Annual report pursuant to Section 13 and 15(d)

Summary of Significant Accounting Policies

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Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2011
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

A.
Use of Estimates

The preparation of financial statements in conformity with United States generally accepted accounting principles (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

B.
Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

C.
Accounts Receivable

Accounts receivable consists primarily of accrued oil and natural gas production receivables.  The balance in the reserve for doubtful accounts netted within accounts receivable was $36 and $339 at December 31, 2011 and 2010, respectively.  During 2011, 2010, and 2009 the Company recorded $(281), $281 and $0, respectively of bad debt expense in general and administrative expenses. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt during 2010.

D.
Revenue Recognition and Natural Gas Balancing

The Company recognizes revenue under the entitlement method of accounting.  Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes.  Production imbalances are generally recorded at the lower of cost or market.  The revenue we receive from the sale of natural gas liquids is included in natural gas sales. Natural gas balancing receivables were $144 and $396 as of December 31, 2011 and 2010, respectively.  Natural gas balancing payables were $756 and $870 as of December 31, 2011 and 2010, respectively.
 
E.
Major Customers

The Company’s production is generally sold on month-to-month contracts at prevailing prices.  The following table identifies customers to whom it sold a significant percentage of its total oil and natural gas production during each of the years ended:
 
December 31,
 
2011
 
2010
 
2009
Shell Trading Company
45
%
 
44
%
 
45
%
Plains Marketing, L.P.
17
%
 
20
%
 
23
%
Enterprise Crude Oil, LLC
16
%
 
%
 
%
Louis Dreyfus Energy Services
4
%
 
13
%
 
15
%
Other
18
%
 
23
%
 
17
%
Total
100
%
 
100
%
 
100
%

Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production.

F.
Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its exploration and development activities.  Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment.  Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance.  Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities.  The Company capitalized $11,857, $11,829  and $10,107  of these internal costs during 2011, 2010 and 2009, respectively.

When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities are sold, in which case a gain or loss is recognized in income.

Costs of oil and natural gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves.  Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs.  Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired.

 
Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at 10%) future net cash flows from proved reserves, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Historically, estimated future net cash flows from proved reserves were calculated based on period-end hedge adjusted commodity prices, and the impact of price increases subsequent to the period end could be considered. In December 2008, the Securities and Exchange Commission (“SEC”) issued a final rule, “Modernization of Oil and Gas Reporting,” which adopted revisions to the SEC’s oil and gas reporting requirements. The revisions, which became effective for the Company’s financial statements as of December 31, 2009, replaced the single-day year-end pricing with a twelve-month average pricing assumption. Additionally, consideration of the impact of subsequent price increases after period end is no longer allowed. The changes to prices used in the reserves calculation under the new rule are used in both disclosures and accounting impairment tests. In January 2010, the Financial Accounting Standards Board (“FASB”) issued its final standard on oil and gas reserve estimation and disclosures aligning its requirements with the SEC’s final rule. The new rules were considered a change in accounting principle that is inseparable from a change in accounting estimate, which did not require retroactive revision. See Note 13 for additional information regarding the Company’s oil and natural gas properties.

Upon the acquisition or discovery of oil and natural gas properties, the Company estimates by using available geological, engineering and regulatory data the future net costs to dismantle, abandon and restore the property.  Such cost estimates are periodically updated for changes in conditions and requirements.  In accordance with asset retirement obligation guidance issued by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred.  In accordance with SEC's rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full-cost ceiling limitation.  The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount.

G.
Amendments to Oil and Natural Gas Reserves Estimation and Disclosure Requirements

In December 2008 the SEC approved amendments to its oil and gas reserves estimation and disclosure requirements.  The amendments, among other things:

allow the use of reliable technologies to estimate proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes;
require disclosure of oil and gas proved reserves by significant geographic area;
permit the optional disclosure of probable and possible reserves;
modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average beginning-of-the-month price instead of a period-end price; and
require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party.

Additionally, during January 2010, the FASB issued accounting guidance to align the reserve calculation and disclosure requirements of US GAAP with the new SEC oil and gas reserve estimation and disclosure rules.  The Company adopted the new requirements effective for its year-end financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009.  The adoption had no material impact on the Company’s financial statements.

H.
Other Property and Equipment

The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years.  Depreciation expense of $645, $446 and $423 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009, respectively.  The accumulated depreciation on other property and equipment was $12,688 and $12,047 as of December 31, 2011 and 2010, respectively.

I.
Asset Retirement Obligations

The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations.  See Note 14 for additional information.

J.
Derivatives

Settlements of oil and natural 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 natural 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.  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 natural gas sales.  Both changes in fair value and cash settlements of ineffective derivative contracts are recognized as derivative expense (income).  See Notes 7 and 8 for additional information.

K.
Income Taxes

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes.  US GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance.  A valuation allowance is provided for that portion of the asset for which it is deemed more likely than not will not be realized. See Note 12 for additional information.

L.
Share-Based Compensation

The Company grants to directors and employees stock options, restricted stock awards ("RS awards"), restricted stock unit awards ("RSU awards") that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash RSU awards”).

Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years).

RS awards, RSU awards and Cash RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as Accounts payable and accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as Other long-term liabilities.

M.
Statements of Cash Flows

During the three year period ended December 31, 2011, the Company paid no federal income taxes. During the years ended December 31, 2011, 2010 and 2009, the company made cash interest payments of $14,922, $18,579 and $19,811, respectively.

N.
Off-Balance Sheet Investment in Medusa Spar LLC

The Company holds a 10% ownership interest in Medusa Spar LLC (“LLC”), which is accounted for under the equity method of accounting for investments.  The LLC owns a 75% undivided ownership interest in the deepwater spar production facilities at the Company’s Medusa Field in the Gulf of Mexico. The LLC earns a tariff based upon production volume throughput from the Medusa area. Callon is obligated to process through the spar production facilities its share of production from the Medusa Field and any future discoveries in the area.  The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation.

O.
Consolidation of Variable Interest Entities

In June 2009, the FASB issued an accounting standard which became effective for the Company on January 1, 2010, 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, and as discussed in Note 3, the Company reevaluated its interest in its subsidiary, Callon Entrada.  Based on the evaluation performed, management 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 beneficiary.  Therefore, effective January 1, 2010, Callon Entrada was deconsolidated from the consolidated financial statements of the Company.   During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company's financial statements. For additional information, see Note 3.

P.
Earnings per Share ("EPS")

The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period.  Diluted EPS reflects the potential dilution, using the treasury-stock method, which assumes that options were exercised and restricted stock was fully vested.  Diluted EPS also includes the impact of unvested share appreciation plans.  For awards in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury-stock method.  For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in the diluted EPS is based on the number of shares, if any, using the treasury-stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan.

Q.
Treasury Stock

The Company applies the weighted-average-cost method of accounting for treasury stock transactions and held 29 treasury shares as of December 31, 2011.

R.
Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.

Presentation of Comprehensive Income

In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05). The guidance eliminates the option of presenting components of other comprehensive income as part of the statement of stockholders’ equity. The standard will allow the Company the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB issued Comprehensive Income (Topic 220) — Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (ASU No. 2011-12). The FASB indefinitely deferred the effective date for the guidance related to the presentation of reclassifications of items out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. The standard, except for the portion that was indefinitely deferred, is effective for the Company on January 1, 2012, and must be applied retrospectively. The Company is evaluating the effects of this standard on disclosure, but it will not impact the Company’s results of operations, financial position or cash flows.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs

In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU No. 2011-04). The standard generally clarifies the application of existing requirements on topics including the concepts of highest and best use and valuation premise and disclosing quantitative information about the unobservable inputs used in the measurement of instruments categorized within Level 3 of the fair value hierarchy. Additionally, the standard includes changes on topics such as measuring fair value of financial instruments that are managed within a portfolio and additional disclosure for fair value measurements categorized within Level 3 of the fair value hierarchy. This standard is effective for the Company on January 1, 2012. The standard will require additional disclosures, but it will not impact the Company’s results of operations, financial position or cash flows.

Balance Sheet Offsetting

In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which updates the Codification to require disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. These updates to the disclosure requirements of the Codification do not affect the presentation of amounts in the balance sheet, and are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those periods. The Company does not expect the implementation of this disclosure guidance to have a material impact on its financial statements.