Note 2 – Summary of Significant Accounting Policies

 

 

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.

 

 

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

 

 

Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners.

 

 

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 and payables were immaterial as of December 31, 2014 and 2013. 

 

 

The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended:

 

 

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.

 

 

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 oil and gas properties. 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 $16,688,  $14,753 and $13,331 of these internal costs during 2014,  2013 and 2012, 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.

 

Historical and estimated future development costs of oil and natural gas properties which have been evaluated and contain proved reserves, as well as the historical cost of properties which have been determined to have no future economic value, 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 the Company determines that these costs have been impaired.

 

Under full cost accounting rules, 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 net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. 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 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, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting 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.

 

 

The Company depreciates its other property and equipment of $7,118 and $7,255 at December 31, 2014 and 2013, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $836,  $750 and $760 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, 2014,  2013 and 2012, respectively. The accumulated depreciation on other property and equipment was $14,005 and $13,240 as of December 31, 2014 and 2013, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 14 for additional information.

 

 

The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2014,  2013 and 2012, the Company capitalized $4,295,  $4,410 and $2,109 of interest expense.

 

 

Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan, which is reflective of the effective interest rate method. Deferred financing costs of $18,200 and $1,098 as of December 31, 2014 and 2013, respectively, net of accumulated amortization. Amortization of deferred financing costs of $1,272,  $471 and $402 was recorded for the years ended December 31, 2014,  2013 and 2012, respectively.

 

 

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 12 for additional information.

 

 

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 gain or loss on derivative contracts. The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012.  Derivative contracts executed subsequent to December 31, 2012 and outstanding as of December 31, 2014 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 6 and 7 for additional information regarding the Company’s derivative contracts.

 

 

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 carryforwards 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 11 for additional information.

 

 

The Company grants to directors and employees stock options and restricted stock awards (“RS awards”). The Company also grants 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).

 

 

During the three year period ended 2013, the Company paid no federal income taxes. During the years ended December 31, 2014,  2013 and 2012, the company made cash interest payments of $7,283,  $13,189 and $13,920, respectively.

 

 

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. 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 3 for additional information on the Medusa divestiture.

 

 

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.

 

 

In May 2014, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.