Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Basis of Presentation [Policy Text Block]

Basis of Presentation and Use of Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

Use of Estimates, Policy [Policy Text Block]

These accounting principles require management to use estimates, judgments and assumptions that affect the amounts of assets, liabilities, revenues and expenses reported herein. While management regularly reviews its estimates, actual results could differ from those estimates.

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year:

• estimates of proved oil and gas reserves,
• estimates as to the expected future cash flow from proved oil and gas properties,
• estimates of future dismantlement and restoration costs,
• estimates of fair values used in purchase accounting and
• estimates of the fair value of derivative instruments.

Principles of Consolidation [Policy Text Block]

Principles of Consolidation

The accompanying consolidated financial statements include all of the accounts of Endeavour and our consolidated subsidiaries. All significant intercompany accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted for equity in earnings or (losses) and distributions received.

Cash And Cash Equivalents Policy [Policy Text Block]

Cash and Cash Equivalents

We consider all highly liquid instruments with an original maturity of 90 days or less at the time of purchase to be cash equivalents.

Restricted Cash [Policy Text Block]

Restricted Cash

Restricted cash has historically included amounts held in escrow for drilling rig commitments, as collateral for lines of credit, and for acquisitions.

Inventory, Policy [Policy Text Block]

Inventories

Materials and supplies and oil inventories are valued at the lower of cost or market value (net realizable value).

Full Cost Accounting for Oil and Gas Operations [Policy Text Block]

Full Cost Accounting for Oil and Gas Operations

Under the full cost method of accounting for oil and gas activities, all acquisition, exploration and development costs incurred for the purpose of finding oil and gas, are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, such as the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals,costs related to such activities, certain directly-related employee costs and a portion of interest expense. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.

Capitalized costs are limited on a country-by-country basis (the ceiling test). Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense. The ceiling test limitation is calculated as the present value, discounted 10%, of:

• the future net cash flows related to estimated production of proved reserves, utilizing the average, first-day-of-the-month price for commodities;
• the effect of derivative instruments that qualify as cash flow hedges;
• the lower of cost or estimated fair value of unproved properties; and
• the expected income tax effects of the above items.

We utilize a single cost center for each country where we have operations for amortization purposes. Any sales or other conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.Proved properties are amortized on a country-by-country basis using the units of production method (“UOP”). The amortization base in the UOP calculation includes the sum of proved property, net of accumulated DD&A, estimated future development costs (future costs to access and develop proved reserves), and asset retirement costs, less related salvage value.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us.

Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated and the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.

Other Property and Equipment [Policy Text Block]

Other Property and Equipment

Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using the straight-line method over their estimated useful lives of two to five years.

Capitalized Interest [Policy Text Block]

Capitalized Interest

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense.

Business Combinations Policy [Policy Text Block]

Business Combinations

Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company's assets and liabilities and carryforwards at the merger date.

Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill and Intangible Assets

We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset's fair value.

Dismantlement, Restoration and Environmental Costs [Policy Text Block]

Dismantlement, Restoration and Environmental Costs

We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectability of the revenue is probable.

Significant Customers [Policy Text Block]

Significant Customers

Our sales in the U.K. are to a limited number of customers, each of which accounted for more than 10% of revenue for the year ended December 31, 2012: Chevron North Sea Ltd, Shell U.K. Limited, and Hess Limited. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with the majority of the sales being to J-W Operating Company.

Derivative Intruments and Hedging Activities [Policy Text Block]

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

Wemay use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to:

• reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell,
• reduce our exposure to increases in interest rates, and
• manage cash flows in support of our annual capital expenditure budget.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative's inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. At December 31, 2012 and 2011, we had no outstanding derivatives that were accounted for as a hedge.

Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative's fair value. Any ineffective portion of the derivative instrument's change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when: (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.

Conscentrations of Credit and Market Risk [Policy Text Block]

Concentrations of Credit and Market Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions. Management believes the risk of loss is minimal.

Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts on a regular basis and to date we have not experienced any non-performance by any of our various counterparties.

As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and our access to capital and on the quantities of oil and gas reserves that may be economically produced.

Foreign Currency Translation [Policy Text Block]

Foreign Currency Translation

The U.S. dollar is the functional currency for all of our existing operations, as a majority of all revenue and financing transactions in these operations are denominated in U.S. dollars. For foreign operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.

Income Tax, Policy [Policy Text Block]

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.

Share-Based Payments [Policy Text Block]

Share-Based Payments

We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee's requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method.

It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2012, we had approximately 2.4million additional shares available for issuance pursuant to our existing stock incentive plan.

Adoption of New Accounting Standards [Policy Text Block]

On January 1, 2012, we adopted the following new standards without material effects on our results of operations or financial position:

• Fair Value -An accounting standard on fair value measurements that clarifies the application of existing guidance and disclosure requirements, changes certain fair value measurement principles and requires additional disclosures about fair value measurements.
• Comprehensive Income - Guidance impacting the presentation of comprehensive income. The guidance eliminates the current option to report components of other comprehensive income in the statement of changes in equity or in a footnote to the financial statements.
• Goodwill -Amendment to the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an option of performing a qualitative assessment prior to calculating the fair value of the reporting unit.