Nature of Operations and Significant Accounting Policies

9 Months Ended

12 Months Ended

Sep. 30, 2011

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.

Summary of Significant Accounting Policies

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements.  In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of September 30, 2011, and the Company’s results of operations and cash flows for the three and nine months ended September 30, 2011 and 2010.  Operating results for the three and nine months ended September 30, 2011 and 2010 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results and other factors.  For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited financial statements and the notes thereto should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2010 filed on Form 8-K/A with the Securities and Exchange Commission (“SEC”) on September 21, 2011.

In the course of preparing the unaudited financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses and in the disclosures of commitments and contingencies.  Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and accordingly, actual results could differ from amounts initially established.

Principles of Consolidation

The consolidated financial statements include the accounts of Carbon, Nytis USA and its consolidated subsidiaries.  The Company owns 100% of Nytis USA.  Nytis USA owns 85% of Nytis Pennsylvania and approximately 98% of Nytis LLC.  Nytis LLC also holds an interest in various oil and gas partnerships related to its acquisition discussed in Note 4.

For partnerships where the Company has a controlling interest, the partnerships are consolidated.  The Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its consolidated combined statements of operations.  The Company also reflects the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its consolidated balance sheets.  All significant intercompany accounts and transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s financial statements also include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the oil and gas partnerships in which the Company has a non-controlling interest.

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee.  When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used.  All transactions, if any, with investees have been eliminated in the accompanying consolidated financial statements.

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 equipment, 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.  The Company assesses its unproved properties for impairment at least annually.  Significant unproved properties are assessed individually.

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.

The Company performs a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.  The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation.  The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.  Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down (impairment) would be recognized to the extent of the excess capitalized costs.  Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.

As of September 30, 2011, the Company’s full cost pool exceeded the ceiling limitation, based on oil prices of $90.94 per barrel and gas prices of $4.10 per Mcf and accordingly, for the three months ended September 30, 2011, the Company recorded a non-cash impairment of approximately $3.8 million related to its oil and gas properties.  The impairment for the three months ended September 30, 2011 was primarily attributed to a new gathering arrangement on certain of the Company’s proved undeveloped gas reserves in Kentucky. Additionally, during the quarter, there was a reduction in natural gas prices utilized in calculating the present value of future revenues from the Company’s proved gas reserves.  These negative effects to future revenues were partially offset by additional proved undeveloped oil reserves booked during the quarter.  The impairment for the nine months ended September 30, 2011 was approximately $12.2 million, primarily attributed to the reasons stated above for the three months ended September 30, 2011, and combined with additional reductions in natural gas prices utilized in calculating the present value of future net revenues from the Company’s proved gas reserves that occurred during the six months ended June 30, 2011.  The Company did not recognize any non-cash impairment charges related to its oil and gas properties in the nine months ended September 30, 2010.

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 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 nine months ended September 30, 2011:

	Nine Months Ended September 30,
(in thousands)	2011
Balance at beginning of period	$	352
Accretion expense	71
Additions assumed with acquired properties	1,581
Additions during period	121
Balance at end of period	$	2,125

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate.

The Company has an investment that is accounted for using the equity method of accounting, which was acquired in the fourth quarter of 2010 and consists of a 50% interest in a joint venture which owns a gas gathering facility.  Loss of approximately $36,000 and income of approximately $5,000 from the joint venture was recognized for the three and nine months ended September 30, 2011, respectively, in the Company’s consolidated statements of operations.

Also in the fourth quarter of 2010, the Company acquired a 17.5% ownership in Sullivan Energy Ventures LLC (“Sullivan”).  At that time, the Company determined that it had the ability to significantly influence the operating decisions of Sullivan and accounted for its ownership in Sullivan by recording the Company’s pro-rata share of Sullivan’s financial results.  During the second quarter of 2011, it became evident that the Company would not be able to obtain the requisite amount of information relative to Sullivan’s revenues, expenses and reserves and thus did not have the ability to significantly influence the decisions of Sullivan.  As a result, the Company reclassified its investment in Sullivan to Investments in Affiliates in the accompanying consolidated balance sheets at the net investment value of approximately $463,000 as of April 1, 2011 and began to account for this investment using the cost method of accounting.  The Company’s standardized reserve disclosures at December 31, 2010 included approximately $796,000 and 663,000 Mcf of reserves related to Sullivan.  For the three months ended March 31, 2011, the Company would have recorded an additional oil and gas asset impairment expense of approximately $280,000 if the Sullivan reserves and related property balance had not been included in the ceiling test calculation.  Because this was a new entity, revenues and expenses recorded related to Sullivan were deminimus during 2010 and the first quarter of 2011.

Earnings Per Common Share

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period.  The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested.  Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of the options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).  As a result of the reverse merger with SLSC on February 14, 2011 (see Note 3), the number of common shares outstanding from the beginning of the periods presented in the accompanying consolidated financial statements to the merger date were computed on the basis of the weighted-average number of common shares of Nytis USA outstanding during the respective periods multiplied by the exchange ratio established in the merger agreement, which was approximately 1,631 common shares of SLSC for each common share of Nytis USA.  The weighted average number of shares used in the earnings per share calculations were based on historical weighted-average number of common shares outstanding multiplied by the exchange ratio.  The number of common shares outstanding from the merger date to September 30, 2011 is the actual number of common shares of the Company outstanding during that period.

At September 30, 2011, the Company had common stock equivalents of 2,073,530 and 2,134,257 for the three and nine months ended September 30, 2011, respectively, which are excluded from the calculation of diluted loss per share as the effect would be anti-dilutive.