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, 2013
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 (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 $73 and $34 at December 31, 2013 and 2012, respectively. During 2013, 2012, and 2011 the Company recorded $45, $0 and $(281), respectively of bad debt expense. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt expense 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 NGLs is included in natural gas sales. Natural gas balancing receivables were $71 and $93 as of 2013 and 2012, respectively. Natural gas balancing payables were $126 and $653 as of 2013 and 2012, 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 greater than 10% of its total oil and natural gas production during each of the years ended:
 
For the Year Ended December 31,
 
2013
 
2012
 
2011
Enterprise Crude Oil, LLC
38
%
 
32
%
 
16
%
Shell Trading Company
31
%
 
39
%
 
45
%
Plains Marketing, L.P.
15
%
 
15
%
 
17
%
Other
16
%
 
14
%
 
22
%
   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 $14,753, $13,331 and $11,857 of these internal costs during 2013, 2012 and 2011, 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 the sale would significantly alter the relationship between capitalized costs and proved reserves, 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 accounting rules of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. See Note 12 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 the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data.  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.
Other Property and Equipment

The Company depreciates its other property and equipment of $7,255 and $6,424 at December 31, 2013 and 2012, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $750, $760 and $645 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, 2013, 2012 and 2011, respectively. The accumulated depreciation on other property and equipment was $13,240 and $13,238 as of December 31, 2013 and 2012, respectively. As discussed in Note 13, during 2013, the Company recorded an impairment charge to reduce to zero the carrying values of its assets held for sale. The Company reviews its other property and equipment for impairment when indicators of impairment exist.

H.
Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization (e.g. unevaluated properties). Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2013, 2012 and 2011, the Company capitalized $4,410, $2,109 and $573 of interest expense.

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 11 for additional information.

J.
Derivatives

The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or ineffective portions of contracts designated as cash flow hedges were recognized as derivative expense (income). The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during 2013 and outstanding as of December 31, 2013 were not designated as accounting hedges, and are carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 5 and 6 for additional information regarding the Company’s derivative contracts.

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. 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, if any, of the asset for which it is deemed more likely than not that it will not be realized. See Note 10 for additional information.

L.
Share-Based Compensation

The Company grants to directors and employees stock options, restricted stock awards (“RS awards”), and 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-settleable 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 as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years).

RS awards, RSU awards and Cash-settleable 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-settleable 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 as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated value recognized over the vesting period (generally three years).

M.
Statements of Cash Flows Supplemental Information

During the three year period ended 2013, the Company paid no federal income taxes. During the years ended December 31, 2013, 2012 and 2011, the company made cash interest payments of $13,189, $13,920 and $14,922, respectively.

N.
Investment in Medusa Spar LLC

During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting for investments. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was 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 the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 12 for additional information on the Medusa divestiture.

O.
Consolidation of Variable Interest Entities

In June 2009, the FASB issued an accounting standard which became effective for and was adopted by the Company on January 1, 2010. Upon adoption, 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, which resulted in Callon gaining the power to direct the activities of Callon Entrada, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company’s financial statements. Callon Entrada was later dissolved in 2011.

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, using the treasury-stock method, reflects the potential dilution caused by the exercise of all options and vesting of all restricted stock and restricted stock units settleable in shares.

Q.
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.

In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income and required disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, it requires that the Company present either on the face of its financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount is reclassified in its entirety to net income in the same reporting period. For amounts not reclassified in their entirety to net income, the Company is required to cross-reference to the related note on the face of the financial statements for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.