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EXCEL - IDEA: XBRL DOCUMENT - Callon Petroleum CoFinancial_Report.xls
EX-32 - CERTIFICATION OF PERIODIC FINANCIAL REPORT - Callon Petroleum Coexhibit_32.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - Callon Petroleum Coexhibit_31-2.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER - Callon Petroleum Coexhibit_31-1.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

x
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended September 30, 2011
 
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)

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 x
 
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 x
   
Non-accelerated filer ¨
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 November 1, 2011 there were outstanding 39,397,451 shares of the Registrant’s common stock, par value $0.01 per share.

 

Table of Contents
Part I. Financial Information
 
   
Item 1. Financial Statements
 
   
3
   
4
   
5
   
6
   
14
   
26
   
26
   
Part II.  Other Information
 
   
27
   
27
   
28
   
28
   
Item 4.  [Removed and Reserved]
28
   
28
   
29
   
30
   





Part 1.  Financial Information
Item 1.  Financial Statements

Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except share data)

   
September 30, 2011
   
December 31, 2010
 
ASSETS
 
(Unaudited)
       
Current assets:
           
   Cash and cash equivalents
  $ 48,234     $ 17,436  
   Accounts receivable
    15,786       10,728  
   Fair market value of derivatives
    8,338       -  
   Other current assets
    1,744       2,180  
      Total current assets
    74,102       30,344  
                 
Oil and gas properties, full-cost accounting method:
               
   Evaluated properties
    1,388,501       1,316,677  
   Less accumulated depreciation, depletion and amortization
    (1,195,371 )     (1,155,915 )
      Net oil and gas properties
    193,130       160,762  
   Unevaluated properties excluded from amortization
    7,811       8,106  
      Total oil and gas properties
    200,941       168,868  
                 
Other property and equipment, net
    10,716       3,370  
Restricted investments
    3,750       4,044  
Investment in Medusa Spar LLC
    9,914       10,424  
Other assets, net
    3,395       1,276  
      Total assets
  $ 302,818     $ 218,326  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
               
Current liabilities:
               
  Accounts payable and accrued liabilities
  $ 24,335     $ 17,702  
  Asset retirement obligations
    1,372       2,822  
  Fair market value of derivatives
    -       937  
      Total current liabilities
    25,707       21,461  
                 
13% Senior Notes due 2016
               
   Principal outstanding
    106,961       137,961  
   Deferred credit, net of accumulated amortization of $12,329 and $3,964, respectively
    19,178       27,543  
       Total 13% Senior Notes
    126,139       165,504  
                 
Asset retirement obligations
    12,565       13,103  
Other long-term liabilities
    2,910       2,448  
      Total liabilities
    167,321       202,516  
                 
Stockholders' equity:
               
  Preferred Stock, $.01 par value, 2,500,000 shares authorized;
    -       -  
  Common Stock, $.01 par value, 60,000,000 shares authorized; 39,381,693 and 28,984,125
    shares outstanding at September 30, 2011 and December 31, 2010, respectively
    394       290  
  Capital in excess of par value
    323,693       248,160  
  Other comprehensive income (loss)
    3,027       (8,560 )
  Retained earnings (deficit)
    (191,617 )     (224,080 )
       Total stockholders' equity
    135,497       15,810  
       Total liabilities and stockholders' equity
  $ 302,818     $ 218,326  

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


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

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Operating revenues:
 
 
         
 
       
  Oil sales
  $ 26,537     $ 15,123     $ 74,428     $ 47,687  
  Gas sales
    7,013       5,362       21,404       17,752  
      Total operating revenues
    33,550       20,485       95,832       65,439  
                                 
Operating expenses:
                               
  Lease operating expenses
    5,980       4,327       16,324       13,006  
  Depreciation, depletion and amortization
    13,013       7,392       35,741       21,247  
  General and administrative
    3,464       3,371       11,487       12,086  
  Accretion expense
    569       601       1,767       1,803  
  Acquisition expense
    -       139       -       139  
     Total operating expenses
    23,026       15,830       65,319       48,281  
  Income from operations
    10,524       4,655       30,513       17,158  
                                 
  Other (income) expenses:
                               
  Interest expense
    2,722       3,133       8,912       9,925  
  (Gain) loss on early extinguishment of debt
    -       -       (1,942 )     339  
  Gain on acquired assets (See Note 10)
    -       -       (3,688 )     -  
  Gain on sale of acquired assets
    (217 )     -       (217 )     -  
   Loss on impairment of acquired assets
    171       -       171       -  
  Other (income) expense
    (347 )     63       (599 )     (409 )
     Total other (income) expenses
    2,329       3,196       2,637       9,855  
                                 
  Income before income taxes
    8,195       1,459       27,876       7,303  
  Income tax benefit
    -       -       (3,972 )     -  
  Income before equity in earnings of Medusa Spar LLC
    8,195       1,459       31,848       7,303  
  Equity in earnings of Medusa Spar LLC
    211       143       597       352  
  Net income available to common shares
  $ 8,406     $ 1,602     $ 32,445     $ 7,655  
                                 
  Net income per common share:
                               
    Basic
  $ 0.21     $ 0.06     $ 0.87     $ 0.27  
    Diluted
  $ 0.21     $ 0.05     $ 0.85     $ 0.26  
                                 
  Shares used in computing net income per common share:
                               
    Basic
    39,322       28,815       37,431       28,769  
    Diluted
    39,976       29,491       38,120       29,431  


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


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

   
Nine Months Ended September 30,
 
   
2011
   
2010
 
Cash flows from operating activities:
           
Net income
  $ 32,445     $ 7,655  
Adjustments to reconcile net income to
               
cash provided by operating activities:
               
      Depreciation, depletion and amortization
    36,501       21,860  
      Accretion expense
    1,767       1,803  
      Gain on acquired assets
    (3,688 )     -  
      Amortization of non-cash debt related items
    338       305  
      Amortization of deferred credit
    (2,361 )     (2,723 )
      Non-cash (gain) loss on early extinguishment of debt
    (1,942 )     179  
      Equity in earnings of Medusa Spar LLC
    (597 )     (352 )
      Deferred income tax expense
    10,696       2,455  
      Deferred income tax asset valuation allowance
    (14,668 )     (2,455 )
      Non-cash derivative income due to hedge ineffectiveness
    (189 )     -  
      Non-cash charge related to compensation plans
    1,122       2,356  
      Payments to settle asset retirement obligations
    (2,428 )     (1,211 )
      Changes in current assets and liabilities
               
         Accounts receivable
    (5,280 )     54,593  
         Other current assets
    37       (1,462 )
         Current liabilities
    6,334       (134 )
      Change in gas balancing receivable
    198       370  
      Change in gas balancing payable
    (29 )     (292 )
      Change in other long-term liabilities
    100       (115 )
      Change in other assets, net
    (427 )     (588 )
         Cash provided by operating activities
    57,929       82,244  
                 
Cash flows from investing activities:
               
   Capital expenditures
    (74,388 )     (39,617 )
   Acquisition expenditures
    -       (995 )
   Investment in restricted assets for plugging and abandonment
    (112 )     (337 )
   Proceeds from sale of mineral interest and equipment
    7,559       -  
   Distribution from Medusa Spar LLC
    1,107       1,224  
         Cash used in investing activities
    (65,834 )     (39,725 )
                 
Cash flows from financing activities:
               
   Payments on senior secured credit facility
    -       (10,000 )
   Redemption of remaining 9.75% senior notes
    -       (16,052 )
   Redemption of 13% senior notes
    (35,062 )     -  
   Proceeds from exercise of employee stock options
    -       (41 )
   Issuance of common stock
    73,765       -  
         Cash provided by (used in) financing activities
    38,703       (26,093 )
                 
Net change in cash and cash equivalents
    30,798       16,426  
Cash and cash equivalents:
               
    Balance, beginning of period
    17,436       3,635  
    Less: Cash held by subsidiary deconsolidated at January 1, 2010
    -       (311 )
    Balance, end of period
  $ 48,234     $ 19,750  

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.    Fair Value Measurements
2.    Earnings Per Share
7.     Equity Transactions
3.    Comprehensive Income
8.     Income Taxes
4.    Borrowings
9.     Asset Retirement Obligations
5.    Derivative Instruments and Hedging Activities
10.   Entrada Project Wind-Down

Note 1 - Description of Business and Basis of Presentation

Description of Business

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950.  The 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.

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 Securities 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, 2010. The balance sheet at December 31, 2010 has been derived from the audited financial statements at that date.

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, 2011.

Unless otherwise indicated, 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 - Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share (“EPS”):

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
(a) Net income
  $ 8,406     $ 1,602     $ 32,445     $ 7,655  
                                 
(b) Weighted average shares outstanding
    39,322       28,815       37,431       28,769  
      Dilutive impact of stock options
    16       147       22       127  
      Dilutive impact of restricted stock
    638       529       667       535  
                                 
(c) Weighted average shares outstanding
                               
         for diluted net income per share
    39,976       29,491       38,120       29,431  
                                 
Basic net income per share (a/b)
  $ 0.21     $ 0.06     $ 0.87     $ 0.27  
Diluted net income per share (a/c)
  $ 0.21     $ 0.05     $ 0.85     $ 0.26  
                                 
The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive:
 
                                 
Stock options
    82       122       67       122  
Warrants
    -       365       -       365  
Restricted stock
    766       36       766       36  



Note 3 - Comprehensive Income

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

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Net income
  $ 8,406     $ 1,602     $ 32,445     $ 7,655  
Other comprehensive income:
                               
     Change in fair value of derivatives
    8,337       (860 )     11,587       591  
Total comprehensive income
  $ 16,743     $ 742     $ 44,032     $ 8,246  


 
7

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

Note 4 – Borrowings

The Company’s borrowings consisted of the following at:

 
 
September 30, 2011
   
December 31, 2010
 
Principal components:
           
     Credit Facility
  $ -     $ -  
     13% Senior Notes due 2016, principal
    106,961       137,961  
          Total principal outstanding
    106,961       137,961  
                 
Non-cash components:
               
     13% Senior Notes due 2016 unamortized deferred credit
    19,178       27,543  
          Total carrying value
  $ 126,139     $ 165,504  


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. Amounts borrowed under the Credit Facility may not exceed a borrowing base which is reviewed and re-determined on a semi-annual basis using second and fourth quarter financial results and reserve information available at the time of the redetermination.  During the second quarter of 2011, the lender completed their borrowing base redetermination, which resulted in a 50% increase in the borrowing base from $30,000 at December 31, 2010 to $45,000 at September 30, 2011.  As of September 30, 2011, the interest rate on the facility was 3%, defined in the amended agreement as the London Interbank Offered Rate (“LIBOR”), with a minimum of 0.5%, plus a tiered rate ranging from 2.5% to 3.0%, which is based on the amount drawn on the facility.  In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly.

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

During the fourth quarter of 2009, the Company exchanged approximately 92% of the principal amount, or $183,948, of the Company’s 9.75% Senior Notes (“Old Notes”) for $137,961 of Senior Notes.  The exchange resulted in a 25% reduction in the principal amount of the Old Notes, and included a 3.25% increase in the coupon rate from 9.75% to 13%.  In addition, holders of the tendered notes received an aggregate of 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 into 10 shares of common stock.  The Senior Notes’ 13% interest coupon is payable on the last day of each quarter.  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.

 
8

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


Upon issuing the Senior Notes in 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 $31,507 difference between the adjusted carrying amount of the Old Notes and the principal of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction of 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:
Gross Carrying Amount
   
Accumulated Amortization at September 30, 2011(1)
   
Carrying Value at September 30, 2011
   
Amortization Recorded during 2011 as a Reduction of Interest Expense(1)
   
Estimated Amortization
Expected to be
Recorded during the Remainder of 2011
 
$ 31,507     $ 12,329     $ 19,178     $ 2,361     $ 794  

(1)
Amortization recorded during 2011 excludes $6,004 of accelerated amortization related to the March 2011 early redemption of $31,000 principal of notes discussed below, which is recorded in the Statement of Operations as a component of the “Gain on early extinguishment of debt.”  Accumulated Amortization at September 30, 2011 includes the $6,004 of accelerated amortization.

On March 19, 2011, using a portion of the proceeds from the Company’s February 2011 equity offering discussed in Note 7, the Company redeemed an aggregate principal amount of $31,000 of its Senior Notes with a carrying value of $37,004 including $6,004 of the Notes’ deferred credit, in exchange for $35,062.  The amount paid included the $31,000 principal of the notes, the $4,030 call premium and $32 of redemption expenses, which resulted in a $1,942 net gain on the early extinguishment of debt.

Restrictive Covenants

Both the indenture governing our Senior Notes and the Company’s Credit Facility contain 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 September 30, 2011.

Note 5 - 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 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 speculative 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.
     
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 terminate the arrangement or demand the posting of collateral, which may involve cash, letters of credit or property.


 
9

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


Settlements and Financial Statement Presentation

Settlements of the Company’s oil and gas collar derivative contracts are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (“NYMEX”) price.  The estimated fair value of these collar contracts is based upon closing exchange prices on NYMEX and the time value of options.  See Note 6, “Fair Value Measurements.”

The Company’s derivative contracts 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. 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) and are included in Other (income) expense within the Company’s consolidated statements of operations.

Listed in the table below are the outstanding oil and gas derivative contracts as of September 30, 2011:

Product
Product Type
 
Volumes per Month
 
Quantity Type
 
Average Floor Price per Hedge
   
Average Ceiling Price per Hedge
 
Period
                         
Oil
Collar
    10  
Bbls
  $ 75.00     $ 101.85  
Oct11 - Dec11
Oil
Collar
    5  
Bbls
    80.00       102.00  
Oct11 - Dec11
Oil
Collar
    10  
Bbls
    75.00       94.50  
Oct11 - Dec11
Oil
Collar
    15  
Bbls
    90.00       122.00  
Oct11 - Dec11
Oil
Collar
    25  
Bbls
    90.00       122.00  
Jan12 - Dec12
Oil
Collar
    25  
Bbls
    95.00       125.00  
Jan12 - Dec12

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 for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
Amount of gain (loss) reclassified from OCI into income (effective portion)
  $ 88     $ 124     $ (361 )   $ 364  
Amount of gain recognized in income (ineffective portion and
   amount excluded from effectiveness testing)
    159       -       177       -  

Note 6 - 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. 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 carrying and fair values at:
 
 
 
 
September 30, 2011
   
December 31, 2010
 
   
Carrying Value
   
Fair Value
   
Carrying Value
   
Fair Value
 
                         
13% Senior Notes due 2016 (1)
  $ 126,139     $ 110,170     $ 165,504     $ 140,030  
                                 
(1) Fair value is calculated only in relation to the $106,961 and $137,961 principal outstanding of the 13% Senior Notes at the dates indicated above, respectively.  The remaining $19,178 and $27,543, respectively, which the Company has recorded as a deferred credit, is excluded from the fair value calculation, and will be recognized in earnings as a reduction of interest expense over the remaining amortization period.  See Note 4 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 Sheets. 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.  As disclosed in Note 5, the Company’s hedge portfolio includes only collar contracts.  The fair value of these derivatives is calculated using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities.  The Company believes that these inputs primarily fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts.  For additional information, see Note 5.

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

As of September 30, 2011
Balance Sheet Presentation
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets
                         
Derivative financial instruments - current
Fair market value of derivatives
  $ -     $ 8,338     $ -     $ 8,338  
Derivative financial instruments - non-current
Other assets, net
    -       2,500       -       2,500  
                                   
Liabilities
                                 
Derivative financial instruments - current
Fair market value of derivatives
  $ -     $ -     $ -     $ -  
Derivative financial instruments - non-current
Other long-term liabilities
    -       -       -       -  
Total
    $ -     $ 10,838     $ -     $ 10,838  
                                   
As of December 31, 2010
Balance Sheet Presentation
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets
                                 
Derivative financial instruments - current
Fair market value of derivatives
  $ -     $ -     $ -     $ -  
Derivative financial instruments - non-current
Other assets, net
    -       -       -       -  
                                   
Liabilities
                                 
Derivative financial instruments - current
Fair market value of derivatives
  $ -     $ 937     $ -     $ 937  
Derivative financial instruments - non-current
Other long-term liabilities
    -       -       -       -  
Total
    $ -     $ (937 )   $ -     $ (937 )

The derivative fair values above are based on analysis of each contract. Derivative liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists.

 
11

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


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 (“AROs”) 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 during the three and nine-month periods ended September 30, 2011, including upward revisions of $186 and $405, respectively, were Level 3 fair value measurements.  See Note 9, “Asset Retirement Obligations,” which provides a summary of changes in the ARO liability.

Other Property and Equipment.  During the quarter ended September 30, 2011, the Company determined that certain unsold surplus Entrada equipment with carrying values of $690 had become impaired due to the limited market for these assets and based on discussions with potential buyers.  Consequently, the Company reduced these assets’ carrying value to $348, which represents a Level 3 fair value measurement.  See Note 10 for additional information regarding this equipment.

Note 7 – Equity Transactions

During February 2011, the Company received $73,765 in net proceeds through the public offering of 10,100 shares of its common stock, which included the issuance of 1,100 shares pursuant to the partial exercise of the underwriters’ over-allotment option.  As discussed in Note 4, the Company used a portion of the proceeds to redeem $31,000 principal amount, or 22% of its outstanding Senior Notes.  The remaining proceeds are intended for general corporate purposes including the accelerated development of the Company’s Permian Basin properties and for potential acquisitions.

Note 8 - Income Taxes

The following table presents Callon’s net unrecognized tax benefits relating to its reported net losses and other temporary differences from operations:
   
September 30, 2011
   
December 31, 2010
 
Deferred tax asset:
           
   Federal net operating loss carryforward
  $ 77,432     $ 79,680  
   Statutory depletion carryforward
    7,392       6,140  
   Alternative minimum tax credit carryforward
    209       208  
   Asset retirement obligations
    3,565       4,018  
   Other
    11,078       16,807  
      Deferred tax asset before valuation allowance
    99,676       106,853  
   Less: Valuation allowance
    (68,151 )     (85,222 )
Total deferred tax asset
    31,525       21,631  
Deferred tax liability:
               
   Oil and gas properties
    31,525       21,631  
Total deferred tax liability
    31,525       21,631  
Net deferred tax asset
  $ -     $ -  

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.  The Company considers the scheduled expiration of deferred tax assets, projected future taxable income and tax planning strategies in making this assessment.  Following an impairment of oil and gas properties recorded during the fourth quarter of 2008, the Company remains in a three-year cumulative loss position as of September 30, 2011.  Accordingly, the Company continues to carry a full valuation allowance against its net deferred tax assets, which will affect the Company’s effective tax rate in future periods to the extent these deferred tax assets are recognized.


 
12

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


Note 9 - Asset Retirement Obligations

The following table summarizes the Company’s asset retirement obligations year-to-date activity:

Asset retirement obligations at January 1, 2011
  $ 15,925  
   Accretion expense
    1,767  
   Liabilities incurred
    29  
   Liabilities settled
    (3,109 )
   Revisions to estimate
    (675 )
Asset retirement obligations at end of period
    13,937  
   Less: current asset retirement obligations
    (1,372 )
Long-term asset retirement obligations at September 30, 2011
  $ 12,565  

Liabilities settled relate to properties sold during the period for which the related asset retirement obligations were assumed by the purchaser, and also includes individual properties, primarily located in the Gulf of Mexico, plugged and abandoned during the period.

Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations.  Amounts recorded on the Consolidated Balance Sheets as long-term restricted investments were $3,750 at September 30, 2011.  These investments include primarily U.S. Government securities, and are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and gas properties.

Note 10 – Entrada Project Wind-Down

Effective January 1, 2010, Callon Entrada Company (“CEC”), a variable interest entity, was deconsolidated from the Company’s consolidated financial statements because the Company no longer had the power to direct the activities that most significantly affected CEC’s economic performance, which was the liquidation of the surplus equipment related to the Entrada project.  During May 2011, the Company entered into a final project wind-down agreement (the “Agreement”) with CIECO Energy LLC (“CIECO”), its former joint interest partner in the Entrada deepwater project.  The Agreement, effective as of April 29, 2011, provided for the extinguishment of all existing agreements and commitments between the parties as it related to the past development of the Entrada project.  The Agreement included a formal extinguishment of the non-recourse credit agreement between CEC and CIECO and the assignment to CEC of CIECO’s 50% rights to the remaining assets including primarily the unsold, residual equipment and all engineering data related to the Entrada project.  When combined with CEC’s existing 50% ownership of these assets, this Agreement results in CEC’s full ownership of all remaining assets. Also, as a result of this Agreement, which included both the assignment of the rights to the Entrada assets and the proceeds from the ultimate sale of such assets, the Company gained the power to direct the activities related to the sale of the remaining assets, and therefore became the primary beneficiary of CEC.  Therefore, as Callon became its primary beneficiary, CEC was consolidated in the Company’s consolidated financial statements, effective April 29, 2011.

At June 30, 2011, the Company estimated the fair values of the assets acquired to be $11,349 and liabilities assumed of CEC to be $3,972 as a result of this Agreement. The assets acquired consisted primarily of the Entrada surplus equipment and the liabilities assumed consisted of deferred tax liabilities associated with the basis difference of the equipment.  The total net assets acquired of approximately $7,377 were recorded at June 30, 2011 as a $3,688 gain and $3,689 as an adjustment to the Company’s full cost pool of oil and gas properties.  The gain recognition was required as a result of the Company acquiring CIECO’s former 50% share of the assets and the full cost pool adjustment was required to reflect the Company’s 50% share of the assets held by the Company prior to the deconsolidation of the CEC subsidiary in 2010.  The gain of $3,688 increased the Company’s fully diluted earnings per share by $0.09 and $0.10, respectively, for the three and six months ended June 30, 2011.

With respect to the deferred tax liability, the Company utilized a portion of its deferred tax asset and recognized an income tax benefit equal to $3,972.  During the period from the acquisition date through June 30, 2011, the Company sold certain of the acquired assets for $3,658.  The remaining unsold assets were recorded on the Company’s balance sheet at June 30, 2011 as $296 in Other current assets and $7,395 included in Other property and equipment, net. The Company is actively marketing these assets. Also in connection with this Agreement, CEC agreed to pay to CIECO approximately $438, which represented the net balance of joint interest billings due to CIECO and which had been previously accrued.  The agreement also included joint releases of each party from any further liabilities or obligations to the other party in connection with the Entrada project.

During the quarter ended September 30, 2011, the Company sold Entrada surplus equipment with carrying values of $778 for $1,211.  As discussed above, 50% of the proceeds received in excess of the carrying value of the assets, or $217, were recorded as a gain on sale of assets, while the remaining 50% was recorded as an adjustment to the full cost pool.  Also during the current quarter, the Company determined that certain unsold equipment with carrying values of $690 had become impaired due to the limited market for these assets, and consequently the Company reduced these assets’ carrying value to $348.  The $342 reduction in carrying value was recorded as a $171 loss with the remaining as an adjustment to the Company’s full cost pool.  As of September 30, 2011, the remaining unsold assets had carrying values of $6,570 and are included in the Company’s balance sheet as a component of Other property and equipment, net.


 
13

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


Special Note Regarding Forward Looking Statements

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target,” “may,” “will” or similar expressions.

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

·          the timing and extent of changes in market conditions and prices for commodities (including regional basis differentials);
 
·          our ability to transport our production to the most favorable markets or at all;
 
·          the timing and extent of our success in discovering, developing, producing and estimating reserves;
 
·          our ability to fund our planned capital investments;
 
·          the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic
    fracturing, the climate and over-the-counter derivatives;
 
·          the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services;
 
·          our future property acquisition or divestiture activities;
 
·          the effects of weather;
 
·          increased competition;
 
·          the financial impact of accounting regulations and critical accounting policies;
 
·          the comparative cost of alternative fuels;
 
·          conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed;
 
·          credit risk relating to the risk of loss as a result of non-performance by our counterparties; and
 
·          any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A our Annual Report on Form 10-K for the year ended December 31, 2010 (the “2010 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”).

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties occur as described above or elsewhere in our 2010 Annual Report on Form 10-K or in our 2011 Quarterly Reports on Form 10-Q, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

 
14

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


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 2010 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. When appropriate, the Company also updates 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. In late 2008, our management shifted our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both oil and natural gas basins.  The transition from offshore to onshore has been and is expected to continue to be primarily funded by reinvesting onshore the cash flows from our legacy Gulf of Mexico properties.

Overview and Outlook

For the nine months ended September 30, 2011, we reported net income and fully diluted earnings per share of $32.4 million and $0.85, respectively, compared to net income and diluted earnings per share of $7.7 million and $0.26, respectively for the same period of 2010.  These results are discussed in greater detail within the “Results of Operations” section included below.  Key accomplishments to date in 2011 include:

 
·
Successfully completed a public offering of 10.1 million shares during February 2011 for which the Company received $73.8 million in net proceeds.  While approximately 47% of the proceeds were used to reduce the Company’s debt outstanding, the remaining proceeds will be used for general corporate purposes, to fund the Company’s development of its Permian Basin and other properties and would be available should the Company identify an attractive acquisition opportunity.

 
·
Redeemed during March 2011 $31 million aggregate principal amount of our Senior Notes resulting in a net gain on the early extinguishment of debt of approximately $2.0 million.  This redemption reduced the principal of the Company’s debt outstanding by approximately 22% to $107 million, and will reduce future interest expense by approximately $3.2 million during 2011 and by $4.0 million for each full year through the Senior Notes’ maturity in 2016.

 
·
Increased Credit Facility borrowing base to $45 million, representing a $15 million or 50% increase over the previously approved $30 million borrowing base and simultaneously received a reduction in the Credit Facility’s interest rate from a minimum of 6% to 3%.

 
·
Increased production from our Permian Basin properties.  Production has increased approximately 135% since December 31, 2010 to approximately 1,300 net barrels of oil equivalent per day (“Boe/d”) from 550 Boe/d.

 
·
Executed an Agreement with our former joint interest partner to complete the wind-down of the Company’s previously abandoned deepwater Entrada Project.  Through the Agreement, the Company acquired rights to the remaining, unsold assets from the project.  Upon recording these assets in the Company’s consolidated financial statements, we recognized a gain of $3.7 million and a related income tax benefit of $4.0 million.


 
15

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


Our success in these areas allows us to continue executing on our strategy to shift our operational focus from the offshore Gulf of Mexico to developing longer life, lower risk onshore properties.  Our onshore properties along with the cash flows from our Gulf of Mexico operations have re-shaped our portfolio and outlook, and we believe we are positioned to continue diversifying our portfolio by building profitable growth opportunities onshore.  At December 31, 2010, our onshore properties represented 50% of our proved reserves, and we expect to increase this percentage throughout the remainder of 2011 as we further develop our onshore assets.  Highlights of our onshore and deepwater development program include:

Onshore – Permian Basin

We currently own approximately 9,300 net acres in the Permian Basin, of which approximately 80% is prospective for the Wolfberry play.  We operate substantially all of the production and development of these Permian assets, which are located in Crockett, Ector, Midland and Upton Counties, Texas.  As of December 31, 2010, the properties included an estimated 4.5 million barrels of oil equivalent (“MMBoe”) of proved reserves. As of September 30, 2011 and compared to December 31, 2010, production from these properties has increased over 135% to approximately 1,300 net Boe/d from 59 gross wells compared to production of 550 net Boe/d from 33 gross wells.  As of September 30, 2011, the acreage has the remaining potential for an approximate 127 additional net wells based on 40-acre spacing.  

During the first nine months of 2011, we fracture stimulated and placed on production 29 wells and have 8 wells awaiting fracture stimulation services.  We also drilled 25 wells during the first nine months of 2011 at a total cost, including fracture stimulation, other completion and facility costs, of approximately $61.8 million.  While the majority of these costs were included in our 2011 capital expenditures budget, certain costs have exceeded our expectations by approximately $6 million during the first nine months of 2011 and include items such as drilling a portion of our wells deeper to the Atoka and Strawn formations.   While production results achieved from the Atoka completion declined to the point that we are no longer drilling through this formation, we are encouraged with the early results from the Strawn such that most completions now include a fracture stimulation in the Strawn.  Also exceeding our original development cost expectations are higher costs related to increased demand for materials and services in the basin, the costs associated with various down-hole drilling difficulties and other similar development costs.  For example, drilling rig rates have increased 34% due to increased labor costs to maintain crew continuity, and fracture stimulation services and associated wireline services have increased approximately 13% over the first nine months of 2011.  We continue to monitor these trends and, to the extent possible, negotiate favorable pricing based on any leverage we possess, such as negotiating volume discounts.  We also continue to monitor drilling rig operator efficiency, and have replaced one operator with another that we believe will improve drilling efficiency.
We now expect to drill approximately 36 total gross wells in 2011, down from 41 previously estimated wells due primarily to drilling wells deeper through the Atoka to define deeper potential within the Wolfberry interval and increasing costs pressures.  We expect to fracture stimulate approximately an additional 11 wells during the fourth quarter of 2011 under our fracture stimulation service agreement.

Onshore – Haynesville Shale

We own a 69% working interest in a 624-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana.   Our multi-year development plan for this property includes drilling and operating a total of seven horizontal wells, the first of which was placed on production in September 2010.  As of September 30, 2011, this well was producing 3,400 thousand cubic feet of natural gas equivalent per day.  We have no drilling obligations in our Haynesville Shale position, and currently plan to mobilize a rig to the area once natural gas prices warrant continued development of the remaining six planned gross horizontal wells.

Deepwater Mississippi Canyon Blocks 538/582 (“Medusa”) and Garden Banks Block 341 (“Habanero”)

Our deepwater, legacy properties continue to play a key role in our transition to onshore operations by providing strong cash flows used to fund the development of our onshore properties.  Together, our two deepwater properties have produced approximately 645 MBoe equal to nearly 50% of the Company’s total year-to-date production in 2011.  Most of our Medusa’s eight wells continue to produce from their initial completions and, as of December 31, 2010, had 2.4 MMBoe of proved developed non-producing reserves that will be accessed by recompletions in the existing wells.  Another 1.2 MMBoe of proved undeveloped reserves will be developed by side tracking an existing well.  On March 29, 2011, the operator of our Medusa property successfully recompleted at a net cost to Callon of $0.2 million the A6 well from the T4-C zone to the T4-B zone, which increased production net to Callon from approximately 80 Boe/day to approximately 850 Boe/day.  As of September 30, 2011, production from the A6 well was approximately 500 Boe/day, net.  Production from our deepwater properties is approximately 85% oil, which in the present market offers favorable pricing in relation to gas.

While we are proud of the portfolio of assets we have built, we remain committed to strategic, onshore growth through attractive property acquisitions.  To this end, we have been actively evaluating various opportunities.


 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
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.  Cash and cash equivalents increased by approximately $30.8 million during the nine month period ended September 30, 2011 to $48.2 million compared to $17.4 million at December 31, 2010.  The increase in liquidity is primarily attributable to higher commodity oil prices, increased production levels and the receipt of $73.8 million from the previously discussed equity offering of 10.1 million shares of common stock offset by approximately $35 million used to repurchase $31 million principal amount of our outstanding Senior Notes and by the use of cash for ongoing operations, including capital expenditures.

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 (“the Credit Facility”) matures on September 25, 2012, and provides for a $100 million facility with a current borrowing base of $45 million as approved by Regions Bank in May 2011.  The current borrowing base represents a $15 million, or 50%, increase over the previous $30 million borrowing base as of December 31, 2010.  Simultaneous with the May 2011 increase in the borrowing base, Regions Bank also approved a reduction in the interest rate on the facility from the previous floor of 6% to 3%.  The rate is calculated as LIBOR, with a minimum of 0.5%, plus a tiered rate ranging from 2.5% to 3.0%, which is based on the amount drawn on the facility.  In addition, the Credit Facility, which continues to carry a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly.  As of September 30, 2011, the interest rate on the facility was 3%, though no amounts were outstanding under the amended facility as of September 30, 2011.  We are in discussions with Regions Bank to syndicate this facility, which is expected to include an extension of the maturity beyond the September 25, 2012 date noted above.  Similarly, we expect that reserves growth related to our accelerated development of our Permian Basin properties could result in an additional increase in the borrowing base at syndication.

At September 30, 2011, we had approximately $107.0 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly, a $31 million decrease from amounts outstanding at December 31, 2010 following the partial redemption previously discussed.  The principal reduction in our Senior Notes will reduce 2011 cash interest paid by approximately $3.2 million and each full-year thereafter by approximately $4.0 million.

2011 Budget and Capital Expenditures.  For 2011, we designed a flexible capital expenditures spending program that can be funded from cash on hand, inclusive of the proceeds received from the previously discussed equity offering, and cash flows from operations.  This budget projects approximately $107 million of capital expenditures and is primarily focused on the accelerated development of our Permian Basin oil properties including completion costs and the drilling of an estimated 36 wells.  Despite the previously discussed $6 million increase in Permian related capital expenditures, the overall budget is expected to remain at the current projected level or slightly under.  This budget also includes all anticipated plugging and abandonment, capitalized interest and certain overhead costs related to acquiring, exploring and developing oil and gas properties. 

In addition to cash on hand, should we identify an attractive strategic opportunity or acquisition, we currently have $45 million of borrowing capacity available under our Credit Facility.  We believe that our cash on hand and operating cash flows along with our Credit Facility, if needed, will be adequate to meet our capital, interest payments, and operating requirements for 2011.


 
17

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


Summary cash flow information is provided as follows:

Operating Activities.  For the nine-months ended September 30, 2011, net cash provided by operating activities was $57.9 million, compared to $82.2 million for the same period in 2010.  Cash flows from operations in the first nine months of 2010 included a $44.8 million recoupment of royalties paid to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”; formerly the Minerals Management Service), and related interest of $7.9 million.  Excluding this $52.7 million related to the BOEMRE royalty recoupment, cash flow provided by operating activities increased period-over-period by approximately 96% or $28.4 million primarily as a result of a 25% increase in the average realized sales price on an equivalent basis and a 17% increase in total production on an equivalent basis.

Investing Activities.  For the nine months ended September 30, 2011, net cash used in investing activities was $65.8 million as compared to $39.7 million for the same period in 2010. The $26.1 million increase in net cash used in investing activities is primarily attributable to an increase in capital expenditure spending, and relates to drilling activity on our Permian Basin acreage, which was partially offset by $7.6 million in proceeds received for the sale of certain mineral interests and assets acquired as part of the Entrada project wind-down agreement discussed below and in Note 10 of Part 1, Item 1 of this report.

Financing Activities.  For the nine months ended September 30, 2011, net cash provided by financing activities was $38.7 million compared to cash used by financing activities of $26.1 million during the same period of 2010.  The 2011 net cash provided by financing activities included $73.8 million of net proceeds from an equity offering offset by approximately $35.1 million used to redeem a $31.0 million principal portion of our outstanding Senior Notes and to pay the $4.0 million call premium and other redemption expenses.  The 2010 expenditures related to the $10.0 million repayment of outstanding borrowings under the Credit Facility and the $16.0 million redemption of the Company’s remaining outstanding 9.75% Senior Notes.

Income Taxes

As a result of the impairment of oil and gas properties recorded in the fourth quarter of 2008, we incurred losses on an aggregate basis for the three-year period ended December 31, 2008.  At the time of this impairment, we also established a full valuation allowance against our deferred tax asset at the end of that year because, based on the relevant accounting rules, it was more likely than not that we would be unable to utilize our deferred tax assets.  During the current quarter, and consistent with previous profitable periods, we recognized no income tax expense by applying a portion of our net operating losses against current income, and simultaneously reversed a portion of the deferred tax valuation allowance equal to this benefit. As a result, we recognized no income tax expense in the income statement for the past two years as we continue to utilize our deferred tax assets to offset taxable income. We have reported earnings in 2009, 2010 and expect to have earnings for the full year of 2011. Based on our recent profitable operations, we have evaluated whether it is more likely than not that we will be able to utilize our deferred tax assets and, as of September 30, 2011, we concluded that we should not reverse all or a portion of our valuation allowance.  At September 30, 2011, our net deferred tax asset was $68.2 million.  We will continue to evaluate this conclusion as of December 31, 2011 when we have our year-end reserve report and have finalized our projections for 2012 and beyond.


 
18

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


Entrada Project Wind-down Agreement

Effective January 1, 2010, Callon Entrada Company (“CEC”), a variable interest entity, was deconsolidated from our consolidated financial statements because we no longer had the power to direct the activities that most significantly affected CEC’s economic performance, which was the liquidation of the surplus equipment related to the Entrada project.  During the second quarter of 2011, we entered into a final project wind-down agreement (the Agreement) with CIECO Energy LLC (“CIECO”), our former joint interest partner in the Entrada deepwater project.  The Agreement provides for the extinguishment of all existing agreements and commitments between the parties as it relates to the past development of the Entrada project.  The Agreement included a formal extinguishment of the non-recourse credit agreement between CEC and CIECO and the assignment to CEC of CIECO’s 50% rights to the remaining assets including primarily the unsold, residual equipment and all engineering data related to the Entrada project.  When combined with CEC’s existing 50% ownership of these assets, this Agreement results in CEC’s full ownership of all remaining assets. Also, as a result of this Agreement, which included both the assignment of the rights to the Entrada assets and the proceeds from the ultimate sale of such assets, we gained the power to direct the activities related to the sale of the remaining assets, and therefore became the primary beneficiary of CEC.  Therefore, as we became its primary beneficiary, CEC was included in our consolidated financial statements, effective April 29, 2011.

As discussed in Note 6, at June 30, 2011, we estimated the fair values of the assets acquired to be $11.4 million and liabilities assumed of CEC to be $4.0 million as a result of this Agreement. The assets acquired consisted primarily of the Entrada surplus equipment and the liabilities assumed consisted of deferred tax liabilities associated with the basis difference of the equipment.  The total net assets acquired of approximately $7.4 million were recorded at June 30, 2011 as a $3.7 million gain and $3.7 million as an adjustment to our full cost pool of oil and gas properties.  The gain recognition was required as a result of our acquiring CIECO’s former 50% share of the assets, and the full cost pool adjustment was required to reflect the 50% share of the assets we held prior to the deconsolidation of the CEC subsidiary in 2010.  The gain of $3.7 million increased our fully diluted earnings per share by $0.09 and $0.10, respectively for the three and six months ended June 30, 2011.

With respect to the deferred tax liability, we utilized a portion of our deferred tax asset and recognized an income tax benefit equal to $4.0 million.  During the period from the acquisition date through June 30, 2011, we sold certain of the acquired assets for $3.7 million.  The remaining unsold assets are recorded on our balance sheet as $0.3 million in Other current assets and $7.7 million included in Other property and equipment, net. We are actively marketing these assets. Also in connection with this Agreement, CEC agreed to pay to CIECO approximately $0.4 million, which represented the net balance of joint interest billings due to CIECO and which had been previously accrued.  The agreement also included joint releases of each party from any further liabilities or obligations to the other party in connection with the Entrada project.

During the quarter ended September 30, 2011, the Company sold Entrada surplus equipment with carrying values of $0.8 million for $1.2 million.  As discussed above, 50% of the proceeds received in excess of the carrying value of the assets, or $0.2 million, were recorded as a gain on sale of assets, while the remaining 50% was recorded as an adjustment to the full cost pool.  Also during the current quarter, the Company determined that certain unsold equipment with carrying values of $0.7 million had become impaired due to the limited market for these assets, and consequently the Company reduced these assets’ carrying value to $0.4 million.  The $0.3 million reduction in carrying value was recorded as a $0.2 million loss with the remaining as an adjustment to the Company’s full cost pool.  As of September 30, 2011, the remaining unsold assets had carrying values of $6.6 million and are included in the Company’s balance sheet as a component of Other property and equipment, net.
 
 

 
19

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

Results of Operations

The following table set forth certain unaudited operating information with respect to the Company's oil and gas operations for the period indicated:

   
Three Months Ended September 30,
 
   
2011
   
2010
   
Change
   
% Change
 
Net production:
                       
  Oil (MBbls)
    270       209       61       29 %
  Gas (MMcf)
    1,284       1,107       177       16 %
  Total production (Mboe)
    484       393       91       23 %
  Average daily production (Boe)
    5,261       4,274       987       23 %
                                 
Average realized sales price (a):
                               
  Oil (Bbl)
  $ 98.27     $ 72.47     $ 25.80       36 %
  Gas (Mcf)
    5.46       4.84       0.62       13 %
  Total (Boe)
    69.31       52.10       17.21       33 %
                                 
Oil and gas revenues (in thousands):
                               
  Oil revenue
  $ 26,537     $ 15,123     $ 11,414       76 %
  Gas revenue
    7,013       5,362       1,651       31 %
  Total
  $ 33,550     $ 20,485     $ 13,065       64 %
                                 
Additional per Boe data:
                               
  Sales price
  $ 69.31     $ 52.10     $ 17.21       33 %
  Lease operating expense
    (12.35 )     (11.00 )     (1.35 )     (12 ) %
  Operating margin
  $ 56.96     $ 41.10     $ 15.86       39 %
                                 
Other expenses per Boe:
                               
  Depletion, depreciation and amortization
  $ 26.88     $ 18.80     $ 8.08       43 %
  General and administrative
  $ 7.16     $ 8.57     $ (1.41 )     (16 )%
                                 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:
 
                                 
Average NYMEX price per barrel of oil
  $ 89.78     $ 76.23     $ 13.55       18 %
  Basis differential and quality adjustments
    9.10       (2.62 )     11.72    
nm
 
  Transportation
    (0.94 )     (1.14 )     0.20       (18 )%
  Hedging
    0.33       -       0.33       100 %
Average realized price per barrel of oil
  $ 98.27     $ 72.47     $ 25.80       36 %
                                 
Average NYMEX price per Mcf of natural gas
  $ 4.29     $ 4.24       0.05       1 %
  Basis differential and quality adjustments
    1.17       0.49       0.68       139 %
  Hedging
    -       0.11       (0.11 )     100 %
Average realized price per Mcf of natural gas
  $ 5.46     $ 4.84     $ 0.62       13 %
                                 
nm – Not Meaningful
                               

   

 
20

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

The following table set forth certain unaudited operating information with respect to the Company's oil and gas operations for the period indicated:

   
Nine Months Ended September 30,
 
   
2011
   
2010
   
Change
   
% Change
 
Net production:
                       
  Oil (MBbls)
    746       646       100       15 %
  Gas (MMcf)
    4,014       3,359       655       19 %
  Total production (Mboe)
    1,415       1,206       209       17 %
  Average daily production (Boe)
    5,182       4,417       765       17 %
                                 
Average realized sales price (a):
                               
  Oil (Bbl)
  $ 99.82     $ 73.78     $ 26.04       35 %
  Gas (Mcf)
    5.33       5.29       0.04       1 %
  Total (Boe)
    67.75       54.27       13.48       25 %
                                 
Oil and gas revenues (in thousands):
                               
  Oil revenue
  $ 74,428     $ 47,687     $ 26,741       56 %
  Gas revenue
    21,404       17,752       3,652       21 %
  Total
  $ 95,832     $ 65,439     $ 30,393       46 %
                                 
Additional per Boe data:
                               
  Sales price
  $ 67.75     $ 54.27     $ 13.48       25 %
  Lease operating expense
    (11.54 )     (10.79 )     (0.75 )     (7 ) %
  Operating margin
  $ 56.21     $ 43.48     $ 12.73       29 %
                                 
Other expenses per Boe:
                               
  Depletion, depreciation and amortization
  $ 25.27     $ 17.62     $ 7.65       43 %
  General and administrative
  $ 8.12     $ 10.02     $ (1.90 )     (19 )%
                                 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:
 
                                 
Average NYMEX price per barrel of oil
  $ 95.48     $ 77.65     $ 17.83       23 %
  Basis differential and quality adjustments
    5.84       (2.70 )     8.54    
nm
 
  Transportation
    (1.02 )     (1.18 )     0.16       (14 )%
  Hedging
    (0.48 )     0.01       (0.49 )  
nm
 
Average realized price per barrel of oil
  $ 99.82     $ 73.78     $ 26.04       35 %
                                 
Average NYMEX price per Mcf of natural gas
  $ 4.29     $ 4.54     $ (0.25 )     (6 )%
  Basis differential and quality adjustments
    1.04       0.64       0.40       63 %
  Hedging
    -       0.11       (0.11 )     (100 )%
Average realized price per Mcf of natural gas
  $ 5.33     $ 5.29     $ 0.04       1 %
                                 
nm – Not Meaningful
                               

 
21

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


Revenues

The following table is intended to reconcile the change in crude oil, natural gas and total revenue for the respective periods presented 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
                 
                   
   
Crude Oil
   
Natural Gas
   
Total
 
                   
Revenues for the three months ended September 30, 2009
  $ 16,451     $ 4,869     $ 21,320  
                         
Volume increase (decrease)
    947       (833 )     114  
Price increase (decrease)
    (2,275 )     1,202       (1,073 )
Impact of hedges increase
    -       124       124  
Net increase (decrease) in 2010
    (1,328 )     493       (835 )
                         
Revenues for the three months ended September 30, 2010
  $ 15,123     $ 5,362     $ 20,485  
                         
Volume increase
    4,448       856       5,304  
Price increase
    6,878       795       7,673  
Impact of hedges increase
    88       -       88  
Net increase in 2011
    11,414       1,651       13,065  
                         
Revenues for the three months ended September 30, 2011
  $ 26,537     $ 7,013     $ 33,550  
 
 
Changes in Oil and Gas Production Revenues
                 
                   
   
Crude Oil
   
Natural Gas
   
Total
 
                   
Revenues for the nine months ended September 30, 2009
  $ 51,374     $ 19,786     $ 71,160  
                         
Volume increase (decrease)
    (5,465 )     (4,023 )     (9,488 )
Price increase (decrease)
    1,769       1,634       3,403  
Impact of hedges increase
    9       355       364  
Net increase (decrease) in 2010
    (3,687 )     (2,034 )     (5,721 )
                         
Revenues for the nine months ended September 30, 2010
  $ 47,687     $ 17,752     $ 65,439  
                         
Volume increase (decrease)
    7,327       3,461       10,788  
Price increase (decrease)
    19,775       191       19,966  
Impact of hedges increase (decrease)
    (361 )     -       (361 )
Net increase (decrease) in 2011
    26,741       3,652       30,393  
                         
Revenues for the nine months ended September 30, 2011
  $ 74,428     $ 21,404     $ 95,832  

 
22

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


Total Revenue

Total oil and gas revenues of $33.6 million for the three months ended September 30, 2011 increased approximately $13.1 million or 64% from $20.5 million during the same period of 2010 principally driven by an increase in pricing on an equivalent unit basis combined with an increase in overall production.  Compared to the third quarter of 2010, and on an equivalent basis, the average price realized by the Company increased 33%, while overall production on an equivalent basis increased by 23%.  Production increases were primarily attributable to the Company’s accelerated development program in its Permian Basin properties, the addition of the Company’s Haynesville Shale gas well which began producing late in the third quarter of 2010 and due to a well recompletion at its Medusa offshore property.  While year-over-year production increased 23%, production during the current quarter was negatively affected by the shut-in of our Medusa and Habanero wells due to Tropical Storm Lee and due to other required maintenance work on the facilities.  Combined, these events reduced current period production by approximately 25 MBoe.  Also offsetting the increases in production discussed above are the normal and expected declines in other legacy properties.

For the nine months ended September 30, 2011, total oil and gas revenues of $95.8 million increased approximately $30.4 million or 46% from $65.4 million for the same period of 2010.  Compared to the first nine months of 2010 and despite the shut-in of our Medusa and Habanero wells discussed above, total production on an equivalent basis increased by 17%, for the same reasons cited above, while the average realized price per Boe also increased by 25%.

Oil Revenue

Oil revenues increased $11.4 million or 76% to $26.5 million for the three months ended September 30, 2011 compared to revenues of $15.1 million for the same period of 2010.  As noted above in conjunction with the overall increase in total revenue, both an increase in commodity prices and production resulted in the increase in oil revenue.   The average price realized increased 36% to $98.27 per barrel compared to $72.47 for the same period of 2010.  Similarly, production levels, for the reasons previously discussed, increased 29% to 270 thousand barrels (“MBbls”) compared to 209 MBbls during the same period in 2010.

For the nine months ended September 30, 2011, oil revenues increased $26.7 million or 56% to $74.4 million compared to revenues of $47.7 million for the same period of 2010.  As previously mentioned, increases in both commodity prices and production contributed to the increase in revenue.  The average price realized increased 35% to $99.82 per barrel compared to $73.78 for the same period of 2010.  Similarly, production increased 15% to 746 MBbls compared to 646 MBbls during the same period in 2010.


Gas Revenue

Gas revenues of $7.0 million for the three months ended September 30, 2011 increased 31% or $1.6 million compared to gas revenues of $5.4 million for the same period of 2010.  Gas production increased 16% period-over-period, primarily driven by production from our Haynesville Shale gas well, which was placed on production during September 2010, and due to the production from East Cameron #2 well, which was shut-in during the first quarter of 2010 for repairs to the host facility and did not return to production until December 2010.  In addition to production increases, the average realized price increased 13% to $5.46 per thousand cubic feet of natural gas (“Mcf”) compared to an average realized price of $4.84 per Mcf for the corresponding period in 2010.

For the nine months ended September 30, 2011, gas revenues of $21.4 million increased 21% or $3.7 million when compared to gas revenues of $17.8 million for the same period of 2010.  The largest contributor to the period-over-period increase was a 19% increase in production, the drivers of which are discussed above and a 1% period-over-period increase in the average realized gas sales price.


 
23

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


Expenses
   
Three Months Ended September 30,
 
   
2011
   
Per Boe
   
2010
   
Per Boe
   
Year $ Change
   
Year % Change
   
Boe $ Change
   
Boe % Change
 
Lease operating expenses
  $ 5,980     $ 12.35     $ 4,327     $ 11.00     $ 1,653       38 %   $ 1.35       12 %
Depreciation, depletion and amortization
    13,013       26.88       7,392       18.80       5,621       76 %     8.08       43 %
General and administrative
    3,464       7.16       3,371       8.57       93       3 %     (1.41 )     (16 )%
Accretion expense
    569       1.18       601       1.53       (32 )     (5 )%     (0.35 )     (23 )%

   
Nine Months Ended September 30,
 
   
2011
   
Per Boe
   
2010
   
Per Boe
   
Year $ Change
   
Year % Change
   
Boe $ Change
   
Boe % Change
 
Lease operating expenses
  $ 16,324     $ 11.54     $ 13,006     $ 10.79     $ 3,318       26 %   $ 0.75       7 %
Depreciation, depletion and amortization
    35,741       25.27       21,247       17.62       14,494       68 %     7.65       43 %
General and administrative
    11,487       8.12       12,086       10.02       (599 )     (5 )%     (1.90 )     (19 )%
Accretion expense
    1,767       1.25       1,803       1.50       (36 )     (2 )%     (0.25 )     (17 )%

Lease Operating Expenses

For the three months ended September 30, 2011, lease operating expenses (“LOE”) of $6.0 million increased by 38% or $1.7 million compared to $4.3 million for the same period in 2010.  The significant growth in the number of wells now producing in our Permian Basin properties and the Haynesville Shale well that was placed on production in September of 2010 together increased LOE approximately $1.2 million compared to the corresponding period of 2010.  Additionally, LOE increased approximately $0.3 million related to both increased production from our Medusa A6 well following the previously discussed well recompletion and due to LOE at our East Cameron #2 well, which was shut-in for repairs on the host facility during the first quarter of 2010 and returned to production during December 2010.  The remaining $0.2 million increase in LOE is attributable to higher severance taxes partially offset by a mix of lower LOE related primarily to our shelf properties.

For the nine months ended September 30, 2011, LOE of $16.3 million increased by 26% or $3.3 million compared to $13.0 million for the same period in 2010.  As discussed above, the significant growth in the number of wells now producing in our Permian Basin properties and our Haynesville Shale well increased LOE approximately $2.9 million compared to the corresponding period of 2010.  Additionally, LOE increased approximately $0.5 million related to platform maintenance work at Medusa and the increased production from the Medusa A6 well following the previously discussed well recompletion, and also increased $0.4 million due to LOE at our East Cameron #2 well discussed above. Offsetting these increases was a mix of lower LOE related primarily to our shelf properties.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) for the three months ended September 30, 2011 increased 43% per Boe to $26.88 per Boe compared to $18.80 per Boe for the same period of 2010.  Similarly, DD&A for the nine months ended September 30, 2011 increased 43% per Boe to $25.27 per Boe compared to $17.62 per Boe for the same period of 2010.  As we began developing our onshore properties and in-line with our expectations, our per-unit DD&A rate began to normalize itself and increase in comparison to prior period DD&A rates, which were effectively reduced by the impact of a $486 million 2008 impairment charge following the then annual ceiling test.  This significant oil and gas property impairment charge resulted in a lower, prospective DD&A rate for the then existing reserves.  Also contributing to the current rate increase, and as previously discussed above related to the development of our Permian basin properties, onshore development cost pressures have exceeded our original estimates.

General and Administrative

For the three months ended September 30, 2011, general and administrative (“G&A”) expenses of $3.5 million, net of amounts capitalized, was relatively flat compared to $3.4 million for the same period of 2010.  For the nine months ended September 30, 2011, G&A expenses of $11.5 million, net of amounts capitalized, decreased 5% or $0.6 million compared to $12.1 million for the same period of 2010.  Reduced legal expenses and lower employee-related costs were the primary drivers of the decrease.

Accretion Expense

Accretion expense related to our asset retirement obligation decreased 5% and 2% for the three and nine months ended September 30, 2011, respectively, compared to the same periods of 2010.  Accretion expense correlates directionally with the Company’s asset retirement obligation (“ARO”).    At September 30, 2011, our asset retirement obligation of $13.9 million was lower than the $14.9 million ARO at September 30, 2010.  See Note 9 for additional information regarding the Company’s ARO.
 
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)

Other Income and Expenses
   
Three Months Ended September 30,
 
   
2011
   
2010
   
$ Change
   
% Change
 
Interest expense
  $ 2,722     $ 3,133     $ (411 )     (13 )%
Gain on acquired assets
    (46 )     -       (46 )     100 %
Other (income) expense
    (347 )     63       (410