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, 2010
 
or
¨
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from__________ to__________

Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
 
 
 
Callon Logo
 
 

Delaware
(State or other jurisdiction
of incorporation or organization)
64-0844345
(I.R.S. Employer
Identification No.)
   
200 North Canal Street
Natchez, Mississippi
(Address of principal executive offices)
 
 39120
(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 x
 
No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ¨
 
No ¨


Indicate by check mark whether the registrant is a larger accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definition of “accelerated filer”, “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨
Accelerated filer ¨
   
Non-accelerated filer x
Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨
 
No x

As of August 1, 2010 there were outstanding 28,771,832 shares of the Registrant’s common stock, par value $0.01 per share.

 
 
 


 


 
Table of Contents
Part I. Financial Information
 
   
Item 1. Financial Statements
 
   
   
   
   
   
   
   
   
Part II.  Other Information
 
   
   
   
   
   
   
   
   












 
2


Part 1.  Financial Information

Item 1.  Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except share data)
   
June 30, 2010
   
December 31, 2009
 
ASSETS
 
(Unaudited)
       
Current assets:
           
   Cash and cash equivalents
  $ 31,812     $ 3,635  
   Accounts receivable
    16,632       20,798  
   Accounts receivable - MMS royalty recoupment
    -       51,534  
   Fair market value of derivatives
    1,106       145  
   Other current assets
    914       1,572  
      Total current assets
    50,464       77,684  
                 
Oil and gas properties, full-cost accounting method:
               
   Evaluated properties
    1,248,051       1,593,884  
   Less accumulated depreciation, depletion and amortization
    (1,137,978 )     (1,488,718 )
      Net oil and gas properties
    110,073       105,166  
   Unevaluated properties excluded from amortization
    30,482       25,442  
      Total oil and gas properties
    140,555       130,608  
                 
Other property and equipment, net
    2,724       2,508  
Restricted investments
    4,365       4,065  
Investment in Medusa Spar LLC
    10,928       11,537  
Other assets, net
    2,215       1,589  
      Total assets
  $ 211,251     $ 227,991  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
               
Current liabilities:
               
  Accounts payable and accrued liabilities
  $ 12,111     $ 12,887  
  Asset retirement obligations
    3,377       4,002  
   9.75% Senior Notes, net of $0 and $232 discount, respectively
    -       15,820  
        Subtotal
    15,488       32,709  
  Callon Entrada non-recourse credit facility (See Note 1)
    -       84,847  
      Total current liabilities
    15,488       117,556  
                 
13% Senior Notes (See Note 6)
               
   Principal outstanding
    137,961       137,961  
   Deferred credit, net of accumulated amortization of $2,090 and $294, respectively
    29,417       31,213  
       Total 13% Senior Notes
    167,378       169,174  
                 
Senior secured revolving credit facility
    -       10,000  
Asset retirement obligations
    11,542       10,648  
Other long-term liabilities
    2,424       1,467  
      Total liabilities
    196,832       308,845  
                 
Stockholders' equity (deficit):
               
  Preferred Stock, $.01 par value, 2,500,000 shares authorized;
    -       -  
  Common Stock, $.01 par value, 60,000,000 shares authorized; 28,792,290 and 28,742,926
    shares outstanding at June 30, 2010 and December 31, 2009, respectively
    288       287  
  Capital in excess of par value
    246,571       243,898  
  Other comprehensive loss
    (6,027 )     (7,478 )
  Retained deficit
    (226,413 )     (317,561 )
       Total stockholders' equity (deficit)
    14,419       (80,854 )
       Total liabilities and stockholders' equity (deficit)
  $ 211,251     $ 227,991  

The accompanying notes are an integral part of these consolidated financial statements.

 
3


Callon Petroleum Company
Consolidated Statements of Operations (Unaudited)
(in thousands, except per share data)


   
Three-Months Ended
June 30,
   
Six-Months Ended
June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Operating revenues:
 
 
         
 
       
  Oil sales
  $ 15,901     $ 18,971     $ 32,564     $ 34,923  
  Gas sales
    5,668       6,054       12,390       14,917  
      Total operating revenues
    21,569       25,025       44,954       49,840  
                                 
Operating expenses:
                               
  Lease operating expenses
    4,031       4,656       8,679       8,695  
  Depreciation, depletion and amortization
    7,042       8,452       13,855       17,865  
  General and administrative
    4,411       5,391       8,715       7,210  
  Accretion expense
    622       795       1,202       1,833  
     Total operating expenses
    16,106       19,294       32,451       35,603  
  Income from operations
    5,463       5,731       12,503       14,237  
                                 
  Other (income) expenses:
                               
  Interest expense
    3,198       4,854       6,792       9,636  
  Callon Entrada non-recourse credit facility interest expense (See Note 2)
    -       1,935       -       3,491  
  Loss on early extinguishment of debt (See Note 6)
    339       -       339       -  
  Other (income) expense
    (111 )     61       (472 )     (34 )
     Total other (income) expenses
    3,426       6,850       6,659       13,093  
                                 
  Income (loss) before income taxes
    2,037       (1,119 )     5,844       1,144  
  Income tax expense
    -       24       -       -  
  Income (loss) before equity in earnings of Medusa Spar LLC
    2,037       (1,143 )     5,844       1,144  
  Equity in earnings of Medusa Spar LLC
    93       218       209       335  
  Net income (loss) available to common shares
  $ 2,130     $ (925 )   $ 6,053     $ 1,479  
                                 
  Net income (loss) per common share:
                               
    Basic
  $ 0.07     $ (0.04 )   $ 0.21     $ 0.07  
    Diluted
  $ 0.07     $ (0.04 )   $ 0.21     $ 0.07  
                                 
  Shares used in computing net income (loss) per common share:
                               
    Basic
    28,762       21,645       28,750       21,626  
    Diluted
    29,583       21,645       29,406       21,626  

The accompanying notes are an integral part of these consolidated financial statements.

 
4


Callon Petroleum Company
Consolidated Statements of Cash Flows (Unaudited)
(in thousands)

   
Six-Months Ended June 30,
 
   
2010
   
2009
 
Cash flows from operating activities:
           
Net income
  $ 6,053     $ 1,479  
Adjustments to reconcile net income to
               
cash provided by operating activities:
               
      Depreciation, depletion and amortization
    14,245       18,285  
      Accretion expense
    1,202       1,833  
      Amortization of non-cash debt related items
    221       3,168  
      Amortization of deferred credit
    (1,796 )     -  
      Equity in earnings of Medusa Spar LLC
    (209 )     (335 )
      Non-cash charge for early debt extinguishment
    179       -  
      Non-cash charge related to compensation plans
    2,049       1,184  
      Payments to settle asset retirement obligations
    (180 )     (2,601 )
      Changes in current assets and liabilities:
               
         Accounts receivable
    53,362       6,441  
         Other current assets
    658       (868 )
         Current liabilities
    (921 )     (28,993 )
      Change in gas balancing receivable
    285       155  
      Change in gas balancing payable
    (249 )     (123 )
      Change in other long-term liabilities
    (115 )     16  
      Change in other assets, net
    (780 )     (189 )
         Cash provided by (used in) operating activities
    74,004       (548 )
                 
Cash flows from investing activities:
               
   Capital expenditures
    (19,987 )     (21,829 )
   Investment in restricted assets related to plugging and abandonment obligations
    (300 )     -  
   Distribution from Medusa Spar LLC
    818       986  
         Cash used in investing activities
    (19,469 )     (20,843 )
                 
Cash flows from financing activities:
               
   Borrowings from senior secured credit facility
    -       9,337  
   Payments on senior secured credit facility
    (10,000 )     (4,337 )
   Redemption of remaining 9.75% senior notes (See Note 6)
    (16,052 )     -  
   Proceeds from exercise of employee stock options
    5       -  
         Cash (used in) provided by financing activities
    (26,047 )     5,000  
                 
Net change in cash and cash equivalents
    28,488       (16,391 )
Cash and cash equivalents:
               
    Balance, beginning of period
    3,635       17,126  
    Less: Cash held by subsidiary deconsolidated at January 1, 2010
    (311 )     -  
    Balance, end of period
  $ 31,812     $ 735  

The accompanying notes are an integral part of these consolidated financial statements.

 
5

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)



INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Description of Business and Basis of Presentation
6.    Borrowings
2.    Deconsolidation of Callon Entrada
7.    Derivative Instruments and Hedging Activities
3.    Minerals Management Service Royalty Recoupment
8.    Fair Value Measurements
4.    Earnings per Share
9.    Income Taxes
5. Comprehensive Income (Loss)
10.  Asset Retirement Obligations

Note 1 - Description of Business and Basis of Presentation

Description of Business

Callon Petroleum Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management.  As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

Callon is engaged in the acquisition, development, exploration and operation of oil and gas properties.  The Company’s properties and operations are geographically concentrated onshore in Louisiana and Texas and the offshore waters of the Gulf of Mexico.

Basis of Presentation

These interim financial statements of the Company have been prepared in accordance with (1) accounting principles generally accepted in the United States (“US GAAP”), (2) the Security and Exchange Commission’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments (including normal recurring adjustments) necessary to present fairly the Company's financial position, the results of its operations and its cash flows for the periods indicated.  Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2010.

All amounts contained in the notes to the consolidated financial statements are presented in thousands, with the exception of years, per-share and per-hedge amounts.


 
6

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


Note 2 - Deconsolidation of Callon Entrada

In April 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO Energy (US) Limited (“CIECO”) effective January 1, 2008.  At closing, CIECO paid Callon $155,000, and reimbursed the Company $12,600 for 50% of Entrada capital expenditures incurred prior to the closing date.  In addition, as part of the purchase and sale agreement, CIECO agreed to loan Callon Entrada, a wholly owned subsidiary of the Company, up to $150,000 plus interest expense incurred up to $12,000, for its share of the development costs for the Entrada project.  Based on the terms of the credit agreement with CIECO Energy (Entrada) LLC (“CIECO Entrada”), the debt was to be repaid solely from assets, primarily production, from the Entrada field.  All assets of Callon Entrada, and its stock, are pledged to CIECO Entrada under the Callon Entrada credit agreement, and neither Callon nor its subsidiaries (other than Callon Entrada) guaranteed the Callon Entrada credit facility.

 Prior to January 1, 2010, the Company was required to consolidate the financial statements and results of operations of Callon Entrada, and as such, Callon Entrada’s non-recourse principal and interest due under the credit facility was reflected in a separate line item in Callon’s 2009 consolidated financial statements.

In June 2009, the Financial Accounting Standards Board (“FASB”) issued an accounting standard which became effective for the first annual reporting period that begins after November 15, 2009 (with early adoption prohibited), and which amended US GAAP as follows:

 
·
to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a Variable Interest Entity (“VIE”), identifying the primary beneficiary of a VIE;
 
·
to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur;
 
·
to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE;
 
·
to amend certain guidance for determining whether an entity is a VIE;
 
·
to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur;
 
·
to eliminate the exception for troubled debt restructuring regarding VIE reconsideration;  and
 
·
to require advanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in a VIE.

The Company adopted the pronouncement for consolidation of variable interest entities on January 1, 2010.  Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada.  Based on the evaluation performed, which is detailed below, the Company concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary and, as a result, Callon Entrada is deconsolidated from the Company’s consolidated financial statements as of January 1, 2010.  The Company included additional disclosures related to the deconsolidation of Callon Entrada in its Form 10-K for the year-ended December 31, 2009.  Key events considered in this analysis include the following:

Default on non-recourse debt and CIECO’s acceleration rights exercised:  As a result of abandoning the Entrada project in November 2008, prior to completion, Callon Entrada’s only source of payment is the proceeds from the sale of equipment purchased but not used for the Entrada project. On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada credit agreement to accelerate payment of the principal and interest due, and to invoke its rights to the surplus equipment related to the Entrada project, including the proceeds from the sale of the equipment and the ability to control the decisions related to the sale of the equipment.  Based on the advice of legal counsel, Callon believes that it and its other subsidiaries are not otherwise obligated to repay the principal, accrued interest or any other amounts which may become due under the Callon Entrada credit facility.

 
7

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


     Abandonment obligations satisfied:  Callon guaranteed Callon Entrada’s payment of all amounts to plug and abandon the wells and related facilities and for a breach of law, rule or regulation (including environmental laws) and for any losses of CIECO Entrada attributable to gross negligence of Callon Entrada.  The well for which Callon Entrada was responsible was plugged and abandoned in the fourth of quarter of 2008, and the Minerals Management Service (“MMS”) confirmed to Callon during September 2009 that Callon had satisfied all if its abandonment obligations related to this project.

No ability to control future actions of Callon Entrada: As of December 31, 2009, the wind down of the Entrada project was complete, all of the costs related to the Entrada project were paid, and subsequent to the lease expiration June 1, 2009, control of the property reverted to the MMS.  The sale of remaining equipment purchased for the Entrada project remains ongoing, and the Company believes that the amount of future operating costs of Callon Entrada, for which the Company would be responsible for, is insignificant and is limited to minimal storage fees for the surplus equipment while the equipment is being liquidated.

As a result of the events described above, the Company lost its power to direct the only remaining activities that affect Callon Entrada’s future economic performance.  Below is a condensed balance sheet of Callon presented to demonstrate the effect of deconsolidation on the financial statements at January 1, 2010:

   
Callon
   
Callon
   
Callon
 
   
Consolidated
   
Entrada
   
Consolidated
 
   
at 12/31/09
   
Deconsolidated
   
at 1/1/2010
 
Balance Sheet (in thousands)
                 
Total current assets
  $ 77,684     $ (1,767 )   $ 75,917  
Total oil and gas properties
    130,608       -       130,608  
Other property and equipment
    2,508       -       2,508  
Other assets
    17,191       -       17,191  
  Total assets
  $ 227,991     $ (1,767 )   $ 226,224  
                         
Other current liabilities
  $ 16,889     $ (2,015 )   $ 14,874  
9.75% Senior Notes, due December 2010
    15,820       -       15,820  
Callon Entrada non-recourse credit facility
    84,847       (84,847 )     -  
  Total current liabilities
    117,556       (86,862 )     30,694  
Total long-term debt
    179,174       -       179,174  
Total other long-term liabilities
    12,115       -       12,115  
Total stockholders’ equity (deficit)
    (80,854 )     85,095       4,241  
   Total liabilities and stockholders’ equity (deficit)
  $ 227,991     $ (1,767 )   $ 226,224  
                         


 
8

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


Note 3 – Minerals Management Service (“MMS”) Royalty Recoupment

During 2009, we recorded a receivable attributable to a recoupment of royalty payments we previously made to the MMS on our deepwater property, Medusa.  Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the MMS was not entitled to receive these royalty payments.  Accordingly, in November 2009 the Company filed for a recoupment of royalties paid to the MMS in the amount of $44,787 from inception-to-date production at the Company’s Medusa field.  At December 31, 2009, Callon accrued the royalty recoupment of $44,787 and estimated interest of $7,681.  The Company received the recoupment of principal in January 2010, and received $7,927 of interest during the second quarter of 2010, which included additional accrued interest through the repayment date.

Note 4 - Earnings per Share

The following table sets forth the computation of basic and diluted earnings per share:

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
                         
(a) Net income (loss)
  $ 2,130     $ (925 )   $ 6,053     $ 1,479  
                                 
(b) Weighted average shares outstanding
    28,762       21,645       28,750       21,626  
      Dilutive impact of stock options
    196       -       117       -  
      Dilutive impact of restricted stock
    625       -       539       -  
                                 
(c) Weighted average shares outstanding
                               
         for diluted net income per share
    29,583       21,645       29,406       21,626  
                                 
Basic net income per share (a/b)
  $ 0.07     $ (0.04 )   $ 0.21     $ 0.07  
Diluted net income per share (a/c)
  $ 0.07     $ (0.04 )   $ 0.21     $ 0.07  
                                 
The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive:
 
                                 
Stock options
    147       1,003       177       1,003  
Warrants
    365       365       365       365  
Restricted stock
    179       634       179       634  

Note 5 - Comprehensive Income (Loss)

The components of comprehensive income (loss), net of related taxes, are as follows:

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
                         
Net income
  $ 2,130     $ (925 )   $ 6,053     $ 1,479  
Other comprehensive income:
                               
     Change in fair value of derivatives
    1,260       (7,815 )     1,451       (14,738 )
Total comprehensive income (loss)
  $ 3,390     $ (8,740 )   $ 7,504     $ (13,259 )


 
9

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


Note 6 – Borrowings

The Company’s borrowings consisted of the following at:

 
 
June 30, 2010
   
December 31, 2009
 
Principal components:
           
     Senior secured revolving credit facility
  $ -     $ 10,000  
      9.75% Senior Notes due 2010, principal
    -       16,052  
     13% Senior Notes due 2016, principal
    137,961       137,961  
     Callon Entrada non-recourse credit facility (1)
    -       84,847  
          Total principal outstanding
    137,961       248,860  
Non-cash components:
               
     9.75% Senior Notes, due 2010 unamortized discount
    -       (232 )
     13% Senior Notes due 2016 unamortized deferred credit
    29,417       31,213  
          Total carrying value
  $ 167,378     $ 279,841  

(1) Liability was removed as part of the deconsolidation of Callon Entrada.  See Note 2 for additional information.

Senior Secured Revolving Credit Facility (the “Credit Facility”)

In January 2010, the Company amended its Credit Facility agreement to include Regions Bank as the sole arranger and administrative agent. The third amended and restated Credit Facility, which matures on September 25, 2012, provides for a $100,000 facility with an initial borrowing base of $20,000, which will be reviewed and re-determined on a semi-annual basis during the second and fourth quarters.  The Credit Facility bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%.  As of June 30, 2010, the interest rate on the facility was 6%.  In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly.  During July 2010, Regions Bank affirmed the $20,000 borrowing base until the next scheduled review during the fourth quarter.

Simultaneously with the execution of the third amended and restated Credit Facility, the Company repaid the $10,000 outstanding draw under the second amended and restated senior secured credit agreement, which was outstanding as of December 31, 2009.

9.75% Senior Notes (“Old Notes”) (Due December 2010)

During the fourth quarter of 2009, Callon commenced an exchange offer for any and all of its outstanding Old Notes.  Holders of approximately 92% of the Old Notes tendered their Notes in the exchange offer.   During March 2010, the Company announced its intention to redeem all remaining Old Notes by April 30, 2010 (the “Redemption Date”) at a redemption price of 101% of their principal amount, plus accrued and unpaid interest to the Redemption Date.  Pursuant to the terms of the debt agreement, the Company mailed a notice of redemption to all registered holders of the remaining Old Notes, and posted the notice with the responsible transfer agent.

On April 30, 2010, the Company completed its publically announced plans to redeem for 101% of the par value the remaining $16,052 outstanding Old Notes for $16,343, which included the 1% call premium and $130 of accrued interest through the repurchase date.  The Company also recognized $179 of additional interest expense related to the accelerated amortization of the Old Notes’ remaining discount and debt issuance costs, which when added to the $160 call premium resulted in a $339 loss on early extinguishment of this debt.  As of June 30, 2010, no Old Notes remain outstanding.




 
10

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit

As described above, during the fourth quarter of 2009, the Company exchanged approximately 92% of the principal amount, or $183,948, of the Old Notes for $137,961 of Senior Notes.  The exchange resulted in a 25% reduction in the principal amount of the Old Notes tendered, and included a 3.25% increase in the coupon rate from 9.75% to 13%.  In addition, holders of the tendered notes received 3,794 shares of common stock and 311 shares of Convertible Preferred Stock which was valued on November 24, 2009 in the amount of $11,527 and recorded as an increase to stockholders’ equity.  On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock following shareholder approval and the filing of an amendment to the Company’s charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion.  The Senior Notes’ 13% interest coupon is payable on the last day of each quarter.

Upon issuing the Senior Notes during November 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527.  The difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a credit to interest expense over the life of the Senior Notes at an 8.5% effective interest rate.  The following table summarizes the Company’s deferred credit balance at June 30, 2010:

Gross Carrying Amount
   
Accumulated Amortization at June 30, 2010
   
Carrying Value at June 30, 2010
   
Amortization Recorded during 2010 as a Reduction of Interest Expense
   
Estimated Amortization
Expected to be Recorded for the
Remainder of 2010
 
$ 31,507     $ 2,090     $ 29,417     $ 1,796     $ 1,799  

Certain of the Company’s subsidiaries guarantee the Company’s obligations under the Senior Notes.  The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantors are minor.

Restrictive Covenants

The Indenture governing our Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios.  The Company was in compliance with these covenants at June 30, 2010.

Note 7 - Derivative Instruments and Hedging Activities

Objectives and Strategies for Using Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company utilizes primarily collars and swap derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices.  The Company does not use these instruments for trading purposes.

Counterparty Risk

The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the Company’s risk in this area, counterparties to the Company’s commodity derivative instruments include a large, well-known financial institution and a large, well-known oil and gas company.  The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices.

 
11

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement.

Settlements and Financial Statement Presentation

Settlements of oil and gas derivative contracts are generally based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (“NYMEX”) price or other cash or futures index price.  The current and non-current portion of derivative contracts are carried at fair value in the consolidated balance sheet under the caption “Fair Market Value of Derivatives” and “Other Assets, net / Other long-term liabilities” respectively.  The oil and gas derivative contracts are settled based upon reported prices on NYMEX.  The estimated fair value of these contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options.  See Note 8, “Fair Value Measurements.”

The Company’s derivative contracts that are designated as cash flow hedges, and are recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity (deficit). The cash settlements on contracts for future production are recorded as an increase or decrease in oil and gas sales.  Both changes in fair value and cash settlements of ineffective derivative contracts are recognized as derivative expense (income).

Listed in the table below are the outstanding oil and gas derivative contracts, consisting entirely of collars, as of June 30, 2010:
Product
 
Volumes per Month
 
Quantity Type
 
Average Floor Price per Hedge
   
Average Ceiling Price per Hedge
 
Period
                       
Natural Gas
    75  
MMbtu
  $ 5.00     $ 8.30  
Jul10 - Dec10
                             
Oil
    20  
Bbls
  $ 70.00     $ 91.50  
Jul10 - Dec10
Oil
    10  
Bbls
  $ 75.00     $ 101.50  
Jul10 - Dec10
Oil
    10  
Bbls
  $ 75.00     $ 101.85  
Jan11 - Dec11
Oil
    5  
Bbls
  $ 80.00     $ 102.00  
Jan11 - Dec11

The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and gas sales:

   
Three-Months ended June 30,
 
Six-Months ended June 30,
   
2010
 
2009
 
2010
 
2009
                 
Amount of gain reclassified from OCI into income (effective portion)
 
       224
 
    4,534
 
       240
 
  12,392
Amount of gain (loss) recognized in income (ineffective portion and
   amount excluded from effectiveness testing)
 
         -
 
         -
 
         -
 
         -
 

 
Subsequent event:  During August 2010, the Company executed additional oil hedge collars as follows:
Product
 
Volumes per Month
 
Quantity Type
 
Average Floor Price
per Hedge
   
Average Ceiling Price
per Hedge
 
Period
                       
Oil
    10  
Bbls
  $ 75.00     $ 94.50  
Jan11 - Dec11

 
12

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


Note 8 - Fair Value Measurements

The fair value hierarchy outlined in the relevant accounting guidance gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.

Fair Value of Financial Instruments

 Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable and Accounts Payable. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
 
Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet.  The fair value of Callon’s fixed-rate debt is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

The following table summarizes the respective fair values at:
 
 
 
 
June 30, 2010
   
December 31, 2009
 
   
Carrying Value
   
Fair Value
   
Carrying Value
   
Fair Value
 
                         
Credit Facility
  $ -     $ -     $ 10,000     $ 10,000  
9.75% Senior Notes due 2010, net of unamortized discount
    -       -       15,820       15,249  
13% Senior Notes due 2016 (1)
    167,378       108,989       169,174       103,471  
Callon Entrada Credit Facility; non-recourse
    -       -       84,847       -  
     Total
  $ 167,378     $ 108,989     $ 279,841     $ 128,720  
                                 
(1) 2010 Fair value is calculated only in relation to the $137,961 par value outstanding of the 13% Senior Notes. The remaining $29,417, which the company has recorded as a deferred credit, is excluded from the fair value calculation, and will be fully realized in earnings by the Company over the remaining amortization period.  See Note 6 for additional information.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

 Commodity Derivative Instruments. Callon’s derivative policy allows for commodity derivative instruments to consist of collars and natural gas and crude oil basis swaps, though at June 30, 2010 the Company’s portfolio included only collars.  The fair values of the Company’s derivative instruments are not actively quoted in the open market and are valued using forward commodity price curves.  Consequently, the Company estimates the fair values of derivative instruments using internal discounted cash flow calculations based upon forward commodity price curves, and is corroborated by quotes obtained from counterparties to the agreements.  These valuations include primarily Level 3 inputs. For additional information, see Note 7, Derivative Instruments and Hedging Activities, of this Form 10-Q.


 
13

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:

As of June 30, 2010
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets
                       
Derivative financial instruments
  $ -     $ -     $ 1,596     $ 1,596  
                                 
Liabilities
                               
Derivative financial instruments
  $ -     $ -     $ -     $ -  
                                 
Total
  $ -     $ -     $ 1,596     $ 1,596  

As of December 31, 2009
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets
                       
Derivative financial instruments
  $ -     $ -     $ 145     $ 145  
                                 
Liabilities
                               
Derivative financial instruments
  $ -     $ -     $ -     $ -  
                                 
Total
  $ -     $ -     $ 145     $ 145  

The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. Additionally, $1,106 of the derivative assets is reflected as a current asset on the Company’s Consolidated Balance Sheet at June 30, 2010 and as such is expected to settle within the next twelve months.  See Note 7, Derivative Instruments and Hedging Activities, of this Form 10-Q for a discussion of net amounts recorded on the Consolidated Balance Sheet at June 30, 2010.

The following table presents the Company’s assets and liabilities measured at fair value on a recurring basis using significant, unobserved inputs (Level 3):
   
Derivatives
 
Balance at January 1, 2010
  $ 145  
   Total gains or losses (realized or unrealized):
       
         Included in earnings
    240  
         Included in other comprehensive (income) loss
    1,451  
   Purchases, issuances and settlements
    (240 )
Balance at June 30, 2010
  $ 1,596  
         
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of June 30, 2010
  $ -  

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations Incurred in Current Period. Callon estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as (1) the existence of a legal obligation for an ARO, (2) amounts and timing of settlements, (3) the credit-adjusted risk-free rate to be used and (4) inflation rates. AROs incurred in the current period, including upward revisions to ARO liabilities, were $290 and were Level 3 fair value measurements. See Note 10, Asset Retirement Obligations, which
 provides a summary of changes in the ARO liability.

 
14

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(all amounts in thousands, except per-share and per-hedge data)


Note 9 - Income Taxes

The following table presents Callon’s net unrecognized tax benefits relating to its reported net losses and other temporary differences from operations :
   
June 30, 2010
   
December 31, 2009
 
Deferred tax asset:
           
   Federal net operating loss carryforwards
  $ 94,031     $ 94,125  
   Statutory depletion carryforwards
    4,982       4,895  
   Alternative minimum tax credit carryforward
    383       383  
   Asset retirement obligations
    3,694       3,704  
   Other
    5,040       34,170  
      Deferred tax asset before valuation allowance
    108,130       137,277  
   Less: Valuation allowance
    (84,036 )     (116,676 )
Total deferred tax asset
    24,094       20,601  
Deferred tax liability:
               
   Oil and gas properties
    12,649       9,555  
   Other
    11,445       11,046  
Total deferred tax liability
    24,094       20,601  
                 
Net deferred tax asset
  $ -     $ -  

As of January 1, 2010 and as previously disclosed in Note 2, Callon Entrada has been deconsolidated from the Company’s consolidated financial statements, resulting in a $30,330 decrease in deferred tax assets and a corresponding reduction in the valuation allowance.

As previously disclosed in Note 6 of the Company’s 2009 Form 10-K, the Company recorded a full valuation allowance against its net deferred tax assets.  Consequently, the Company’s effective tax rate will be affected in future periods to the extent these deferred tax assets are recognized. The Company continues to assess whether or not deferred tax assets can be recognized based on current and expected future operating results and other factors.  

Note 10 - Asset Retirement Obligations

The following table summarizes the Company’s asset retirement obligations activity for the six-months ended June 30, 2010:

Asset retirement obligations at January 1, 2010
  $ 14,650  
   Accretion expense
    1,202  
   Liabilities incurred
    8  
   Liabilities settled
    (1,597 )
   Revisions to estimate
    656  
Asset retirement obligations at end of period
    14,919  
   Less: current asset retirement obligations
    (3,377 )
Long-term asset retirement obligations at end of period
  $ 11,542  

Liabilities settled primarily relate to individual properties, primarily located in the Gulf of Mexico, plugged and abandoned during the period.

Restricted assets, primarily U.S. Government securities, of approximately $4,365 at June 30, 2010, 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.


 
15

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Certain statements in this Current Report on Form 10-Q (or otherwise made by or on the behalf of Callon Petroleum) contain 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 (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995.  Such statements represent management's beliefs and assumptions concerning future events. When used in this document and in documents incorporated by reference, forward-looking statements include, without limitation, statements regarding financial forecasts or projections, our expectations, beliefs, intentions or future strategies that are signified by the words "expects," "anticipates," "intends," "believes" or similar language. These forward-looking statements are subject to risks, uncertainties and assumptions that could cause our actual results and the timing of certain events to differ materially from those expressed in the forward-looking statements. All forward-looking statements included in this Report are based on information available to us on the date of this Report. It is routine for our internal projections and expectations to change as the year or each quarter in the year progress, and therefore it should be clearly understood that the internal projections, beliefs and assumptions upon which we base our expectations may change prior to the end of each quarter or the year. Although these expectations may change, we may not inform you if they do. Our policy is generally to provide our expectations only once per quarter, and not to update that information until the next quarter.

Many important factors, in addition to those discussed in this Report, could cause our results to differ materially from those expressed in the forward-looking statements. Some of the potential factors that could affect our results are described below within Management’s Discussion and Analysis of Financial Condition and Results of Operations.  In light of these risks and uncertainties, and others not described in this Report, the forward-looking events discussed in this Report might not occur, might occur at a different time, or might cause effects of a different magnitude or direction than presently anticipated.

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations.  This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009 (“Annual Report”), which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. The Company also updates, as necessary, its risk factors in Part II, Item 1A of this filing.

Our website address is www.callon.com.  All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC.  Information on our website does not form part of this report on Form 10-Q.

We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico.  During 2009, we took steps to change our operational focus to lower risk, onshore exploration and development activities.

Overview and Outlook

Building on our transition in 2009, during the second quarter of 2010, we continued to show improving quarter-over-quarter results of operations with net income and fully diluted earnings per share of $2.1 million and $0.07, respectively, compared to a net loss of $0.9 million and diluted loss per share of $0.04, respectively for the same three-month period of 2009.  Further, our year-to-date net income and fully diluted earnings per share of $6.1 million and $0.21, respectively, represents a $4.6 million and $0.14 increase, respectively, over the same six-month period of 2009.  These results are discussed in greater detail within the “Results of Operations” section included below.


 
16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
In an effort to position ourselves for future growth, we remain focused on strengthening our balance sheet by improving our liquidity.  We made significant progress during the first six months of 2010:

 
·
Including principal and interest, we received $52.7 million for recoupment of deepwater royalty payments made to the MMS.
 
 
·
We successfully completed a $100 million amended revolving credit facility, with a borrowing base of $20 million, which was reaffirmed during July 2010 by the related bank.

 
·
After a successful fourth quarter 2009 restructuring our 9.75% Senior Notes due December 2010 (the “Old Notes”), we completed on April 30, 2010 the redemption of the remaining $16.1 million outstanding of Old Notes held by those noteholders who did not participate in the exchange.  The restructuring reduced by 25% the principal balance and extended the restructured notes’ maturity from 2010 to 2016 in exchange for a 3.25% increase in the coupon rate and equity consideration.

Our success in these areas allows us to shift our operational focus from the offshore Gulf of Mexico to developing longer life, lower risk onshore properties.  Our new onshore properties along with the strong cash flow from our Gulf of Mexico operations have already begun to re-shape our portfolio and outlook, and we are well positioned to continue the pursuit of diversifying our portfolio by building profitable growth opportunities onshore.  During 2010, we began to develop the properties we acquired during late 2009:

 
·
During the fourth quarter of 2009, we acquired interests in properties producing from the Permian Basin’s Wolfberry formation in Crockett, Ector, Midland and Upton Counties, Texas.  The acquisition included year-end proven reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe per day and upside from a multi-year inventory of drilling opportunities.  During 2010, we began an accelerated development program for this asset under which we plan to drill 22 to 24 wells during the current year, which when completed, is expected to significantly increase our current Permian Basin production from 350 Boe per day to 1,000 Boe per day.  We operate substantially all of the production and development of these properties.   During the first six months of 2010, we drilled and placed on production six wells, and as of June 30, 2010 on this property, we were in the process of completing a seventh well while also drilling an eighth additional well.

 
·
Also during the fourth quarter of 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana.   We plan to drill a total of seven horizontal wells on this property, which we will operate, and the first well, which was spud during June 2010, is expected to be completed and producing by September 2010.

Also highlighting the continued successful execution of our long-term strategy, on April 23, 2010 the New York Stock Exchange (“NYSE”) removed Callon from its “Watch List” and affirmed that we are now considered a “company back in compliance” with the NYSE’s quantitative continued listing standards.

In our effort to continue to conduct safe operations, and in an effort to evaluate any potential affect on our planned production, we continue to monitor the status of the oil spill that occurred off the Louisiana coast, including potential regulatory changes stemming from the incident.  Based on the information currently available, we see neither an immediate safety concern for those operating on our offshore facilities, nor a threat to our planned production levels. In response to the recent oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.  We are also monitoring the status of the recently imposed deep water drilling moratorium, though at present we do not believe it will affect our planned drilling program related to developing future reserves as the initial length of the drilling moratorium does not interfere with our currently planned drilling program.

We also continue to monitor the changing regulatory environment, particularly the passing of the recent Dodd-Frank Wall Street Reform and Consumer Protection act (the “Bill”) of 2010, including its section 1504 that is applicable to “resource extraction issuers” (i.e. oil and gas companies).  Among a broad spectrum of the Bill’s provisions aimed at reforming the United States’ financial system in an effort to reduce systemic risk, the Bill contains various corporate governance and disclosure provisions.  While it is too soon to fully analyze the impact the new legislation will have on our operations and profitability, we do not currently believe that its Section 1504 will materially affect our operations or profitability.  We will continue to monitor the regulatory environment in our effort to proactively respond the relevant changes.

 
17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

 
Deconsolidation of Callon Entrada

As more fully discussed in Note 2, Deconsolidation of Callon Entrada, included in Item I, Part I of this filing, in June 2009, the FASB issued an accounting standard which became effective for the first annual reporting period that begins after November 15, 2009 (with early adoption prohibited), and which amended US GAAP in several ways, which are disclosed in Note 2 included in Part I, Item 1 of this filing.  We adopted this pronouncement on January 1, 2010.

Upon adoption and as a result of the amendments described above, we reevaluated our interest in Callon Entrada, and based on the evaluation performed, we concluded that a VIE reconsideration event had taken place.  Our reconsideration analysis resulted in the determination that Callon Entrada is a VIE for which we are not the primary beneficiary.  Consequently, effective January 1, 2010, Callon Entrada was deconsolidated from our consolidated financial statements.

The deconsolidation of Callon Entrada resulted in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities, $30 million of deferred tax assets, $30.3 million of tax valuation allowance and approximately $84.8 million of non-recourse debt and the related obligation for the cumulative amount of interest.  Retained earnings increased by $85.1 million as a cumulative effect of change related to this accounting standard.  No gain was recognized in the statement of operations. See Note 2 of Part I, Item I – Consolidated Financial Statements.

 

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities.  Net cash and cash equivalents increased by $28.2 million during the six months-ended June 30, 2010 to $31.8 million compared to $3.6 million at December 31, 2009.  Cash provided from operating activities during the first six months of 2010 totaled $74.0 million, an increase of $74.5 million compared to the same quarter of 2009.  The increase in liquidity is primarily attributable to receipt of the $44.8 million MMS royalty recoupment and related interest of $7.9 million as well as a reduction in year-over-year payables following the abandonment of the Entrada project.

During 2009, we recorded a receivable attributable to a recoupment of royalty payments we previously made to the MMS on our deep water property, Medusa.  Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the MMS was not entitled to receive these royalty payments.  Accordingly the MMS refunded the payments previously made.  We received the principal payment of $44.8 million in January 2010, and received approximately $7.9 million during the second quarter of 2010 representing interest on the amounts previously withheld.

In January 2010, we amended our Senior Secured Credit Agreement to include Regions Bank as the sole arranger and administrative agent. The third amended and restated senior secured credit agreement, which matures on September 25, 2012, provides for a $100 million facility with an initial borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis.  The third amended and restated credit facility (“Credit Facility”) bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%.  As of June 30, 2010, the interest rate on the facility was 6%.  In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly.  Simultaneously with the execution of the third amended and restated senior secured credit agreement, we repaid the $10 million outstanding on the borrowing base under the second amended and restated senior secured credit agreement, which was outstanding as of December 31, 2009.  No amounts were outstanding under the amended facility as of June 30, 2010.

During the fourth quarter of 2009, we completed an exchange offer for our $200 million of outstanding 9.75% Senior Notes due December 2010 (“Old Notes”).  Holders of approximately 92% of the 9.75% Old Notes tendered their notes in the exchange offer, and received in their place 13% Senior Notes due 2016 (“Senior Notes”).  The exchange offer included a 25% decrease in the principal amount exchanged, increased the coupon rate to 13%

 
18

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
 
and included equity consideration.  In addition, holders who tendered Old Notes consented to amend the indenture governing the Old Notes, eliminating substantially all of the indenture’s restrictive covenants.  On April 30, 2010, as previously discussed, we used a portion of the proceeds received from the MMS recoupment to retire the remaining $16.1 million of Old Notes, which did not exchange, for 101% of par plus accrued interest not yet paid.  At June 30, 2010, $137.9 million of the 13% Senior Notes were outstanding with interest payable quarterly.

2010 Budget and Capital Expenditures.  For 2010, we designed a flexible capital spending program that can be funded from cash on hand and cash flows from operations.  Our preliminary base capital program includes an accelerated development program of our Permian Basin crude oil assets as well as exploiting our Haynesville Shale gas play.

 
·
Our 2010 capital budget approximates $65 million and includes plugging and abandonment, capitalized interest and certain overhead costs related to acquiring, exploring and developing our oil and gas properties.  However, depending on commodity prices and other economic conditions that develop during the current year, this base capital program may be adjusted upward or downward.  

 
·
Planned capital expenditures for 2010 include, in addition to other less significant items, drilling and completing up to 23 wells in the Permian Basin and drilling and completing one well in the Haynesville Shale gas play.

 
·
In addition, should we identify an attractive strategic opportunity or acquisition, we have a $20 million borrowing base available under our Credit Facility.

 
·
We believe that our cash on hand and operating cash flow along with our Credit Facility, if needed, will be adequate to meet our capital, interest payments, and operating requirements for 2010.

Summary cash flow information is provided as follows:

Operating Activities.  For the six-months ended June 30, 2010, net cash provided by operating activities was $74.0 million, a $74.5 million increase from net cash used in operating activities of $0.5 million for the same period in 2009. The increase in net cash provided by operating activities was primarily attributable to receipt of the $44.8 million MMS royalty recoupment plus interest and higher commodity prices on an equivalent basis, partially offset by production declines.

Investing Activities.  For the six-months ended June 30, 2010, net cash used in investing activities was $19.5 million as compared to $20.8 million for the same period in 2009. The $1.3 million decrease in net cash used in investing activities, primarily attributable to a decrease in capital expenditures, relates to wind-down costs paid in 2009 for the Callon Entrada project offset by 2010 capital expenditures related to drilling new wells in the Permian Basin.

Financing Activities.  For the six-months ended June 30, 2010, net cash used in financing activities was $26.0 million compared to cash provided of $5.0 million for the same period in 2009. The 2010 expenditure related to the redemption of all remaining 9.75% Old Notes and to the repayment of outstanding borrowings under the Credit Facility simultaneously with its being amended to include Regions Bank as the sole arranger and administrative agent.

 
19

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

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 June 30,
 
   
2010
   
2009
   
Change
   
% Change
 
Net production:
                       
  Oil (MBbls)
    215       263       (48 )     (18 )%
  Gas (MMcf)
    1,085       1,433       (348 )     (24 )%
  Total production (MMcfe)
    2,374       3,010       (636 )     (21 )%
  Average daily production (MMcfe)
    26.1       33.1       (7.0 )     (21 )%
                                 
Average realized sales price (a):
                               
  Oil (Bbl)
  $ 74.03     $ 72.22     $ 1.81       3 %
  Gas (Mcf)
    5.22       4.22       1.00       24 %
  Total (Mcfe)
    9.09       8.32       0.77       9 %
                                 
Oil and gas revenues (in thousands):
                               
  Oil revenue
  $ 15,901     $ 18,971     $ (3,070 )     (16 )%
  Gas revenue
    5,668       6,054       (386 )     (6 )%
  Total
  $ 21,569     $ 25,025     $ (3,456 )     (14 )%
                                 
Additional per Mcfe data:
                               
  Sales price
  $ 9.09     $ 8.32     $ 0.77       9 %
  Lease operating expense
    (1.70 )     (1.55 )     (0.15 )     10 %
  Operating margin
  $ 7.39     $ 6.77     $ 0.62       9 %
                                 
Other expenses on a per Mcfe basis:
                               
  Depletion, depreciation and amortization
  $ 2.97     $ 2.81     $ 0.16       6 %
  General and administrative (net of management fees)
  $ 1.86     $ 1.79     $ 0.07       4 %
                                 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil / Mcf of gas:
 
                                 
Average NYMEX oil price
  $ 78.03     $ 59.62     $ 18.41       31 %
  Basis differential and quality adjustments
    (2.88 )     (3.30 )     0.42       (13 )%
  Transportation
    (1.16 )     (1.36 )     0.20       (15 )%
  Hedging
    0.04       17.26       (17.22 )     (100 )%
Average realized oil price
  $ 74.03     $ 72.22     $ 1.81       3 %
                                 
Average NYMEX gas price
  $ 4.34     $ 3.82     $ 0.52       14 %
  Natural gas liquid content and volume conversion adjustments
    0.70       0.40       0.30       75 %
  Hedging
    0.18       -       0.18       100 %
Average realized gas price
  $ 5.22     $ 4.22     $ 1.00       24 %
                                 

 
 

 
20

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Results of Operations (continued)
 
The following table sets forth certain unaudited operating information with respect to the Company's oil and gas operations for the periods indicated:

 
 
Six-Months Ended June 30,
 
   
2010
   
2009
   
Change
   
% Change
 
Net production:
                       
  Oil (MBbls)
    438       526       (88 )     (17 )%
  Gas (MMcf)
    2,252       2,880       (628 )     (22 )%
  Total production (MMcfe)
    4,877       6,036       (1,159 )     (19 )%
  Average daily production (MMcfe)
    26.9       33.3       (6.4 )     (19 )%
                                 
Average realized sales price (a):
                               
  Oil (Bbl)
  $ 74.41     $ 66.39     $ 8.02       12 %
  Gas (Mcf)
    5.50       5.18       0.32       6 %
  Total (Mcfe)
    9.22       8.26       0.96       12 %
                                 
Oil and gas revenues (in thousands):
                               
  Oil revenue
  $ 32,564     $ 34,923     $ (2,359 )     (7 )%
  Gas revenue
    12,390       14,917       (2,527 )     (17 )%
  Total
  $ 44,954     $ 49,840     $ (4,886 )     (10 )%
                                 
Additional per Mcfe data:
                               
  Sales price
  $ 9.22     $ 8.26     $ 0.96       12 %
  Lease operating expense
    (1.78 )     (1.44 )     (0.34 )     24 %
  Operating margin
  $ 7.44     $ 6.82     $ 0.62       9 %
                                 
Other expenses on a per Mcfe basis:
                               
  Depletion, depreciation and amortization
  $ 2.84     $ 2.96     $ (0.12 )     (4 )%
  General and administrative (net of management fees)
  1.79     $ 1.19     $ 0.60       50 %
                                 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil / Mcf of gas:
 
                                 
Average NYMEX oil price
  $ 78.37     $ 51.35     $ 27.02       53 %
  Basis differential and quality adjustments
    (2.83 )     (3.68 )     0.85       (23 )%
  Transportation
    (1.16 )     (1.35 )     0.19       (14 )%
  Hedging
    0.03       20.07       (20.04 )     (100 )%
Average realized oil price
  $ 74.41     $ 66.39     $ 8.02       12 %
                                 
Average NYMEX gas price
  $ 4.69     $ 4.15     $ 0.54       13 %
  Natural gas liquid content and volume conversion adjustments
    0.73       0.39       0.34       87 %
  Hedging
    0.08       0.64       (0.56 )     (88 )%
Average realized gas price
  $ 5.50     $ 5.18     $ 0.32       6 %

 
21

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Revenues

    The following tables are intended to reconcile the change in crude oil, natural gas and total revenue by reflecting the effect of changes in volume, changes in the underlying commodity prices and the impact of our hedge program.

Changes in Oil and Gas Production Revenues – Three Months
 
                   
   
Crude Oil
   
Natural Gas
   
Total
 
                   
Revenues for the three-months ended June 30, 2008
  $ 28,554     $ 19,475     $ 48,029  
                         
Volume increase (decrease)
    (2,288 )     (2,740 )     (5,028 )
Price increase (decrease)
    (11,829 )     (10,681 )     (22,510 )
Impact of hedges increase
    4,534       -       4,534  
Net increase (decrease) in 2009
    (9,583 )     (13,421 )     (23,004 )
                         
Revenues for the three-months ended June 30, 2009
  $ 18,971     $ 6,054     $ 25,025  
                         
Volume increase (decrease)
    (3,458 )     (1,471 )     (4,929 )
Price increase (decrease)
    379       870       1,249  
Impact of hedges increase
    9       215       224  
Net increase (decrease) in 2010
    (3,070 )     (386 )     (3,456 )
                         
Revenues for the three-months ended June 30, 2010
  $ 15,901     $ 5,668     $ 21,569  



Changes in Oil and Gas Production Revenues – Six Months
 
                   
   
Crude Oil
   
Natural Gas
   
Total
 
                   
Revenues for the six-months ended June 30, 2008
  $ 53,650     $ 39,339     $ 92,989  
                         
Volume increase (decrease)
    (4,595 )     (9,202 )     (13,797 )
Price increase (decrease)
    (24,689 )     (17,055 )     (41,744 )
Impact of hedges increase
    10,557       1,835       12,392  
Net increase (decrease) in 2009
    (18,727 )     (24,422 )     (43,149 )
                         
Revenues for the six-months ended June 30, 2009
  $ 34,923     $ 14,917     $ 49,840  
                         
Volume increase (decrease)
    (5,863 )     (3,255 )     (9,118 )
Price increase (decrease)
    3,495       497       3,992  
Impact of hedges increase
    9       231       240  
Net increase (decrease) in 2010
    (2,359 )     (2,527 )     (4,886 )
                         
Revenues for the six-months ended June 30, 2010
  $ 32,564     $ 12,390     $ 44,954  


 
22

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Total Revenue

For the three-months ended June 30, 2010, total oil and gas revenues of $21.6 million decreased approximately $3.5 million or 14% from $25.0 million for the same period of 2009.  Compared to the second quarter of 2009, total production on an equivalent basis decreased by 21% during the second quarter of 2010. This decline in 2010 production was partially offset by an increase in the average sales price of both oil and gas of 3% and 24%, respectively or 9% on an equivalent basis.

For the six-months ended June 30, 2010, total oil and gas revenues of $45.0 million decreased approximately $4.8 million or 10% from $49.8 million for the same period of 2009.  Compared to the first six months of 2009, total production on an equivalent basis decreased by 19% during the first half of 2010. This decline in 2010 production was partially offset by an increase in the average sales price of both oil and gas of 12% and 6%, respectively or 12% on an equivalent basis.

Oil Revenue

For the three-months ended June 30, 2010, oil revenues of $15.9 million decreased $3.1 million or 16% from the same period of 2009.  The largest contributor to the three-month period-over-period decline was an 18% decrease in production, but was slightly offset by a 3% period-over-period increase in the average sales price of oil, after accounting for the effects of hedging.  In addition to normal and expected production declines, volumes declined primarily due to our working interest in Habanero #1 decreasing from 25% to 11.25% in June 2009 following the payout of a sidetrack on this well.  The payout was associated with a third quarter 2007 sidetrack of the #1 well for which the operator elected to non-consent.  These declines were partially offset by production from our newly drilled and completed wells on the Permian Basin properties that we acquired during the fourth quarter of 2009.

For the six-months ended June 30, 2010, oil revenues of $32.6 million decreased $2.4 million or 7% compared to revenues of $34.9 million for the same period of 2009.  The largest contributor to the six-month period-over-period decline was a 17% decrease in production, but was partially offset by a 12% period-over-period increase in the average sales price of oil, after accounting for the effects of hedging.  In addition to normal and expected production declines, volumes declined as discussed above related to our Habanero #1 working interest following its payout in June 2009.  These declines were partially offset by production from our newly drilled and completed wells on the Permian Basin properties that we acquired during the fourth quarter of 2009.

Gas Revenue

For the three-months ended June 30, 2010, gas revenues of $5.7 million declined by 6% when compared to gas revenues of $6.1 million for the same period of 2009.  The largest contributor to the three-month period-over-period decline was a 24% decrease in production, but was largely offset by a 24% period-over-period increase in the average sales price of gas, after accounting for the effects of hedging.  Approximately 13 points of the 24% decrease in second quarter 2010 production was due to the host facility for East Cameron #2 well being shut-in due to damage resulting from a fire.  Production for East Cameron #2 is expected to be restored in the fourth quarter of 2010 following the completion of the necessary repairs.  The remaining 11 point decrease was a mix of both normal and expected declines from our legacy properties and due to the Habanero #1 well reversionary interest discussed above in the oil revenue analysis.

For the six-months ended June 30, 2010, gas revenues of $12.4 million declined by 17% when compared to gas revenues of $14.9 million for the same period of 2009.  The largest contributor to the six-month period-over-period decline was a 22% decrease in production, but was partially offset by a 6% period-over-period increase in the average sales price of oil, after accounting for the effects of hedging.  As mentioned above, more than 50% of the six-month period-over-period decline in production is largely attributable due to the shut-in of East Cameron #2 well.  Of the 22% decrease during the first half of 2010 as compared to the same period of 2009, 13 points of the decline related to the shut-in of this property.  Production for East Cameron #2 is expected to be restored in the fourth quarter of 2010.  The remaining 9 point decrease in production was due to normal and expected declines from our legacy properties and due to the Habanero #1 well reversionary interest discussed above in the oil revenue analysis.


 
23

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Operating Expenses

   
Three-Months ended June 30,
 
   
2010
   
Per Mcfe
   
2009
   
Per Mcfe
   
Year $ Change
   
Year % Change
 
Lease operating expenses
  $ 4,031     $ 1.70     $ 4,656     $ 1.55     $ (625 )     (13 )%
Depreciation, depletion and amortization
    7,042       2.97       8,452       2.81       (1,410 )     (17 )%
General and administrative, net
    4,411       1.86       5,391       1.79       (980 )     (18 )%
Accretion expense
    622       0.26       795       0.26       (173 )     (22 )%

   
Six-Months ended June 30,
 
   
2010
   
Per Mcfe
   
2009
   
Per Mcfe
   
Year $ Change
   
Year % Change
 
Lease operating expenses
  $ 8,679     $ 1.78     $ 8,695     $ 1.44     $ (16 )     (0 )%
Depreciation, depletion and amortization
    13,855       2.84       17,865       2.96       (4,010 )     (22 )%
General and administrative, net
    8,715       1.79       7,210       1.19       1,505       21 %
Accretion expense
    1,202       0.25       1,833       0.30       (631 )     (34 )%


Lease Operating Expenses

For the three-month period ended June 30, 2010, lease operating expenses (“LOE”) decreased 13% to $4.0 million compared to $4.7 million for the same period in 2009.  The primary contributor to the reduction in LOE was normal and expected declines in production in addition  to, as previously discussed above in the oil revenue comparative analysis, the reduction in our working interest in Habanero #1 well following the payout of a sidetrack on this well.  Partially offsetting these decreases, LOE increased related to our acquisition of the Permian Basin properties and a modest increase in insurance rates due to adding additional coverage to our program designed to better protect the Company from damage caused by severe weather.

For the six-month period ended June 30, 2010, lease operating expenses (“LOE”) remained flat at 8.7 million for the corresponding periods of 2010 and 2009.  While normal and expected declines in production in addition to the reduction in our Habanero #1 well working interest discussed above resulted in lower LOE, we experienced an offsetting increase in LOE related to our acquisition of the Permian Basin properties and a modest increase in insurance rates due to adding additional coverage to our program discussed above.

Depreciation, Depletion and Amortization

For the three-month period ended June 30, 2010, depreciation, depletion and amortization (“DD&A”) decreased approximately $1.4 million or 17% to $7.0 million compared to $8.5 million for the same period of 2009.  Production declines account for $1.8 million of the decrease, but are partially offset by a higher DD&A rate.

For the six-month period ended June 30, 2010, DD&A decreased approximately $4.0 million or 22% to $13.9 million compared to $17.9 million for the same period of 2009.  Production declines account for $3.3 million of the decrease, while a rate decrease further reduced DD&A.  The Company’s rate decreased primarily as a result of the downward revision during the second quarter of 2009 of the cost estimates for plugging and abandonment of the Entrada field and an increase in the December 31, 2009 proved reserves.

General and Administrative

For the three-month period ended June 30, 2010, general and administrative (“G&A”) expenses, net of amounts capitalized, decreased approximately $1.0 million or 18% to $4.4 million from $5.4 million for the same period of 2009.  The primary contributor to the three-month period-over-period decrease was a $2.2 million reduction in expenses related to staff reductions incurred during the second quarter of 2009, partially offset by a $1.4 million increase in share-based compensation awarded during 2010.  The remaining decrease relates to changes in various other G&A items, none of which individually were significant.

 
24

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

For the six-month period ended June 30, 2010, G&A expenses, net of amounts capitalized, increased $1.5 million or 21% to $8.7 million from $7.2 million for the same period of 2009.  Our performance-based incentive program runs from April to March, and adjustments to our accruals are recorded during the first quarter of the year subsequent to the issuance of final year-end financials.  During the first quarter of 2009, we recorded a 75% reduction in incentive-based compensation related to our actual 2008 results. These results, which were negatively affected by the decline in oil and gas prices, the abandonment of the Entrada project and worsening broader economic conditions, were lower than the performance goals set for fiscal year 2008.  Conversely, the increase experienced year-to-date in 2010 relates primarily to a 21% increase in incentive-based compensation related to exceeding performance goals set for fiscal year 2009.   Also contributing to the period-over-period increase is (1) a valuation adjustment to mark to fair value certain share-based awards issued in a prior year that will vest in the future, (2) additional employee-related costs, including non-recurring early retirement expenses, and (3) costs associated with adding new employees, including relocation and similar costs. Partially offsetting these increases is a $2.2 million reduction in expenses related to staff reductions incurred during the second quarter of 2009.

Accretion Expense

For the three-month period ended June 30, 2010, accretion expense related to our asset retirement obligations (“ARO”) decreased 22% to $0.6 million from $0.8 million compared to the same period of 2009.  Similarly, for the six-month period ended June 30, 2010, accretion expense related to our ARO decreased 34% to $1.2 million from $1.8 million compared to the same period of 2009.  As the Company’s ARO decreases, so too does the related accretion expense.  At June 30, 2010, ARO of $14.9 million was significantly lower compared to the June 30, 2009 balance of $35.0 million.  Additionally, as we plug and abandon shelf wells, we are replacing those properties with on-shore wells.  Our on-shore properties, in addition to typically having lower plugging and abandoning costs, tend to have longer lives, which therefore extends the accretion period and results in lower period expense.  For additional information regarding the companies ARO, see Note 10 included within the Consolidated Financial Statements found in Item 1, Part I of this filing.


 
25

Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Other
   
Three-Months ended June 30,
 
   
2010
   
2009
   
$ Change
   
% Change
 
Interest expense
  3,198     4,854     (1,656 )     (34 )%
Callon Entrada non-recourse credit facility interest expense (1)
    -       1,935       (1,935 )     (100 )%
Loss on early extinguishment of debt
    339       -       339       100 %
Other (income) expense
    (111 )     61       (172 )     (282 )%
Income tax expense
    -       24       (24 )     (100 )%

   
Six-Months ended June 30,
 
   
2010
   
2009
   
$ Change
   
% Change
 
Interest expense
  6,792     9,636     (2,844 )     (30 )%
Callon Entrada non-recourse credit facility interest expense (1)