Calpine and MMS and Calpine and CSLC extending the deadline to assume or reject the MMS Oil and Gas Leases and the CSLC Leases respectively, these parties have further extended this deadline by stipulation. The deadline was first extended to January 31, 2007, was further extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007 with respect to the CSLC Leases, was further extended again to September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007 and more recently, October 31, 2007 with respect to the CSLC Leases. The Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC Leases which included appropriate language that the Company negotiated with Calpine for the Company’s protection in this regard.
 
On June 20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure Statement with the Bankruptcy Court.  Calpine has indicated in its filings with the Court that it believes substantial payments in the form of cash or newly issued stock, or some combination thereof, will be made to unsecured creditors under its proposed Plan of Reorganization that could conceivably result in payment of 100% of allowed claims and possibly provide some payment to its equity holders.  The amounts any plan ultimately distributes to its various claimants of the Calpine estate, including unsecured creditors, will depend on the Court’s conclusion with regard to Calpine’s enterprise value and the amount of allowed claims that remain following the objection process.
 
On June 29, 2007, Calpine filed a notice with the Bankruptcy Court that it was in discussions with unnamed third parties regarding alternative plans of reorganization that might yield guaranteed payments to equity holders, thus paying all unsecured creditors, and requested an extension of time to allow such discussions to continue.  Although the deadlines with respect to confirming any plan would be pushed back by approximately one month, Calpine stated in its notice that its beneficial financing terms required it emerge from bankruptcy by January 31, 2008.
 
On August 3, 2007, the Company and Calpine executed a Partial Transfer and Release Agreement (“PTRA”), subject to Bankruptcy Court approval, resolving certain open issues without prejudice to Calpine’s avoidance action and, if the Court concludes the Purchase Agreement is executory, Calpine’s ability to assume or reject the Purchase Agreement.  The principle terms are as follows:
 
 
·
The Company will extend its existing natural gas marketing agreement with Calpine until June 30, 2009.  This agreement is subject to earlier termination right by the Company upon the occurrence of certain events;
 

 
·
Calpine will deliver to the Company documents that resolve title issues pertaining to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (Properties);
 
 
·
The Company will assume all Calpine's rights and obligations for an audit by the California State Lands Commission on part of the Properties; and
 
 
·
The Company will assume all rights and obligations for the Properties, including all plugging and abandonment liabilities.
 
A number of the properties that, after the closing of the Acquisition, had open issues in regards to legal title will be resolved by the PTRA, if approved by the Bankruptcy Court.  Until a final order is received approving Calpine’s entry into the PTRA, the possibility remains that the PTRA will not become binding obligations of the parties.
 
As a result of Calpine’s bankruptcy, there remains the possibility that there will be issues between the Company and Calpine that could amount to material contingencies in relation to the litigation filed by Calpine against the Company or 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 revenues).
 
Arbitration between Calpine Corp./RROLP and Pogo Producing Company
 
On September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course of that sale, Pogo made three title defect claims on properties sold by Calpine (valued at approximately $2.7 million in the aggregate, subject to a $0.5 million deductible assuming no reconveyance) claiming that certain leases subject to the sale had expired because of lack of production. Calpine had undertaken without success to resolve this matter by obtaining ratifications of a majority of the questionable leases. Calpine filed for bankruptcy protection before Pogo filed arbitration against it. Even though this is a retained liability of Calpine, Calpine declined to accept the Company’s tender of defense and indemnity when Pogo filed for arbitration against the Company.  The Company filed a motion to stay this arbitration under the automatic stay provision of the Bankruptcy Code which motion was granted by the Bankruptcy Court on April 24, 2007 for a period of time of the earlier of fifteen months from the date of entry of the stay order or the effective date of a final order confirming Calpine’s plan of reorganization.  This is a retained liability of Calpine and it is too early for management to determine whether or in what amount, if any, this matter will have on the Company.
 
 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 June 30, 2007 and December 31, 2006 was $0.1 million. The Company does not expect that the outcome of the 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 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 June 30, 2007 or December 31, 2006 as the study is still in the preliminary stage.
 
(9)
Comprehensive Income
 

 
The Company’s total comprehensive income (loss) is shown below.
 
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
Accumulated other comprehensive (loss) income beginning of period
        $ (16,979 )         $ (19,615 )         $
6,315
          $ (50,731 )
Net income
   
13,091
             
9,964
             
27,082
             
19,490
         
                                                                 
Change in fair value of derivative hedging instruments
   
8,570
             
21,648
              (16,521 )            
73,398
         
Hedge settlements reclassed to income
    (2,433 )             (9,127 )             (7,477 )             (10,690 )        
Tax provision related to hedges
   
2,206
              (4,758 )            
9,047
              (23,829 )        
Total other comprehensive income (loss)
   
8,343
     
8,343
     
7,763
     
7,763
      (14,951 )     (14,951 )    
38,879
     
38,879
 
                                                                 
Comprehensive income
   
21,434
             
17,727
             
12,131
             
58,369
         
Accumulated other comprehensive loss
          $ (8,636 )           $ (11,852 )           $ (8,636 )           $ (11,852 )
 
(10)
Earnings Per Share
 
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period.  Diluted earnings per share reflects the potential dilution that could occur if contracts to issue common stock and related stock options were exercised at the end of the period.
 
The following is a calculation of basic and diluted weighted average shares outstanding:
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
Basic weighted average number of shares outstanding
   
50,354
     
50,229
     
50,340
     
50,175
 
Dilution effect of stock option and awards at the end of the period
   
271
     
141
     
225
     
186
 
Diluted weighted average number of shares outstanding
   
50,625
     
50,370
     
50,565
     
50,361
 
 
                               
Stock awards and shares excluded from diluted earnings per share due to anti-dilutive effect
   
268
     
206
     
407
     
154
 
 
(11)
Geographic Area Information
 
The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information”.
 
The Company owns oil and natural gas interests in eight main geographic areas all within the United States or its territorial waters. Geographic revenue and property, plant and equipment information below are based on physical location of the assets at the end of each period.
 
 
 
 
Oil and Natural Gas Revenue
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2007 (1)
   
2006 (1)
   
2007 (1)
   
2006 (1)
 
   
(In thousands)
 
California
  $
28,504
    $
15,715
    $
55,596
    $
36,110
 
Rocky Mountains
   
2,760
     
622
     
4,286
     
964
 
Mid-Continent
   
551
     
431
     
1,356
     
910
 
Gulf of Mexico
   
10,908
     
6,394
     
16,381
     
15,921
 
Lobo
   
28,391
     
13,673
     
53,267
     
29,082
 
Perdido
   
7,570
     
6,962
     
13,338
     
16,784
 
State Waters
   
838
     
2,142
     
1,647
     
5,289
 
Other Onshore
   
4,919
     
8,315
     
9,322
     
12,175
 
    $
84,441
    $
54,254
    $
155,193
    $
117,235
 
 
 
(1)
Excludes the effects of hedging of $2.4 million and $9.1 million for the three months ended June 30, 2007 and 2006, respectively, and $7.5 million and $10.7 million for the six months ended June 30, 2007 and 2006, respectively.
 
Oil and Natural Gas Properties
 
   
June 30, 2007
   
December 31, 2006
 
   
(In thousands)
 
California
  $
497,077
    $
435,167
 
Rocky Mountains
   
58,441
     
44,455
 
Mid-Continent
   
14,149
     
9,584
 
Gulf of Mexico
   
144,254
     
125,425
 
Lobo
   
467,500
     
426,348
 
Perdido
   
64,445
     
52,702
 
State Waters
   
46,204
     
26,922
 
Other Onshore
   
107,124
     
102,734
 
Other
   
5,378
     
4,562
 
    $
1,404,572
    $
1,227,899
 

 
(12)
Subsequent Event
 
In July 2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen resigned.  The Company’s Executive Vice President, Charles F. Chambers, is serving as acting President and CEO.  D. Henry Houston, chair of the Company's Audit Committee and current director, has been named Chairman of the Board and will lead the Board in the search for a permanent President and CEO.  The Company has not filled the vacancy on the Board caused by Mr. Berilgen’s resignation.
 

CAUTIONARY  NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This report includes various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may”, “will”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or variations thereon, or other comparable terminology.
 
The forward-looking statements contained in this report are largely based on our expectations for the future, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 as updated by this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances, or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:  
 
·
The supply and demand for oil, natural gas, and other products and services;
 
·
The price of oil, natural gas, and other products and services;  
 
·
Conditions in the energy markets;
 
·
Changes or advances in technology;
 
·
Reserve levels;
 
·
Currency exchange rates and inflation;
 
·
The availability and cost of relevant raw materials, goods and services;
 
·
Commodity prices;
 
·
Future processing volumes and pipeline throughput;
 
·
Conditions in the securities and/or capital markets;
 
·
The occurrence of property acquisitions or divestitures;
 
·
Drilling and exploration risks;
 
·
The availability and cost of processing and transportation;
 
·
Developments in oil-producing and natural gas-producing countries;
 
·
Competition in the oil and natural gas industry;
 
·
The ability and willingness of our current or potential counterparties or vendors to enter into transactions with us and/or to fulfill their obligations to us;
 
·
Our ability to access the capital markets on favorable terms or at all;
 
·
Our ability to obtain credit and/or capital in desired amounts and/or on favorable terms;
 
·
Present and possible future claims, litigation and enforcement actions;
 

·
Effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;
 
·
Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;
 
·
General economic conditions, either internationally, nationally or in jurisdictions affecting our business;
 
·
The amount of resources expended in connection with Calpine’s bankruptcy, including costs for lawyers, consultant experts and related expenses, as well as all lost opportunity costs associated with our internal resources dedicated to these matters;
 
·
Disputes with mineral lease and royalty owners regarding calculation and payment of royalties;
 
·
The weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; and
 
·
Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.
 

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
The following discussion addresses material changes in the results of operations for the three and six months ended June 30, 2007 compared to the three and six months ended June 30, 2006, and the material changes in financial condition since December 31, 2006.  It is presumed that readers have read or have access to our 2006 Annual Report on Form 10-K for the year ended December 31, 2006, which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
We continue to execute our strategy to increase value per share.  The following summarizes our performance for the first six months of 2007 as compared to the same period for 2006:
 
·
Production increased 31%;
 
·
The average revenue price, including the effects of hedging, decreased $0.25 per Mcfe or 3%;
 
·
Total revenue, including the effects of hedging, increased $34.7 million or 27%;
 
·
Net income increased $7.6 million or 39%;
 
·
Earnings per share increased $0.15 or 38%;
 
·
Capital expenditures increased by $71 million or 70% including acquisition of oil and gas properties; and
 
·
Drilled 94 gross wells with a success rate of 85%.
 
We have significantly grown our oil and natural gas production operations since we acquired Calpine Natural Gas L.P. in July 2005 (the “Acquisition”), and management believes it has the ability to continue growing production by drilling already identified locations on our current existing leases.
 
In April 2007, the Company acquired properties located in the Sacramento Basin from Output Exploration, LLC and OPEX Energy, LLC at a total purchase price of $38.7 million, subject to final adjustments.
 
In addition, in April 2007, we entered into additional 5,000 MMBtu per day of financial fixed price swaps with an average underlying price of $8.08 per MMBtu covering a portion of our 2008 production.
 
Critical Accounting Policies and Estimates
 
In our Annual Report on Form 10-K for the year ended December 31, 2006, we identified our most critical accounting policies upon which our financial condition depends as those relating to oil and natural gas reserves, full cost method of accounting, derivative transactions and hedging activities, income taxes and stock-based compensation.
 
We assess the impairment for oil and natural gas properties for the full cost pool quarterly using a ceiling test to determine if impairment is necessary. If the net capitalized costs of oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, it would reduce earnings and impact shareholders’ equity in the period of occurrence and result in a lower depreciation, depletion and amortization expense in the future.
 
Our ceiling test computation was calculated using hedge adjusted market prices at June 30, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and a West Texas Intermediate oil price of $69.63 per Bbl (adjusted for basis and quality differentials). Cash flow hedges of natural gas production in place at June 30, 2007 increased the calculated ceiling value by approximately $21.7 million (net of tax). There was no write-down recorded at June 30, 2007. Due to the volatility of commodity prices, should natural gas prices decline in the future, it is possible that a write-down could occur.
 
Recent Accounting Developments
 
For a discussion of recent accounting developments, see Note 2 to the Consolidated Financial Statements.
 
Results of Operations
 
Revenues. Our revenues are derived from the sale of our oil and natural gas production, which includes the effects of qualifying hedge contracts.  Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold.  Total revenue for the first six months of 2007 was $162.7 million which is an increase of $34.7 million, or 27%, from the six months ended June 30, 2006.  Approximately 90% of revenue was attributable to natural gas sales on total volumes of 20.6 Bcfe.
 

The following table presents information regarding our revenues and production volumes:
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
               
% Change
               
% Change
 
               
Increase/
               
Increase/
 
   
2007
   
2006
   
(Decrease)
   
2007
   
2006
   
(Decrease)
 
   
(In thousands, except percentages and per unit amounts)
 
Total revenues
  $
86,874
    $
63,381
      37 %   $
162,670
    $
127,925
      27 %
                                                 
Production:
                                               
Gas (Bcf)
   
10.0
     
7.1
      41 %    
19.0
     
14.0
      36 %
Oil (MBbls)
   
149.4
     
143.6
      4 %    
269.3
     
270.8
      (1 %)
Total Equivalents (Bcfe)
   
10.9
     
8.0
      36 %    
20.6
     
15.7
      31 %
                                                 
$ per unit:
                                               
Avg. Gas Price per Mcf
  $
7.74
    $
7.56
      2 %   $
7.72
    $
7.89
      (2 %)
Avg. Gas Price per Mcf excluding Hedging
   
7.50
     
6.28
      19 %    
7.32
     
7.12
      3 %
Avg. Oil Price per Bbl
   
63.17
     
67.54
      (6 %)    
59.68
     
64.65
      (8 %)
Avg. Revenue per Mcfe
   
7.97
     
7.92
      1 %    
7.90
     
8.15
      (3 %)

 
Natural Gas.  For the three months ended June 30, 2007, natural gas revenue increased by $23.7 million, including the realized impact of derivative instruments, from the comparable period in 2006, to $77.4 million.  This increase is primarily due to an increase in production in the California, the Rocky Mountains, the Offshore and the Lobo regions.  Also, the acquisition of the Sacramento Basin properties from Output Exploration, LLC and OPEX Energy, LLC (“OPEX Properties”) in April 2007 contributed to the overall increase in production.  The increase in natural gas sales were offset by a decrease in the gain related to hedging activities of $6.7 million.
 
  For the six months ended June 30, 2007, natural gas revenue increased to $146.6 million from $110.4 million for the comparable period in 2006.  This increase of $36.2 million is primarily due to an increase in the number of wells producing in 2007 as well as an increase in production volumes associated with the California, the Rocky Mountains, the Offshore and the Lobo regions.  Also, the acquisition of the OPEX Properties in April 2007 contributed to the overall increase in production. The 2007 realized average natural gas price was $7.72 as compared to $7.89 for 2006.
 
Crude Oil.  For the three months ended June 30, 2007, oil revenue was $9.4 million as compared to $9.7 million for the same period in 2006.  This decrease is attributable to a decrease in the average realized gas prices from $67.54 per Bbl to $63.17 per Bbl.  The effects of the decrease in the average realized price was offset by an increase in production volume of 4% primarily as a result of new wells producing in the Offshore region.
 
For the six months ended June 30, 2007, oil revenue decreased by $1.4 million due to the decrease in the average realized oil price of $4.97 from $64.65 per Bbl to $59.68 per Bbl.  The production volumes were 269.3 MBbls for the six months ended June 30, 2007 which is comparable to the same period in 2006.
 
Operating Expenses
 
The following table presents information regarding our operating expenses:
 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
               
% Change
               
% Change
 
               
Increase/
               
Increase/
 
   
2007
   
2006
   
(Decrease)
   
2007
   
2006
   
(Decrease)
 
   
(In thousands, except percentages and per unit amounts)
 
Lease operating expense
  $
12,566
    $
8,323
      51 %   $
21,362
    $
17,881
      19 %
Depreciation, depletion and amortization
   
36,342
     
25,601
      42 %    
66,893
     
49,668
      35 %
General and administrative costs
   
9,898
     
7,078
      40 %    
17,967
     
16,329
      10 %
                                                 
$ per unit:
                                               
Avg. lease operating expense per Mcfe
  $
1.15
    $
1.04
      11 %   $
1.04
    $
1.14
      (9 %)
Avg. DD&A per Mcfe
   
3.33
     
3.20
      4 %    
3.25
     
3.16
      3 %
Avg. G&A per Mcfe
   
0.91
     
0.88
      3 %    
0.87
     
1.04
      (16 %)

 
Our operating expenses are primarily related to the following items:
 
Lease Operating Expense.  Lease operating expense increased $4.2 million for the three months ended June 30, 2007 as compared to the three months ended June 30, 2006.  This increase is primarily due to an increase in Ad Valorem tax related to property appraisals in California.  In addition, the increase in production of 36% contributed to higher costs for equipment rentals, maintenance and repairs, and costs associated with non-operated properties.
 
Lease operating expense increased $3.5 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. This increase is primarily due to an increase in Ad Valorem tax related to property appraisals in California.  In addition, the increase in production of 31% for 2007 contributed to higher costs for equipment rentals, maintenance and repairs, and costs associated with non-operated properties.  In the first six months of 2006, we incurred $1.2 million more in workover expenses associated with the Offshore region which was not incurred in 2007.
 
Depreciation, Depletion, and Amortization.  Depreciation, depletion and amortization expense increased $10.7 million for the three months ended June 30, 2007 as compared to the three months ended June 30, 2006.  The increase is due to a 36% increase in total production and a higher depletion rate for 2007 as compared to 2006.  The depletion rate for the second quarter of 2007 was $3.25 per Mcfe while the rate for the second quarter of 2006 was $3.16 per Mcfe.
 
Depreciation, depletion and amortization expense increased $17.2 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006.  The increase is due to a  31% increase in total production and a higher depletion rate for 2007 as compared to 2006.  The depletion rate for the respective period in 2007 was $3.15 per Mcfe while the rate for the same period in 2006 was $3.11 per Mcfe.
 
General and Administrative Costs.  General and administrative costs increased by $2.8 million for the three months ended June 30, 2007 as compared to the three months ended June 30, 2006.  This increase is primarily associated with legal fees, payroll expenses and costs associated with the first year implementation of Section 404 of the Sarbanes-Oxley Act.  In addition, $0.3 million of the increase is due to an increase in stock compensation expense which was $1.8 million for the three months ended June 30, 2007 as compared to $1.5 million for the respective period in 2006.
 
General and administrative costs increased by $1.6 million for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006.  This increase is net of decreases in audit and consulting fees related to higher costs in the first six months of 2006 associated with becoming a public company, which was not incurred in 2007.  The costs in the current period are primarily associated with legal fees, payroll expenses and costs associated with the first year implementation of Section 404 of the Sarbanes-Oxley Act.  In addition, stock compensation expense of $3.2 million for the six months ended June 30, 2007 was comparable to the 2006 expense of $3.3 million.
 
Total Other Expense
 
Other expense includes interest expense, interest income and other income/expense, net which increased $0.8 million and $1.2 million for the three and six months ended June 30, 2007, respectively, as compared to the respective periods in 2006.  The increase in other expense is the result of less interest income in 2007 to offset expenses as compared to 2006.  The interest income is earned on the cash balance, which was greater at June 30, 2006 than at June 30, 2007.  Approximately $35 million was expended during the fourth quarter of 2006 to fund various asset acquisitions and approximately $38 million was expended during the second quarter of 2007 for the acquisition of the OPEX Properties.
 

Provision for Income Taxes
 
The effective tax rate for the six months ended June 30, 2007 was 37.9%, which is comparable to the tax rate for the six months ended June 30, 2006 of 38.1%.  The effective tax rate for the three months ended June 30, 2007 and 2006 was 37.8%.  The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state income taxes, tax credits and other permanent differences.
 
Liquidity and Capital Resources
 
Our primary source of liquidity and capital is our operating cash flow. We also maintain a revolving line of credit, which can be accessed as needed to supplement operating cash flow.
 
Operating Cash Flow.  Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production, thereby mitigating our exposure to price declines, but these transactions will also limit our earnings potential in periods of rising natural gas prices. This derivative transaction activity will allow us the flexibility to continue to execute our capital plan if prices decline during the period in which our derivative transactions are in place. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Natural Gas”.  In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels.
 
Senior Secured Revolving Line of Credit.   BNP Paribas, in July 2005 provided us with a senior secured revolving line of credit concurrent with the Acquisition, in the amount of up to $400.0 million (“Revolver”). This Revolver was syndicated to a group of lenders on September 27, 2005. 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. 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. In May 2007, the borrowing base was adjusted to $350.0 million.  Initial amounts outstanding under the Revolver bore interest, as amended, at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%.  These rates over LIBOR were adjusted in May to be 1.00% to 1.75%.  Such margins will fluctuate based on the utilization of the facility. Borrowings under the Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the SEC PV-10 pretax reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock of domestic subsidiaries and a lien on cash securing the Calpine gas purchase and sale contract. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At June 30, 2007, our current ratio was 2.2 to 1.0, as adjusted per current agreements, and our leverage ratio was 2.9 to 1.0. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties. We were in compliance with all covenants at June 30, 2007. All amounts drawn under the Revolver are due and payable on July 7, 2009.
 
Second Lien Term Loan.   In July 2005, BNP Paribas provided us with a second lien term loan in the amount of $100.0 million (“Term Loan”). On September 27, 2005, we repaid $25.0 million of borrowings on the Term Loan, reducing the balance to $75.0 million and syndicated the Term Loan to a group of lenders including BNP Paribas. Borrowings under the Term Loan 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 Term Loan has been reduced to LIBOR plus 4.00%. The Term Loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at June 30, 2007. The revised principal balance of the Term Loan is due and payable on July 7, 2010.
 
Availability.  Availability under the revolving line of credit was $184.0 million at June 30, 2007.
 
Cash Flows
 

The following table presents information regarding the change in our cash flow:
 
   
Six Months Ended June 30,
 
   
2007
   
2006
 
   
(In thousands)   
 
Cash flows provided by operating activities
  $
114,295
    $
93,431
 
Cash flows used in investing activities
    (165,764 )     (99,516 )
Cash flows provided by (used in) financing activities
   
458
      (433 )
Net decrease in cash and cash equivalents
  $ (51,011 )   $ (6,518 )
 
 
Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation and general and administrative expenses.  Net cash provided by operating activities (“Operating Cash Flow”) continued to be a primary source of liquidity and capital used to finance our capital expenditures for the six months ended June 30, 2007.
 
Cash flows provided by operating activities increased by $20.9 million for the six months ended June 30, 2007 as compared to the same period for 2006.  The increase in 2007 primarily resulted from higher oil and gas production in 2007.  In addition, at June 30, 2007, we had a working capital deficit of $41.0 million.  This deficit was largely caused by the decrease in our cash balance to fund capital expenditures, including property acquisitions.  For the six months ended June 30, 2007, we incurred approximately $172.8 million in capital expenditures as compared to $101.8 million for the six months ended June 30, 2006.
 
Investing Activities.  The primary driver of cash used in investing activities is capital spending.
 
Cash flows used in investing activities increased by $66.2 million for the six months ended June 30, 2007 as compared to the same period for 2006.  During the six months ended June 30, 2007, we participated in the drilling of 94 gross wells and acquired the OPEX Properties.
 
Financing Activities.  The primary driver of cash provided by or used in financing activities are equity transactions.
 
Cash flows provided by financing activities increased by $0.9 million as compared to the same period for 2006.  The net increase  is primarily related to an increase in the issuance of common stock and fewer repurchases of treasury stock.  The repurchases of stock were surrendered by certain employees to pay tax withholding upon vesting of restricted stock awards.  These repurchases are not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of common stock.
 
Capital Expenditures
 
Our capital expenditures for the six months ended June 30, 2007 increased by $71.0 million to $172.8 million, over the comparable period in 2006.  Included in the current year capital expenditures is $38.7 million for the acquisition of the OPEX Properties.  During the six months ended June 30, 2007, we participated in the drilling of 94 gross wells with the majority of these being in the Rocky Mountains and the Lobo regions.  Our positive Operating Cash Flow, along with the availability under our revolving credit facility, are projected to be sufficient to fund our budgeted capital expenditures for 2007, which are currently projected to be $250.0 million. Currently, we are evaluating increasing our capital activity for the year.
 
Calpine Matters
 
On December 20, 2005 Calpine and certain of its subsidiaries filed for protection under federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (the “Bankruptcy Court”). The filing raises certain concerns and disputes regarding aspects of our relationship with Calpine which we will continue to closely monitor as the Calpine bankruptcy proceeds. Additionally, on June 29, 2007, Calpine filed an adversary proceeding against us seeking $400 million, plus interest as a result of alleged shortfall in value received for the assets involved in the Acquisition or in the alternative, a return of the domestic oil and gas assets sold to us by Calpine. See Part II. Item 1. Legal Proceedings for further information regarding the Calpine bankruptcy.
 
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, 2006. There have been no significant changes in our market risk from what was disclosed in our Annual Report filed on Form 10-K for the year ended December 31, 2006.
 

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 June 30, 2007.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2007, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
 
There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.
 
PART II.  Other Information
Item 1.  Legal Proceedings
 
We and our subsidiaries are parties to various oil and natural gas litigation matters arising out of the ordinary course of business.  While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the financial statements.

Calpine Bankruptcy
 
On December 20, 2005, Calpine and certain of its subsidiaries filed for protection under the federal bankruptcy laws in the United States Bankruptcy Court of the Southern District of New York (the “Bankruptcy Court”).
 
Calpine’s Lawsuit Against Rosetta
 
On June 29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy Court.  The complaint alleges that our purchase of the domestic oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for bankruptcy, was completed when Calpine was insolvent and was for less than a reasonably equivalent value.  Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for these assets which it estimates to be approximately $400 million dollars, plus interest, or (ii) in the alternative, return of the Assets from us.  We believe that these allegations are wholly baseless, intend to vigorously defend against all claims made by Calpine and are further considering additional steps we may take to fully protect our interests.  We continue to believe that it is unlikely that this challenge by the Calpine debtors to the fairness of the Acquisition will be successful upon ultimate disposition after appeals, if any.  The deadline for us to answer or file our responsive pleading is September 10, 2007, and we have advised the Bankruptcy Court that we intend to file a motion to dismiss the complaint on or before the answer date. Calpine has requested a trial date in December 2007, but at the present time, no trial date has been set by the Bankruptcy Court.
 
Remaining Issues with Respect to the Acquisition
 
Separate from the Calpine lawsuit, Calpine has taken the position that the Purchase and Sale Agreement and interrelated agreements concurrently executed therewith, dated July 7, 2005, by and among Calpine, us, and various other signatories thereto (collectively, the “Purchase Agreement”) are “executory contracts”, which Calpine may assume or reject.  Following the July 7, 2005 closing of the Acquisition and as of the date of Calpine’s bankruptcy filing, there were open issues regarding legal title to certain properties included in the Purchase Agreement.  On June 20, 2007, Calpine filed with the Bankruptcy Court its proposed Plan of Reorganization under Chapter 11 of the Bankruptcy Code, together with the accompanying Disclosure Statement, in which Calpine revealed it had not yet made a decision as to whether to assume or reject its remaining duties and obligations under the Purchase Agreement. If the Court were to determine that the Purchase Agreement is an executory contract, the various agreements entered into as part of the transaction constitute a single contract for purposes of assumption or rejection under the Bankruptcy Code, and we contend that Calpine cannot choose to assume certain of the agreements and to reject others.  This issue may be contested by Calpine.  If the Purchase Agreement is held to be executory, the deadline by when Calpine must exercise its decision to assume or reject the Purchase Agreement and the further duties and obligations required therein is the date on which Calpine’s Plan of Reorganization is confirmed.
 

Open Issues Regarding Legal Title to Certain Properties
 
Under the Purchase Agreement, Calpine is required to resolve the open issues regarding legal title to certain properties.  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 by the parties before closing (“Non-Consent Properties”).  Those Non-Consent Properties were therefore not included in the conveyances delivered at the closing.  Subsequent analysis determined that a significant portion of the Non-Consent Properties did not require consents or waivers.  For that portion of the Non-Consent Properties for which third-party consents were in fact required and for which either us or Calpine obtained the required consents or waivers, as well as for all Non-Consent Properties that did not require consents or waivers, we contend 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 the third-party preferential right, and, in addition, a post-closing adjustment is required to credit us for approximately $0.3 million for a property which was transferred to us but, if necessary, 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 the third-party preferential right) 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 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, if any. Our statement of operations for the six months ended June 30, 2007, the year ended December 31, 2006 and six months ended December 31, 2005, does not include any net revenues or production from any of the Non-Consent Properties, including those properties subject to preferential rights.
 
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 validly exercised 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 for general corporate purposes, including for the purpose of acquiring additional properties should that third party properly exercise the preferential rights.
 
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 are seeking 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 the properties to us free and clear of mortgages and liens by 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 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 (as a result of rejection of the Purchase Agreement or otherwise) 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 experiences a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to us, an outcome our management considers to be unlikely upon ultimate disposition including appeals, if any, then we could experience losses which could have a material adverse effect on our financial condition, statement of operations and cash flows.
 

Sale of Natural Gas to Calpine
 
In addition, the issues involving legal title to certain properties, we executed, as part of the interrelated agreements that constitute the Purchase Agreement, certain natural gas supply agreements with Calpine Energy Services, L.P. (“CES”), which also filed for bankruptcy on December 20, 2005.  During the period following Calpine’s filing for bankruptcy, CES has continued to make the required deposits into our margin account and to timely pay for natural gas production it purchases from our subsidiaries under these various natural gas supply agreements.  Although Calpine has indicated in a supplement to its recently proposed plan of reorganization that it intends to assume the CES natural gas supply agreements with us, we disagree that Calpine may assume anything less than the entire Purchase Agreement and intend to oppose any effort by Calpine to do less.
 
Calpine’s Marketing of the Company’s Production
 
Additionally, Calpine Producer Services, L.P. (“CPS”), which also filed for bankruptcy, entered into a Marketing and Services Agreement (“MSA”) with us as part of the interrelated agreements that constitute the Purchase Agreement.  Under the MSA, CPS provided marketing and sales of our natural gas production to third-parties and charged us a fee.  The MSA, however, expired by its terms on June 30, 2007.  Through a recently executed letter agreement, we and CPS agreed to extend the MSA until September 30, 2007, subject to and to enable the parties to negotiate and execute a New Marketing and Services Agreement (“New MSA”).  On August 3, 2007, as part of the Partial Transfer and Release Agreement, discussed in greater detail below, we and CPS concurrently executed the New MSA, which, if approved by the Bankruptcy Court, will be effective as of July 1, 2007 and extend CPS’ obligation to provide such services until June 30, 2009.  The New MSA is subject to earlier termination by us upon the occurrence of certain events. In the interim, CPS is generally performing its obligations under the MSA.
 
Events Within Calpine’s Bankruptcy Case
 
On June 29, 2006, Calpine filed a motion in connection with its pending bankruptcy proceeding in the Bankruptcy Court seeking the entry of an order authorizing Calpine to assume certain oil and natural gas leases that Calpine had 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.  The oil and gas leases identified in Calpine’s motion are, in large part, those properties with open issues in regards to their legal title in which Calpine contends it may possess some legal interest.  According to this motion, Calpine filed it in order to avoid the automatic forfeiture of any interest it may have in these leases by operation of a bankruptcy code deadline.  Calpine’s motion did not request that the Bankruptcy 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. In the objection, we also requested that (a) the Bankruptcy 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 all but three of these properties, and (b) any order entered by the Bankruptcy 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 Bankruptcy 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 Bankruptcy Court that the parties could seek 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 had at that time concluded was approximately $79 million, consisting of roughly $68 million for the Non-Consent Properties and approximately $11 million in other true-up payment obligations. We are currently updating these calculations.
 
At a hearing held on July 12, 2006, the Bankruptcy Court 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 Bankruptcy 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 as well as unliquidated damages in amounts that can not presently be determined.  In the event that Calpine elects to reject the Purchase Agreement or otherwise refuses to perform its remaining obligations therein, we anticipate we will be allowed to amend our proofs of claim to assert any additional damages we suffer as a result of the ultimate impact of Calpine’s refusal or failure to perform under the Purchase Agreement.  In the bankruptcy, Calpine may elect to contest or dispute the amount of damages we seek in our proofs of claim.  We will assert all right to offset any of our damages against any funds we possess that may be owed to Calpine.  Until the allowed amount of our claims are finally established and the Bankruptcy Court issues its rulings with respect to Calpine’s plan confirmation, we can not predict what amounts we may recover from the Calpine bankruptcy should Calpine reject or refuse to perform under the Purchase Agreement.
 
With respect to the stipulations between Calpine and MMS and Calpine and CSLC extending the deadline to assume or reject the MMS Oil and Gas Leases and the CSLC Leases respectively, these parties have further extended this deadline by stipulation. The deadline was first extended to January 31, 2007, was further extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007 with respect to the CSLC Leases, was further extended again to September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007 and more recently, October 31, 2007 with respect to the CSLC Leases. The Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC Leases which included appropriate language that we negotiated with Calpine for our protection in this regard.
 
On June 20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure Statement with the Bankruptcy Court.  Calpine has indicated in its filings with the Court that it believes substantial payments in the form of cash or newly issued stock, or some combination thereof, will be made to unsecured creditors under its proposed Plan of Reorganization that could conceivably result in payment of 100% of allowed claims and possibly provide some payment to its equity holders.  The amounts any plan ultimately distributes to its various claimants of the Calpine estate, including unsecured creditors, will depend on the Court’s conclusion with regard to Calpine’s enterprise value and the amount of allowed claims that remain following the objection process.
 
On June 29, 2007, Calpine filed a notice with the Bankruptcy Court that it was in discussions with unnamed third parties regarding alternative plans of reorganization that might yield guaranteed payments to equity holders, thus paying all unsecured creditors, and requested an extension of time to allow such discussions to continue.  Although the deadlines with respect to confirming any plan would be pushed back by approximately one month, Calpine stated in its notice that its beneficial financing terms required it emerge from bankruptcy by January 31, 2008.
 
On August 3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”) with Calpine, subject to Bankruptcy Court approval, resolving certain open issues without prejudice to Calpine’s avoidance action and, if the Court concludes the Purchase Agreement is executory, Calpine’s ability to assume or reject the Purchase Agreement.  The principle terms are as follows:
 
 
·
We will extend our existing natural gas marketing agreement with Calpine until June 30, 2009.  This agreement is subject to earlier termination right by us upon the occurrence of certain events;
 
 
·
Calpine will deliver to us documents that resolve title issues pertaining to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (Properties);
 
 
·
We will assume all Calpine's rights and obligations for an audit by the California State Lands Commission on part of the Properties; and
 
 
·
We will assume all rights and obligations for the Properties, including all plugging and abandonment liabilities.
 

A number of the properties that, after the closing of the Acquisition, had open issues in regards to legal title will be resolved by the PTRA, if approved by the Bankruptcy Court.  Until a final order is received approving Calpine’s entry into the PTRA, the possibility remains that the PTRA will not become binding obligations of the parties.
 
As a result of Calpine’s bankruptcy, there remains the possibility that there will be issues between us and Calpine that could amount to material contingencies in relation to the litigation filed by Calpine against us or 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 revenues).
 
Item 1A.  Risk Factors
 
Other than with respect to the risk factors below, there have been no material changes in our risk factors from those disclosed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2006.  The following risk factor was disclosed on form 10-K and has been updated as of June 30, 2007.
 
Calpine’s bankruptcy filing may adversely affect us in several respects.
 
Calpine, its creditors or interest holders may challenge the fairness of some or all of the Acquisition.
 
On June 29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy Court.  The complaint alleges that the purchase by us of the domestic oil and natural gas assets formally owned by Calpine (the “Assets”) in July 2005 for $1.05 billion, prior to Calpine's declaring bankruptcy, was completed when Calpine was insolvent and was for less than reasonably equivalent value.  Calpine is seeking (i) monetary damages for the alleged shortfall in value it received for the Assets which it estimates to be approximately $400 million dollars, plus interest, or (ii) in the alternative, return of the Assets from us.  We deny and intend to vigorously defend against all claims made by Calpine, and we are considering additional steps we may take to fully protect our interests.  Our deadline to file our responsive pleading or answer is September 10, 2007, and the trial has not yet been scheduled. If after a trial on the merits, the Bankruptcy Court was to determine that the Debtors have met their burden of proof, it could void the transfer or take other actions against us, including (i) setting aside the Acquisition and returning our purchase price and give us a first lien on all the properties and assets we purchased in the Acquisition or (ii) sustaining the Acquisition subject to our being required to pay the Debtors the amount, if any, by which the fair value of the business transferred, as determined by the Bankruptcy Court as of July 7, 2005, exceeded the purchase price determined and paid in July 2005. If the Bankruptcy Court should set aside the Acquisition, it would have a material adverse effect upon our results of operation and financial condition in that substantially all our properties conveyed at the time of the Acquisition would be returned to Calpine, subject to our right (as a good faith transferee) to retain a lien in our favor to secure the return of the purchase price we paid for the properties. Additionally, if the Bankruptcy Court should so rule, any requirement to pay an increased purchase price could have a material adverse effect upon our results of operation and financial condition depending on the amount we might be required to pay. See Item 1. Legal Proceedings for further information regarding the Calpine bankruptcy.
 
The bankruptcy proceeding may prevent, frustrate or delay our ability to receive record legal title to certain properties originally determined to be Non-Consent Properties which we are entitled to receive under the Purchase Agreement.
 
On June 20, 2007, Calpine filed with the Bankruptcy Court its proposed plan of reorganization and disclosure statement.  In the disclosure statement, Calpine revealed that it had not yet made a decision on whether to assume or reject its remaining obligations and duties under the Purchase and Sale Agreement and interrelated agreements, which set forth the terms and agreements related to Calpine’s sale of its oil and gas assets to us.  In its proposed supplement to the plan filed on the same date, however, Calpine indicated its desire to assume the NAESB agreement under which we sell gas to Calpine and the CPS Marketing Agreement under which CPS sells our production to third parties on our behalf.  We contend that all of the transaction documents constitute one agreement and must therefore be assumed or rejected in their entirety as one agreement and will vigorously oppose any effort by Calpine to treat any aspect of the transaction as a stand-alone document.
 
Although Calpine has not made its election to assume or reject the Purchase Agreement, on August 3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”) with Calpine, subject to Bankruptcy Court approval, without prejudice to the other pending claims, disputes, and defenses between Calpine and us.  As part of the PTRA, we agreed to extend the CPS marketing agreement by two years, until June 30, 2009; however, the marketing agreement is subject to earlier termination by us upon the occurrence of certain events.  In return, Calpine has provided documents to resolve legal title issues as to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (“Properties”).  Under the PTRA, we have also agreed to assume all liabilities with respect to those Properties, such as plugging and abandonment, as well as all liabilities and rights associated with any under- or over-payment to the State of California as it relates to certain state land. We anticipate that the Bankruptcy Court will address Calpine’s to-be-filed request for approval of the PTRA in a hearing scheduled for September 11, 2007. If the Bankruptcy Court does not approve the PTRA, our New Marketing and Services Agreement will not take effect, and we will discontinue using Calpine Producer Services, L.P. to market and sell our gas.  Further, we will argue that the liabilities we were to assume under the PTRA will remain obligations of Calpine.  We will continue our efforts to resolve open issues in regard to legal title of the properties; however, if Calpine were also to refuse to perform under the Purchase Agreement and the Bankruptcy Court were to rule against certain legal arguments we would raise such that the resolution of open issues involving legal title on any remaining properties (including any leases) does not occur, the portion of the purchase price we held back pending consent or waiver will be retained and will be available to us for general corporate purposes.
 

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.
 
Certain of the properties we purchased from Calpine and paid Calpine for on July 7, 2005, require certain additional documentation, depending on the particular facts and circumstances surrounding the particular properties involved, such documentation was to be delivered by Calpine to quiet title related to our ownership of these properties following closing. Certain of these properties are subject to ministerial governmental action approving us as qualified assignee and operator, even though in most cases there had been a conveyance by Calpine and release of mortgages and liens by Calpine’s creditors.  For certain other properties, the documentation delivered by Calpine at closing was incomplete. While Calpine has not made a decision on whether to perform its remaining obligations under the Purchase Agreement with us and thus perform these required further assurances as to title, Calpine has agreed to resolve title issues on a significant number of those properties requiring the additional documentation to address title issues.  As noted, we reached agreement with Calpine upon and executed the PTRA on August 3, 2007, subject to Bankruptcy Court approval, without prejudice to the other pending claims, disputes and defenses between them.  Among other obligations and rights of the parties under PTRA, Calpine has provided documents to resolve legal title issues as to certain previously purchased oil and gas properties located in the Gulf of Mexico, California and Wyoming (“Properties”).  We anticipate that the Bankruptcy Court will address Calpine’s to-be-filed request for approval of the PTRA in a hearing scheduled for September 11, 2007.  The PTRA does not address the Non-Consent Properties which Calpine withheld from the July 2005 closing due to lack of lessor consents determined at that time (in many instances mistakenly) as needed for transfer and for which we withheld approximately $75 million of the purchase price.
 
We have expended and may continue to expend significant resources in connection with Calpine’s bankruptcy.
 
We have expended and may continue to expend significant resources in connection with Calpine’s bankruptcy.  These resources include our increased costs for lawyers, consultant experts and related expenses, as well as lost opportunity costs associated with our dedicating internal resources to these matters.  If we continue to expend significant resources and our management is distracted from the operational matters by the Calpine bankruptcy, our business, results of operations, financial position or cash flows could be adversely affected.
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended June 30, 2007

                         
                         
               
Total Number of
   
Maximum Number (or
 
               
Shares Purchased
   
Approximate Dollar Value)
 
               
as Part of Publicly
   
of Shares that May yet Be
 
   
Total Number of
   
Average Price
   
Announced Plans
   
Purchased Under the Plans
 
Period
 
Shares Purchased (1)
   
Paid per Share
   
or Programs
   
or Programs
 
April 1 - April 30
   
82
    $
22.07
     
-
     
-
 
May 1 - May 31
   
1,413
     
23.01
     
-
     
-
 
June 1 - June 30
   
835
     
24.35
     
-
     
-
 
 
(1)
All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.  These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

 
Issuance of Unregistered Securities
 
None.
 
Item 3.
  Defaults Upon Senior Securities
 
None.
 
Item 4.
Submission of Matters to a Vote of Security Holders
 
On May 15, 2007, we held our Annual Meeting of Shareholders.  At the meeting, shareholders voted on election of all of our directors to serve until the next annual meeting of shareholders.  The following is a summary of the votes on this item:
 
 
Votes For
Votes Withheld
B.A. "Bill" Berilgen (1)
              46,354,693
                  771,204
Richard W. Beckler
              44,417,081
               2,708,316
Donald D. Patteson, Jr.
              46,269,282
                  856,615
D. Henry Houston (1)
              44,415,131
               2,708,516
G. Louis Graziadio, III
              37,861,923
               9,263,474
Josiah O. Low, III
              46,416,241
                  709,156

 
(1) In July 2007, Chairman, President and Chief Executive Officer (“CEO”) B.A. Berilgen resigned.  The Company’s Executive Vice President, Charles F. Chambers, is serving as acting President and CEO.  D. Henry Houston, chair of our Audit Committee and current director, has been named Chairman of the Board and will lead the Board in the search for a permanent President and CEO.  We have not filled the vacancy on the Board caused by Mr. Berilgen’s resignation.
 
Item 5.
  Other Information
 
Rosetta reported on Form 8-K during the quarter covered by this report all information required to be reported on such form.
 

Item 6.
Exhibits
 
31.1
Certification of Periodic Financial Reports by Charles F. Chambers in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
31.2
Certification of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
32.1
Certification of Periodic Financial Reports by Charles F. Chambers and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350
 

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

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

 
Date: August 13, 2007
 

ROSETTA RESOURCES INC.
 
EXHIBIT INDEX
 
Exhibit Number
 
Description
 
Certification of Periodic Financial Reports by Charles F. Chambers in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
Certification of Periodic Financial Reports by Michael J. Rosinski in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
 
Certification of Periodic Financial Reports by Charles F. Chambers and Michael J. Rosinski in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350
 
 
32