e10vq
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2006
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
     
Delaware   64-0844345
     
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
200 North Canal Street
Natchez, Mississippi 39120
(Address of principal executive offices)(Zip code)
(601) 442-1601
(Registrant’s telephone number,
including area code)
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 þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definitions of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer þ Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o No þ
As of November 3, 2006, there were 20,747,773 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.
 
 

 


Table of Contents

CALLON PETROLEUM COMPANY
TABLE OF CONTENTS
                 
            Page No.
Part I.  
Financial Information
       
       
 
       
            3  
       
 
       
            4  
       
 
       
            5  
       
 
       
            6  
       
 
       
            15  
       
 
       
            23  
       
 
       
            23  
       
 
       
Part II.          
       
 
       
            24  
 Certification Pursuant to Section 302
 Certification Pursuant to Section 906

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Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except share data)
                 
    September 30,     December 31,  
    2006     2005  
    (Unaudited)     (Note 1)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 2,946     $ 2,565  
Accounts receivable
    30,962       33,195  
Deferred tax asset
          26,770  
Restricted investments
          4,110  
Fair market value of derivatives
    14,014       889  
Other current assets
    2,685       1,998  
 
           
Total current assets
    50,607       69,527  
 
           
 
               
Oil and gas properties, full-cost accounting method:
               
Evaluated properties
    1,043,542       937,698  
Less accumulated depreciation, depletion and amortization
    (582,999 )     (539,399 )
 
           
 
    460,543       398,299  
 
               
Unevaluated properties excluded from amortization
    60,825       49,065  
 
           
Total oil and gas properties
    521,368       447,364  
 
           
 
               
Other property and equipment, net
    1,773       1,605  
Long-term gas balancing receivable
    534       403  
Restricted investments-long-term
    6,172       1,858  
Investment in Medusa Spar LLC
    12,560       11,389  
Other assets, net
    5,864       1,630  
 
           
Total assets
  $ 598,878     $ 533,776  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 44,109     $ 39,323  
Fair market value of derivatives
          1,247  
Undistributed oil and gas revenues
    1,107       721  
Asset retirement obligations-current
    5,499       21,660  
Current maturities of long-term debt
    221       263  
 
           
Total current liabilities
    50,936       63,214  
 
           
 
               
Long-term debt
    202,075       188,813  
Asset retirement obligations-long-term
    33,973       16,613  
Deferred tax liability
    27,463       31,633  
Accrued liabilities to be refinanced
    7,000       5,000  
Other long-term liabilities
    605       455  
 
           
Total liabilities
    322,052       305,728  
 
           
Stockholders’ equity:
               
Preferred Stock, $.01 par value, 2,500,000 shares authorized;
           
Common Stock, $.01 par value, 30,000,000 shares authorized; 20,742,213 and 19,357,138 shares outstanding at September 30, 2006 and December 31, 2005, respectively
    207       194  
Capital in excess of par value
    220,325       220,360  
Unearned compensation restricted stock
          (3,334 )
Other comprehensive income
    10,435       (331 )
Retained earnings
    45,859       11,159  
 
           
Total stockholders’ equity
    276,826       228,048  
 
           
Total liabilities and stockholders’ equity
  $ 598,878     $ 533,776  
 
           
The accompanying notes are an integral part of these financial statements.

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Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited)
(In thousands, except per share amounts)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
Operating revenues:
                               
Oil and gas sales
  $ 44,878     $ 31,722     $ 137,516     $ 116,402  
 
                       
 
                               
Operating expenses:
                               
Lease operating expenses
    8,070       5,649       21,340       18,382  
Depreciation, depletion and amortization
    14,973       9,313       43,600       38,392  
General and administrative
    2,908       1,598       6,558       6,093  
Accretion expense
    1,082       864       3,832       2,495  
Derivative expense
    30       5,606       150       6,518  
 
                       
Total operating expenses
    27,063       23,030       75,480       71,880  
 
                       
 
                               
Income from operations
    17,815       8,692       62,036       44,522  
 
                       
 
                               
Other (income) expenses:
                               
Interest expense
    4,027       4,050       12,303       12,884  
Other (income)
    (354 )     (352 )     (1,354 )     (650 )
 
                       
Total other (income) expenses
    3,673       3,698       10,949       12,234  
 
                       
 
                               
Income before income taxes
    14,142       4,994       51,087       32,288  
Income tax expense
    4,856       1,558       17,700       11,111  
 
                       
 
                               
Income before Medusa Spar LLC
    9,286       3,436       33,387       21,177  
Income from Medusa Spar LLC, net of tax
    344       247       1,313       1,292  
 
                       
 
                               
Net income
    9,630       3,683       34,700       22,469  
Preferred stock dividends
                      318  
 
                       
Net income available to common shares
  $ 9,630     $ 3,683     $ 34,700     $ 22,151  
 
                       
 
                               
Net income per common share:
                               
Basic
  $ 0.47     $ 0.19     $ 1.74     $ 1.23  
 
                       
Diluted
  $ 0.45     $ 0.17     $ 1.64     $ 1.09  
 
                       
 
                               
Shares used in computing net income:
                               
Basic
    20,650       19,132       19,919       17,998  
 
                       
Diluted
    21,326       21,235       21,154       20,545  
 
                       
The accompanying notes are an integral part of these financial statements.

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Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited)
(In thousands)
                 
    Nine Months Ended  
    September 30,     September 30,  
    2006     2005  
Cash flows from operating activities:
               
Net income
  $ 34,700     $ 22,469  
Adjustments to reconcile net income to cash provided by operating activities:
               
Depreciation, depletion and amortization
    44,105       38,908  
Accretion expense
    3,832       2,495  
Amortization of deferred financing costs
    1,667       1,529  
Non-cash derivative expense
    150       5,092  
Income from investment in Medusa Spar LLC
    (1,313 )     (1,292 )
Deferred income tax expense
    17,700       11,111  
Non-cash charge related to compensation plans
    718       1,561  
Excess tax benefits from share-based payment arrangements
    (1,449 )      
Changes in current assets and liabilities:
               
Accounts receivable
    4,569       4,132  
Other current assets
    (687 )     (279 )
Current liabilities
    5,404       797  
Change in gas balancing receivable
    (131 )     14  
Change in gas balancing payable
    149       (89 )
Change in other long-term liabilities
    1       4  
Change in other assets, net
    (2,692 )     (361 )
 
           
Cash provided by operating activities
    106,723       86,091  
 
           
 
               
Cash flows from investing activities:
               
Capital expenditures
    (122,002 )     (57,382 )
Distribution from Medusa Spar LLC
    849       464  
 
           
Cash used by investing activities
    (121,153 )     (56,918 )
 
           
 
               
Cash flows from financing activities:
               
Change in accrued liabilities to be refinanced
    2,000        
Increase in debt
    63,000       7,000  
Payments on debt
    (51,000 )     (12,000 )
Issuance of common stock
          2  
Buyout of preferred stock
          (637 )
Equity issued related to employee stock plans
    (438 )     (241 )
Excess tax benefits from share-based payment arrangements
    1,449        
Capital leases
    (200 )     (448 )
Cash dividends on preferred stock
          (318 )
 
           
Cash provided (used) by financing activities
    14,811       (6,642 )
 
           
Net increase in cash and cash equivalents
    381       22,531  
Cash and cash equivalents:
               
Balance, beginning of period
    2,565       3,266  
 
           
Balance, end of period
  $ 2,946     $ 25,797  
 
           
The accompanying notes are an integral part of these financial statements.

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CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2006
1.   General
 
    The financial information presented as of any date other than December 31 has been prepared from the books and records of Callon Petroleum Company (the “Company” or “Callon”) without audit. Financial information as of December 31, 2005 has been derived from the audited financial statements of the Company, but does not include all disclosures required by U.S. generally accepted accounting principles. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary for the fair presentation of the financial information for the periods indicated, have been included. For further information regarding the Company’s accounting policies, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 2005 included in the Company’s Annual Report on Form 10-K filed March 15, 2006. The results of operations for the three-month and nine-month periods ended September 30, 2006 are not necessarily indicative of future financial results.
 
2.   Stock-Based Compensation
 
    The Company has various stock plans (“Plans”) under which employees of the Company and its subsidiaries and non-employee members of the Board of Directors of the Company have been or may be granted certain equity compensation. The Company has compensatory stock option plans in place whereby participants have been or may be granted rights to purchase shares of common stock of Callon. For further discussion of the Plans, refer to Note 11 of the Consolidated Financial Statements for the year ended December 31, 2005 included in the Company’s Annual Report on Form 10-K filed March 15, 2006.
 
    On March 9, 2006, the Board of Directors of the Company approved the 2006 Stock Incentive Plan (“2006 Plan”). The 2006 Plan was approved by the shareholders at the May 4, 2006 annual meeting. Pursuant to the 2006 Plan, 500,000 shares of common stock shall be reserved for issuance upon exercise of stock options, restricted stock or other stock-based awards.
 
    In August 2006, the Board of Directors approved the award of 520,000 shares of restricted stock from the 1996 Stock Incentive Plan. Of the 520,000 shares, 20,000 shares were granted to non-employee members of the Board of Directors and vested immediately. The remaining 500,000 shares were issued to employees of the Company with 20% vesting immediately and the remaining 80% vesting ratably over the next four years.
 
    Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123 (revised 2004) (“SFAS 123R”), “Share-Based Payment,” utilizing the modified prospective approach. Prior to the adoption of SFAS 123R we accounted for stock option grants in accordance with Accounting Principals Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for stock option grants.

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    Under the modified prospective approach, SFAS 123R applies to new awards, unvested awards as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified, repurchased or cancelled. Under the modified prospective approach, compensation cost recognized in 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of Statement of Financial Accounting Standard No. 123 (“SFAS 123”) “Accounting for Stock-Based Compensation,” and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact of adopting the new standard.
 
    As a result of most of the Company’s stock-based compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes, net income and basic and diluted earnings per share for the three-month and nine-month periods ended September 30, 2006 was immaterial.
 
    SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The $1.4 million of excess tax benefits classified as a financing cash inflow for the nine-month period ended September 30, 2006 would have been classified as an operating cash flow had the Company not adopted SFAS 123R. There were no cash proceeds from the exercise of stock options for the nine months ended September 30, 2006 due to the fact that all options were exercised through net-share settlements.
 
    For the three-month period ended September 30, 2006, we recorded stock-based compensation expense of $2.3 million, of which $1.2 million was included in general and administrative expenses and $1.1 million was capitalized to oil and gas properties. For the nine-month period ended September 30, 2006, we recorded stock-based compensation expense of $2.8 million, of which $1.5 million was included in general and administrative expenses and $1.3 million was capitalized to oil and gas properties. Shares available for future stock option or restricted stock grants to employees and directors under existing plans were 535,666 at September 30, 2006.

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    The following table illustrates the effect on operating results and per share information had the Company accounted for stock-based compensation in accordance with SFAS 123 for the three-month and nine-month periods ended September 30, 2005 (in thousands, except per share amounts):
                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2005  
Net income available to common-as reported
  $ 3,683     $ 22,151  
Add: Stock-based compensation expense included in net income as reported, net of tax
    157       1,119  
Deduct: Total stock-based compensation expense under fair value based method, net of tax
    (207 )     (1,270 )
 
           
Net income available to common- pro forma
  $ 3,633     $ 22,000  
 
           
 
               
Net income per share available to common:
               
Basic-as reported
  $ 0.19     $ 1.23  
Basic-pro forma
  $ 0.19     $ 1.22  
 
               
Diluted-as reported
  $ 0.17     $ 1.09  
Diluted-pro forma
  $ 0.17     $ 1.09  
    Stock Options
    The Company uses the Black-Scholes option pricing model to estimate the fair value of stock-based awards with the following weighted-average assumptions for the indicated periods.
                 
    Nine Months Ended
    September 30,
    2006   2005
Dividend yield
           
Expected volatility
    38.9 %     39.4 %
Risk-free interest rate
    4.6 %     4.2 %
Expected life of option (in years)
    5       4  
Weighted-average grant-date fair value
  $ 7.72     $ 5.59  
Forfeiture rate
    7.5 %      
    The assumptions above are based on multiple factors, including historical exercise patterns of employees with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns and the historical volatility of our stock price. There were no stock options granted during the three months ended September 30, 2006 and 2005.

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    At September 30, 2006, there was $249,000 of unrecognized compensation cost related to nonvested stock options, which is expected to be recognized over a weighted-average period of 2.3 years.
 
    The following table represents stock option activity for the nine months ended September 30, 2006:
                         
                    Weighted-Average
    Number of   Weighted-Average   Remaining
    Shares   Exercise Price   Contract Life
     
Outstanding options at beginning of period
    1,205,558     $ 10.11          
Granted
    15,000       18.69          
Exercised
    (480,333 )     10.66          
Forfeited
                   
     
 
                       
Outstanding options at end of period
    740,225     $ 9.93     4.31 Yrs.
     
 
                       
Outstanding exercisable at end of period
    695,225     $ 9.44     4.01 Yrs.
     
    The aggregate intrinsic value of options outstanding was $2.9 million and the aggregate intrinsic value of options exercisable was $2.9 million. Total intrinsic value of options exercised was $4.1 million for the nine months ended September 30, 2006.
 
    The following table summarizes our nonvested stock option activity for the nine months ended September 30, 2006:
                 
    Number of   Weighted-Average
    Shares   Exercise Price
     
Nonvested stock options at beginning of period
    39,000     $ 16.94  
Granted
    15,000       18.69  
Vested
    (9,000 )     16.71  
Forfeited
           
     
 
               
Nonvested stock options at end of period
    45,000     $ 17.57  
     

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    Restricted Stock
 
    The Plans allow for the issuance of restricted stock awards. The unearned stock-based compensation related to these awards is being amortized to compensation expense over the vesting period. The compensation expense for these awards was determined based on the market price of our stock at the date of grant applied to the total numbers of shares that were anticipated to fully vest. As of September 30, 2006, there was $8.7 million of unrecognized compensation cost associated with these awards.
 
    The following table represents unvested restricted stock activity for the nine months ended September 30, 2006:
                 
    Number of   Weighted-Average
    Shares   Grant Price
     
Outstanding shares at beginning of period
    272,000     $ 13.66  
Granted
    520,000       15.83  
Vested
    (188,000 )     15.04  
Forfeited
    (4,200 )     13.82  
     
 
               
Outstanding shares at end of period
    599,800     $ 15.10  
     
3.   Per Share Amounts
 
    Basic net income per common share was computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share was determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of common stock equivalents computed using the treasury stock method. In addition, an adjustment was included for the nine-month period ended September 30, 2005 for the dilutive effect of the convertible preferred stock.

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    A reconciliation of the basic and diluted earnings per share computation is as follows (in thousands, except per share amounts):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
(a) Net income available to common Shares
  $ 9,630     $ 3,683     $ 34,700     $ 22,151  
Preferred dividends assuming Conversion of preferred stock (if dilutive)
                      318  
 
                       
(b) Income available to common shares assuming conversion of preferred stock (if dilutive)
  $ 9,630     $ 3,683     $ 34,700     $ 22,469  
 
                       
 
                               
(c) Weighted average shares outstanding
    20,650       19,132       19,919       17,998  
Dilutive impact of stock options
    193       410       258       333  
Dilutive impact of warrants
    443       1,523       894       1,309  
Dilutive impact of restricted stock
    40       76       83       62  
Convertible preferred stock (if dilutive)
          94             843  
 
                       
(d) Total diluted shares
    21,326       21,235       21,154       20,545  
 
                       
 
                               
Basic income per share (a¸c)
  $ 0.47     $ 0.19     $ 1.74     $ 1.23  
Diluted income per share (b¸d)
  $ 0.45     $ 0.17     $ 1.64     $ 1.09  
 
                               
Stock options and warrants excluded due to the exercise price being greater than the stock price (in thousands)
    30             27       12  
4.   Derivatives
 
    The Company periodically uses derivative financial instruments to manage oil and gas price risk. Settlements of gains and losses on commodity price contracts are generally based upon the difference between the contract price or prices specified in the derivative instrument and a NYMEX price or other cash or futures index price.
 
    The Company’s derivative contracts that are accounted for as cash flow hedges under Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), “Accounting for Derivative Instruments and Hedging Activities,” are recorded at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The cash settlements on these contracts are also recorded within derivative expense (income).

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    Cash settlements on effective cash flow hedges during the three-month period ended September 30, 2006 resulted in an increase in oil and gas sales of $3.2 million compared to a reduction of oil and gas sales of $3.6 million for the same period in 2005. The nine-month periods ended September 30, 2006 and 2005 included an increase in oil and gas sales of $5.7 million and a reduction of oil and gas sales of $8.3 million, respectively, for cash settlements on effective cash flow hedges.
 
    The Company recognized derivative expense of $30,000 and $150,000 for the three-month and nine-month periods ended September 30, 2006 and $5.6 million and $6.5 million for the three-month and nine-month periods ended September 30, 2005, respectively.
    Included in derivative expense for the three-month and nine-month periods ended September 30, 2005 were cash settlements on ineffective derivative contracts of $1.4 million and $716,000, respectively. These contracts were deemed ineffective as a result of a shortfall in production volumes due to downtime resulting from damages caused by Hurricanes Katrina and Rita in the third quarter of 2005. In addition, continued downtime resulting from damages to oil and gas transmission lines and facilities owned by third parties caused some of our derivative contracts for October and November 2005 to be deemed ineffective. Due to the fact that it was probable that the shortfall in production volumes would continue in October and November, we recognized a non-cash derivative expense of $3.8 million in the three-month period ended September 30, 2005 to reclassify the unrealized loss on these contracts, which was included in other comprehensive income (loss), to earnings.
 
    As of September 30, 2006, the fair value of the outstanding oil and gas derivative contracts was a current asset of $14.0 million and a long-term asset of $2.0 million.
 
    Listed in the table below are the outstanding derivative contracts as of September 30, 2006:
Collars
                                     
                Average   Average    
    Volumes per   Quantity   Floor   Ceiling    
Product   Month   Type   Price   Price   Period
Oil
    30,000     Bbls   $ 60.00     $ 77.10       10/06-12/06  
Oil
    30,000     Bbls   $ 60.00     $ 81.75       10/06-12/06  
Oil
    25,000     Bbls   $ 65.00     $ 83.30       01/07-12/07  
Oil
    25,000     Bbls   $ 65.00     $ 94.20       01/07-12/07  
 
                                   
Natural Gas
    600,000     MMBtu   $ 8.00     $ 9.30       10/06-12/06  
Natural Gas
    300,000     MMBtu   $ 7.00     $ 13.10       10/06-12/06  
Natural Gas
    600,000     MMBtu   $ 8.00     $ 12.70       01/07-12/07  

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5. Long-Term Debt
    Long-term debt consisted of the following at:
                 
    September 30,     December 31,  
    2006     2005  
    (In thousands)  
Senior Secured Credit Facility (matures July 31, 2010)
  $ 12,000     $  
9.75% Senior Notes (due 2010), net of discount
    189,361       187,941  
Capital lease
    935       1,135  
 
           
Total debt
    202,296       189,076  
Less current portion:
               
Capital lease
    221       263  
 
           
Long-term debt
  $ 202,075     $ 188,813  
 
           
    On August 31, 2006, the Company closed on a four-year amended and restated senior secured credit facility with Union Bank of California, N.A. The credit facility includes more favorable borrowing rates and financing flexibility. The initial borrowing base is $75 million, which will be reviewed and redetermined semi-annually and can be increased to a maximum of $175 million. Borrowings under the credit facility are secured by mortgages covering the Company’s major fields. As of September 30, 2006, there was $12 million outstanding under the facility with a weighted average interest rate of 6.96% and $63 million available for future borrowings.
6.   Comprehensive Income
 
    A summary of the Company’s comprehensive income (loss) is detailed below (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
Net income
  $ 9,630     $ 3,683     $ 34,700     $ 22,469  
Other comprehensive income (loss):
                               
Change in fair value of derivatives
    8,472       257       10,766       (2,736 )
 
                       
Total comprehensive income
  $ 18,102     $ 3,940     $ 45,466     $ 19,733  
 
                       

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7.   Asset Retirement Obligations
    The following table summarizes the activity for the Company’s asset retirement obligation for the nine-month period ended September 30, 2006:
         
    Nine Months Ended  
    September 30, 2006  
Asset retirement obligation at beginning of period
  $ 38,273  
Accretion expense
    3,832  
Liabilities incurred
    1,390  
Liabilities settled
    (16,411 )
Revisions to estimate
    12,388  
 
     
Asset retirement obligation at end of period
    39,472  
Less: current asset retirement obligation
    (5,499 )
 
     
Long-term asset retirement obligation
  $ 33,973  
 
     
    The upward revisions to estimate were primarily due to a sharp increase in industry service costs for the Gulf of Mexico region experienced in the first quarter of 2006, principally as a result of the weather patterns during the second half of 2005.
 
    Assets, primarily U.S. Government securities, of approximately $6.2 million at September 30, 2006, are recorded as restricted investments. These assets are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and gas properties.
 
8.   Accounting Pronouncements
 
    In June 2006, the Financial Accounting Standards Board (“FASB”) released interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position must meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. The effective date for FIN 48 is fiscal years beginning after December 15, 2006. The Company is currently reviewing the provisions of FIN 48 and has not yet determined the impact of adoption.
 
    In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, (“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The Company is currently reviewing the provisions of SFAS 157 and has not yet determined the impact of adoption.
 
    In September 2006, the Securities and Exchange Commission issued SAB No. 108, (“SAB 108”), Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. The guidance in SAB 108 is effective for fiscal years ending after November 15, 2006.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this report, including statements regarding our financial position, adequacy of resources, estimated reserve quantities, business strategies, plans, objectives and expectations for future operations and covenant compliance, are forward-looking statements. We can give no assurances that the assumptions upon which such forward-looking statements are based will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K for our most recent fiscal year, elsewhere in this report and from time to time in other filings made by us with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified by the Cautionary Statements.
General
Our revenues, profitability, future growth and the carrying value of our oil and gas properties are substantially dependent on prevailing prices of oil and gas, our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable and our ability to develop existing proved undeveloped reserves. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also influenced by oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulations, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternate fuel sources. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. We use derivative financial instruments for price protection purposes on a limited amount of our future production, but do not use derivative financial instruments for trading purposes.
The following discussion is intended to assist in an understanding of our historical financial position and results of operations. Our historical financial statements and notes thereto included elsewhere in this quarterly report contain detailed information that should be referred to in conjunction with the following discussion.

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Liquidity and Capital Resources
Our primary sources of capital are cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. On September 30, 2006, we had net cash and cash equivalents of $3 million and $63 million of availability under our senior secured credit facility. Cash provided from operating activities during the nine-month period ended September 30, 2006 totaled $107 million, a 24% increase when compared to 2005. The increase was primarily attributable to higher oil and gas prices. Net capital expenditures from the cash flow statement for the nine-month period ended September 30, 2006 totaled $122 million.
We are experiencing downhole mechanical problems at the A-1 well in the Medusa field. This will have a negative impact on our cash flow for the fourth quarter of 2006 and possibly into the first quarter of 2007 depending on the nature of the problem and the timing of repairs. However, production of our reserves during 2006, despite the problem at Medusa, is projected to be higher than that experienced during 2005 due to 11 new discoveries that have commenced production during 2006 or are scheduled to commence initial production during the remainder of 2006. Additionally, 2005 production was negatively impacted by tropical weather conditions. Given the current pricing environment for oil and natural gas and the higher production volumes, our cash provided by operating activities for 2006 is expected to exceed the amount realized during 2005.
Our capital expenditure plans for 2006, including capitalized interest and general and administrative expenses, will require approximately $150 million of funding. We expect that cash flows generated from operations during 2006 and current availability under our senior secured credit facility will provide the capital necessary to fund these planned capital expenditures as well as our asset retirement obligations which are expected to be approximately $14 million. See the Capital Expenditures section below for a more detailed discussion of our capital expenditures for 2006.
On August 31, 2006, we closed on a four-year amended and restated senior secured credit facility with Union Bank of California, N.A. The credit facility includes more favorable borrowing rates and financing flexibility. The initial borrowing base is $75 million which will be reviewed and redetermined semi-annually and can be increased to a maximum of $175 million. Borrowings under the credit facility are secured by mortgages covering our major fields.
The Indenture governing our 9.75% Senior Notes due 2010 and our senior secured credit facility contain various covenants, including restrictions on additional indebtedness and payment of cash dividends. In addition, our senior secured credit facility contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at September 30, 2006. See Note 5 of the Consolidated Financial Statements for the year ended December 31, 2005 included in our Annual Report on Form 10-K filed March 15, 2006 for a more detailed discussion of long-term debt.

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The following table describes our outstanding contractual obligations (in thousands) as of September 30, 2006:
                                         
Contractual           Less Than     One-Three     Four-Five     After-Five  
Obligations   Total     One Year     Years     Years     Years  
Senior Secured Credit Facility
  $ 12,000     $     $     $ 12,000     $  
9.75% Senior Notes
    200,000                   200,000        
Capital Lease (future minimum payments)
    1,374       366       485       447       76  
Throughput Commitments:
                                       
Medusa Spar LLC
    9,740       3,328       5,388       1,024        
Medusa Oil Pipeline
    452       130       146       104       72  
 
                             
 
  $ 223,566     $ 3,824     $ 6,019     $ 213,575     $ 148  
 
                             
Capital Expenditures
Capital expenditures from the cash flow statement were $122 million for the nine months ended September 30, 2006. Of this amount approximately $110 million was for exploration and development costs related to oil and gas properties and the remaining $12 million was for plugging and abandonment activities.
Included in the $110 million for exploration and development costs related to oil and gas properties was approximately $69 million of costs for the Gulf of Mexico Shelf Area, which included drilling costs associated with nine wells and completion and development of our discoveries. Five of the nine wells were successful, two were unsuccessful and two were in progress as of September 30, 2006. In the onshore Louisiana area we spent $12 million, which was associated with the drilling and completion of our Prairie Beach discovery as well as the drilling of two exploratory wells which are in progress. Interest of approximately $5 million and general and administrative costs allocable directly to exploration and development projects of approximately $7 million were capitalized for the first nine months of 2006. The remainder of the capital expended includes the acquisition of seismic and leases and costs related to our Gulf of Mexico deepwater area.
Capital expenditures for the remainder of 2006 are forecast to be approximately $40 million and include:
    the completion and development of our 2006 discoveries, including development wells;
 
    the non-discretionary drilling of exploratory wells;
 
    the acquisition of seismic and leases; and
 
    capitalized interest and general and administrative costs.
In addition, we are projecting to spend $2 million in the fourth quarter of 2006 for asset retirement obligations.

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Off-Balance Sheet Arrangements
In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which now owns a 75% undivided ownership interest in the deepwater Spar production facilities on our Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput from the Medusa area. We are obligated to process our share of production from the Medusa Field and any future discoveries in the area through the Spar production facilities. This arrangement allows us to defer the cost of the Spar production facility over the life of the Medusa Field. Our cash proceeds were used to reduce the balance outstanding under our senior secured credit facility. The LLC used $83.7 million of cash proceeds from non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the Spar. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the LLC under the equity method.

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Results of Operations
The following table sets forth certain unaudited operating information with respect to the Company’s oil and gas operations for the periods indicated:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2006     2005     2006     2005  
Net production :
                               
Oil (MBbls)
    381       382       1,340       1,613  
Gas (MMcf)
    2,710       1,510       7,241       6,570  
Total production (MMcfe)
    4,998       3,804       15,278       16,246  
Average daily production (MMcfe)
    54.3       41.3       56.0       59.5  
Average sales price:
                               
Oil (Bbls) (a)
  $ 62.31     $ 46.16     $ 58.33     $ 41.01  
Gas (Mcf)
    7.79       9.32       8.20       7.65  
Total (Mcfe)
    8.98       8.34       9.00       7.16  
 
Oil and gas revenues:
                               
Oil revenue
  $ 23,754     $ 17,649     $ 78,133     $ 66,142  
Gas revenue
    21,124       14,073       59,383       50,260  
 
                       
Total
  $ 44,878     $ 31,722     $ 137,516     $ 116,402  
 
                       
 
                               
Oil and gas production costs:
                               
Lease operating expense
  $ 8,070     $ 5,649     $ 21,340     $ 18,382  
 
                               
Additional per Mcfe data:
                               
Sales price
  $ 8.98     $ 8.34     $ 9.00     $ 7.16  
Lease operating expense
    1.61       1.49       1.40       1.13  
 
                       
Operating margin
  $ 7.37     $ 6.85     $ 7.60     $ 6.03  
 
                       
 
                               
Depletion, depreciation and amortization
  $ 3.00     $ 2.45     $ 2.85     $ 2.36  
General and administrative (net of management fees)
  $ 0.58     $ 0.42     $ 0.43     $ 0.38  
 
                               
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
 
Average NYMEX oil price
  $ 70.51     $ 63.19     $ 68.23     $ 55.40  
Basis differential and quality adjustments
    (6.91 )     (6.98 )     (7.81 )     (8.04 )
Transportation
    (1.29 )     (1.25 )     (1.28 )     (1.28 )
Hedging
          (8.80 )     (0.81 )     (5.07 )
 
                       
Average realized oil price
  $ 62.31     $ 46.16     $ 58.33     $ 41.01  
 
                       

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Comparison of Results of Operations for the Three Months Ended September 30, 2006 and the Three Months Ended September 30, 2005.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 41% to $44.9 million in the third quarter of 2006 from $31.7 million in the third quarter of 2005. The increase was primarily due to higher gas production and oil prices. Total production on an equivalent basis for the third quarter of 2006 increased by 31% versus the third quarter of 2005, which included downtime for tropical storms and hurricane activity.
Gas production during the third quarter of 2006 totaled 2.7 Bcf and generated $21.1 million in revenues compared to 1.5 Bcf and $14.1 million in revenues during the same period in 2005. The average gas price after hedging impact for the third quarter of 2006 was $7.79 per Mcf compared to $9.32 per Mcf for the same period last year. The 80% increase in production was primarily due to production from our new wells at East Cameron Block 90, North Padre Island Block 913, High Island Block 73, Brazos Block 405 and West Cameron Block 295 and third quarter 2005 production being negatively impacted by tropical weather conditions. The increase was partially offset by normal and expected declines in production from our Habanero, High Island Block 119 and Mobile Bay area fields and older properties.
Oil production during the third quarter of 2006 totaled 381,000 barrels and generated $23.8 million in revenues compared to 382,000 barrels and $17.6 million in revenues for the same period in 2005. The average oil price received after hedging impact in the third quarter of 2006 was $62.31 per barrel compared to $46.16 per barrel in the third quarter of 2005. Production was flat for the third quarter of 2006 compared to the third quarter of 2005, which was negatively impacted by tropical weather conditions.
Lease Operating Expenses
Lease operating expenses were $8.1 million for the three-month period ended September 30, 2006, an increase of $2.4 million compared to the same period in 2005. The increase was primarily due to new wells coming on line, higher costs for fuel and marine transportation and an increase in insurance rates for our policies which were renewed on April 1, 2006. In the third quarter of 2006, we incurred higher throughput charges at Medusa due to an increase in production as compared to the third quarter of 2005 where production was negatively impacted by tropical weather conditions. In addition, we incurred approximately $1.4 million for pipeline repairs at our South Marsh Island Block 261 field during the third quarter of 2006.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the three months ended September 30, 2006 and 2005 was $15.0 million and $9.3 million, respectively. The 61% increase was due to higher production volumes and a higher depletion rate resulting from higher costs associated with our exploration and development activities in the Gulf of Mexico.
Accretion Expense
Accretion expense for the three-month periods ended September 30, 2006 and 2005 of $1.1 million and $864,000, respectively, represents accretion of our asset retirement obligations. The increase was primarily due to the addition of plugging and abandonment obligations associated

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with new discoveries and an increase in plugging and abandonment cost estimates. See Note 7 to the Consolidated Financial Statements.
General and Administrative
General and administrative expenses, net of amounts capitalized, were $2.9 million and $1.6 million for the three-month periods ended September 30, 2006 and 2005, respectively. The 82% increase was primarily due to non-cash charges of approximately $1.1 million that were recognized in the third quarter of 2006 for the vesting of 20% of restricted shares issued as part of the 2006 restricted stock award. See Note 2 for more details.
Interest Expense
Interest expense was flat at $4.0 million during the three months ended September 30, 2006 compared to $4.1 million during the three months ended September 30, 2005.
Income Taxes
Income tax expense was $4.9 million and $1.6 million for the three-month periods ended September 30, 2006 and 2005, respectively. The increase was primarily due to an increase in income before income taxes.
Comparison of Results of Operations for the Nine Months Ended September 30, 2006 and the Nine Months Ended September 30, 2005.
Oil and Gas Production and Revenues
Total oil and gas revenues increased 18% to $137.5 million in the first nine months of 2006 from $116.4 million in the first nine months of 2005. The increase was primarily due to higher product prices. Total production on an equivalent basis for the nine months ended September 30, 2006 decreased by 6% versus 2005.
Gas production during the nine months ended September 30, 2006 totaled 7.2 Bcf and generated $59.4 million in revenues compared to 6.6 Bcf and $50.3 million in revenues during the same period in 2005. The average gas price after hedging impact for the nine months ended September 30, 2006 was $8.20 per Mcf compared to $7.65 per Mcf for the same period last year. The 10% increase in production was primarily due to new producing wells at East Cameron Block 90, North Padre Island Block 913, High Island Block 73, Brazos Block 405 and West Cameron Block 295, and 2005 production being negatively impacted by tropical weather conditions. The increase was partially offset by the normal and expected declines in production from our Habanero, High Island Block 119, and Mobile Bay area fields and older properties.
Oil production during the nine months ended September 30, 2006 totaled 1,340,000 barrels and generated $78.1 million in revenues compared to 1,613,000 barrels and $66.1 million in revenues for the same period in 2005. The average oil price received after hedging impact in the first nine months of 2006 was $58.33 per barrel compared to $41.01 per barrel in the first nine months 2005. The decrease in production was primarily due to normal and expected declines in production from our Habanero Field and older properties.

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Lease Operating Expenses
Lease operating expenses were $21.3 million for the nine-month period ended September 30, 2006, an increase of $3.0 million compared to the same period in 2005. The increase was primarily due to new wells coming on line, higher costs for fuel and marine transportation and an increase in insurance rates for our policies which were renewed on April 1, 2006. The increase was partially offset by the shut-in of our Main Pass Block 163 Field after the first quarter of 2005, which became uneconomic and is being plugged and abandoned, and a decrease in throughput charges for Habanero resulting from lower production.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the nine-months ended September 30, 2006 and 2005 was $43.6 million and $38.4 million, respectively. The 14% increase was a result of a higher depletion rate primarily due to higher costs associated with exploration and development in the Gulf of Mexico.
Accretion Expense
Accretion expense for the nine-month period ended September 30, 2006 and 2005 of $3.8 million and $2.5 million, respectively, represents accretion of our asset retirement obligations. The increase was primarily due to the addition of plugging and abandonment obligations associated with new discoveries and an increase in plugging and abandonment estimates. See Note 7 to the Consolidated Financial Statements.
General and Administrative
General and administrative expenses, net of amounts capitalized, were $6.6 million and $6.1 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was partially due to non-cash charges of approximately $1.1 million recognized in the third quarter of 2006 resulting from the vesting of 20% of restricted shares issued as part of the 2006 restricted stock award. These non-cash charges was offset by non-cash charges of $1.0 million we recognized in the second quarter of 2005 for the accelerated vesting of performance shares pursuant to the terms of the plan due to death or disability for an executive officer and two directors of the Company. See Note 2 for more details on the 2006 restricted stock award.
Interest Expense
Interest expense decreased by 5% to $12.3 million during the nine months ended September 30, 2006 from $12.9 million during the nine months ended September 30, 2005. This decrease is primarily attributable to an increase in capitalized interest resulting from an increase in our investment in unevaluated properties over the last year due to expanded exploration activities.
Income Taxes
Income tax expense was $17.7 million and $11.1 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was due to an increase in income before income taxes.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s revenues are derived from the sale of its crude oil and natural gas production. The prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and gas price risk.
The Company may utilize fixed price “swaps”, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices.
The Company may utilize price “collars” to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counter-party receives the difference from the Company.
Callon may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls below the floor, the counter-party pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the effects of volatile oil and gas prices and does not enter into derivative transactions for speculative purposes. However, certain of the Company’s derivative positions may not be designated as hedges for accounting purposes.
See Note 4 to the Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts at September 30, 2006. There have been no significant changes in market risks faced by the Company since the end of 2005.
Item 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. The Company’s principal executive and financial officer has concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) were effective as of September 30, 2006.
There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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CALLON PETROLEUM COMPANY
PART II. OTHER INFORMATION
Item 6. EXHIBITS
     Exhibits
  3.   Articles of Incorporation and By-Laws
  3.1   Certificate of Incorporation of the Company, as amended (incorporated by reference from Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed March 15, 2004, File No. 001-14039)
 
  3.2   Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
  4.   Instruments defining the rights of security holders, including indentures
  4.1   Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
 
  4.2   Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000, File No. 001- 14039)
 
  4.3   Form of Warrant entitling certain holders of the Company’s 10.125% Senior Subordinated Notes due 2002 to purchase common stock from the Company (incorporated by reference to Exhibit 4.13 of the Company’s Form 10-Q for the period ended June 30, 2002, File No. 001-14039)

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  4.4   Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company’s $185 million amended and restated Senior Unsecured Credit Agreement, dated December 23, 2003, to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)
 
  4.5   Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004, between Callon Petroleum Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2004, File No. 001-14039)
  31.   Certifications
  31.1   Certification of Chief Executive and Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  32.   Section 1350 Certifications
  32.1   Certification of Chief Executive and Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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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.
             
 
           
    CALLON PETROLEUM COMPANY    
 
           
Date: November 7, 2006
  By:   /s/ Fred L. Callon    
 
           
 
      Fred L. Callon, President and Chief Executive Officer (on behalf of the    
 
      registrant and as the principal financial officer)    

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Exhibit Index
     
Exhibit Number
  Title of Document
  3.   Articles of Incorporation and By-Laws
  3.1   Certificate of Incorporation of the Company, as amended (incorporated by reference from Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed March 15, 2004, File No. 001-14039)
 
  3.2   Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
  4.   Instruments defining the rights of security holders, including indentures
  4.1   Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
 
  4.2   Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000, File No. 001- 14039)
 
  4.3   Form of Warrant entitling certain holders of the Company’s 10.125% Senior Subordinated Notes due 2002 to purchase common stock from the Company (incorporated by reference to Exhibit 4.13 of the Company’s Form 10-Q for the period ended June 30, 2002, File No. 001-14039)
 
  4.4   Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company’s $185 million amended and restated Senior Unsecured Credit Agreement, dated December 23, 2003, to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)

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  4.5   Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004, between Callon Petroleum Company and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2004, File No. 001-14039)
  31.   Certifications
  31.1   Certification of Chief Executive and Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  32.   Section 1350 Certifications
  32.1   Certification of Chief Executive and Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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