Nature of Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2010

Nature of Operations and Significant Accounting Policies

Nature of Operations and Significant Accounting Policies

Note 1 — Nature of Operations and Significant Accounting Policies

Nytis Exploration (USA) Inc. (Nytis or the Company) is an independent oil and gas company engaged in the exploration, development and production of natural gas in the United States.  The Company’s business is comprised of the assets and properties of Nytis Exploration Company LLC (Nytis LLC) and Nytis Exploration of Pennsylvania LLC (Nytis Pennsylvania) which conduct the Company’s operations in the Appalachian and Illinois Basins.  Collectively Nytis, Nytis LLC and Nytis Pennsylvania are referred to as the Company.

Accounting policies used by the Company reflect industry practices and conform to accounting principles generally accepted in the United States of America.  The more significant of such accounting policies are briefly discussed below.

Principles of Consolidation

The consolidated financial statements include the accounts of Nytis and its consolidated subsidiaries.  As of December 31, 2010, the Company owns 85% of Nytis Pennsylvania and approximately 98% of Nytis LLC.  In February and March of 2010, Nytis LLC and Nytis Pennsylvania sold all their assets located in Pennsylvania.  As certain of these assets sold comprised all of the assets of Nytis Pennsylvania, this subsidiary is in the process of being dissolved and its business wound up.  As a result of the sale and pursuant to the operating agreement, as the Company received a certain return on its investment in Nytis Pennsylvania, the Company’s interest in Nytis Pennsylvania was reduced from 90% to 85% effective March 2010. All significant intercompany accounts and transactions have been eliminated.

Reclassifications

As of December 31, 2010, due to the long-term nature of the utilization of the prepaid drilling costs, the Company reclassified these prepaid assets as of December 31, 2009 from current assets to long-term assets.  The Company evaluated the quantitative and qualitative aspects of the adjustment and determined the reclassification was not material.  There was no impact on the Company’s results of operations and a nominal change in cash flows from operating activities with a corresponding change in cash flows from investing activities for the year ended December 31, 2009.

As of December 31, 2010, the Company elected to reflect its derivative gains and losses on a separate line in its Consolidated Statements of Operations.  Prior to 2010, such gains and losses were included with oil and gas revenues.  For comparative purposes, the Company reclassified its 2009 derivative gains from oil and gas revenues to a separate line.  As a result of this reclassification, there was no impact on the Company’s results of operations or cash flow statements for the year ended December 31, 2009.

Cash and Cash Equivalents

Cash and cash equivalents in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less.  Such investments are deemed to be cash equivalents for purposes of the consolidated financial statements.  The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments.

Accounts Receivable

Revenue producing activities are conducted primarily in Illinois, Kentucky, Ohio, Pennsylvania and West Virginia.  The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers.  The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified.  At December 31, 2010 and 2009, the Company had not identified any collection issues and as a consequence no allowance for doubtful accounts was provided for on those dates.  During 2010 and 2009, the Company’s primary purchaser of its natural gas accounted for 47% and 45%, respectively of the Company’s natural gas revenues and represented approximately 45% of the Company’s natural gas accounts receivable at December 31, 2010.  There are a number of purchasers in the areas that the Company sells its production and accordingly, management does not believe that changing its primary purchaser, as the Company elected to do in 2010, or a loss of any other single purchaser would materially impact the Company’s business.

Accounting for Oil and Gas Operations

The Company uses the full cost method of accounting for oil and gas properties.  Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipments, are capitalized.  Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties.  Nytis assesses its unproved properties for impairment at least annually.  Significant unproved properties are assessed individually.  During 2010, approximately $846,000 of expiring acreage was reclassified into proved property.  This acreage represents leases that will expire during 2011 and will not be renewed.  During 2009, approximately $620,000 of expiring acreage was reclassified into proved property.  This acreage represents leases that expired during 2010 and were not renewed.  These costs were included in the ceiling test and depletion calculations.

The Company performs a ceiling test annually.  Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued in the balance sheet, plus the cost, or estimated fair value if lower, of unproved properties and the costs of any properties not being amortized, if any, net of income taxes  (“ceiling limitation”).  Should the full cost pool exceed this ceiling limitation, impairment is recognized.  The present value of estimated future net revenues is computed by applying the average, first-day-of-the-month oil and gas price during the 12-month period ended December 31, 2010 to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

The December 31, 2009 ceiling test was based on average first-day-of-the-month prices during the twelve-month period prior to December 31, 2009 pursuant to the Securities and Exchange Commission’s (SEC) new “Modernization of Oil and Gas Reporting” rule (see Note 2).  As a result of applying the new pricing rules and the five year limitation rule for proved undeveloped reserves, the Company recognized a ceiling test impairment expense of $16.1 million as of December 31, 2009.  Based on the prior rules utilizing spot prices at the end of the year, the Company would have not exceeded its ceiling limitation.  No ceiling test impairment expense related to the Company’s oil and gas properties was recorded during 2010.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil.  Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves.  All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.  During 2010, the Company recognized a gain on the disposition of its Pennsylvania oil and gas properties as the disposition significantly altered the relationship between capitalized costs and proved reserves.  See Note 4.

Other Property and Equipment

Other property and equipment are recorded at cost upon acquisition.  Depreciation of other property and equipment over their estimated useful lives is provided for using the straight-line method over three to seven years.

Long-Lived Assets

The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered.  The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired.

Equity Method Investments

Investee companies that are not consolidated, but over which the Company exercises significant influence, are accounted for under the equity method of accounting.  Under the equity method of accounting, an Investee company’s accounts are not reflected within the Company’s Consolidated Balance Sheets and Statements of Operations; however, the Company’s share of the earnings or losses, net of intercompany earnings or losses, of the Investee company is reflected in earnings.

Proportional Consolidation

The Company accounts for its 17.5% ownership interest in Sullivan Energy Ventures LLC (Sullivan), using the proportionate consolidation method of accounting.  Therefore, the Company’s proportionate share of Sullivan’s assets, liabilities, revenues and expenses are reflected in the corresponding line items within the balance sheets and statements of operations.  The Company includes its proportionate share of reserves from the Sullivan assets in its reserves presented in Note 17 and for purposes of calculating its depletion and ceiling test limitation.

Asset Retirement Obligations

The Company’s asset retirement obligations (ARO) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool.  Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements.  The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability.  Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.  AROs are valued utilizing Level 3 fair value measurement inputs.

The following table is a reconciliation of the ARO for the years ended December 31, 2010 and 2009.

	Year Ended December 31, 2010			Year Ended December 31, 2009
Balance at beginning of year	$	749,470		$	669,963
Accretion expense	17,367			43,315
Additions during period	97,597			36,192
Property dispositions	(512,480		)	—
Balance at end of year	$	351,954		$	749,470

Financial Instruments

The Company’s financial instruments include cash and cash equivalents, accounts receivables, trade payables and accrued liabilities.  The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments.  The Company’s derivative instruments are recorded at fair value, as discussed below and in Note 3.  The carrying amount of the Company’s credit facility approximated fair value since borrowings bear interest at variable rates.

Gas Derivative Instruments

The Company enters into commodity derivative contracts to manage its exposure to natural gas price volatility with an objective to achieve more predictable cash flows.  Commodity derivative contracts may take the form of futures contracts, swaps or options.  The Company has elected not to designate its derivatives as cash flow hedges.  All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the consolidated balance sheets and the changes in fair value are recognized as gains or losses in revenues in the consolidated statements of operations.

Income Taxes

Nytis accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Stock-Based Compensation

Compensation cost is measured at the grant date based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Revenue Recognition

The Company accounts for natural gas sales using the entitlements method.  The Company accounts for oil sales when title to the product is transferred. Under the entitlements method, revenue is recorded based upon the Company’s share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced.  The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.  Gas imbalances at December 31, 2010 and 2009 were not significant.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities.  Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of derivative instruments and asset retirement obligations.  Actual results could differ from those estimates and assumptions used.

Impact of Recently Issued Accounting Standards

Effective January 1, 2010, the Company adopted new authoritative guidance for fair value measurements and disclosures requiring additional disclosures related to transfers in and out of Levels 1 and 2 fair value measurements, inputs and valuation techniques used to value Level 2 and 3 measurements and fair value disclosures for each class of asset and liability for Levels 1, 2, and 3.  The adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.  Effective January 1, 2011, the Company will adopt the new guidance requiring that purchases, sales, issuances, and settlements in the rollforward activity in Level 3 measurements be disclosed.  Refer to Note 3 for further details regarding the Company’s assets and liabilities measured at fair value.