Quarterly report pursuant to Section 13 or 15(d)

SIGNIFICANT ACCOUNTING POLICIES

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SIGNIFICANT ACCOUNTING POLICIES
6 Months Ended
Jun. 30, 2011
SIGNIFICANT ACCOUNTING POLICIES [Abstract]  
SIGNIFICANT ACCOUNTING POLICIES
NOTE 2     SIGNIFICANT ACCOUNTING POLICIES
 
The financial information included herein is unaudited. The balance sheet as of December 31, 2010 has been derived from the Company's audited financial statements as of December 31, 2010.  However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles), which are in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods.  The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.
 
Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2010, which were included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010.
 
Cash and Cash Equivalents
 
The Company considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents.  Cash equivalents consist primarily of interest-bearing bank accounts and money market funds.  The Company's cash positions represent assets held in checking and money market accounts.  These assets are generally available on a daily or weekly basis and are highly liquid in nature.  Due to the balances being greater than $250,000, the Company does not have FDIC coverage on the entire amount of bank deposits.  The Company believes this risk is minimal.  In addition, the Company is subject to Security Investor Protection Corporation (SIPC) protection on a vast majority of its financial assets.
 
Short-Term Investments
 
All United States Treasuries that are included in short-term investments are considered available-for-sale and are carried at fair value.  The short-term investments are considered current assets due their maturity term or the Company's ability and intent to use them to fund current operations.  The unrealized gains and losses related to these securities are included in Accumulated Other Comprehensive Income.   The realized gains and losses related to these securities are included in Other Income (Expense) in the condensed statements of operations.
 
Other Property and Equipment
 
Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to fifteen years.  Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets.  Depreciation expense was $138,608 and $50,897 for the six months ended June 30, 2011 and 2010 respectively.
 
Debt Issuance Costs
 
In February 2009, the Company entered into a revolving credit facility with CIT Capital USA, Inc. (“CIT”) (See Note 8).  The Company incurred costs related to this facility that were capitalized on the balance sheet as Debt Issuance Costs.  Included in the Debt Issuance Costs are direct costs paid to third parties for broker fees and legal fees, 180,000 shares of restricted common stock paid as additional compensation for broker fees, and the fair value of 300,000 warrants issued to CIT.  The fair value of the warrants was calculated using the Black-Scholes valuation model based on factors present at the time of closing.  CIT exercised these warrants at a price of $5.00 per share in January 2011.  The initial total amount capitalized for Debt Issuance Costs was $1,670,000 related to the original agreement with CIT.  In May 2009, the Company amended the revolving credit facility with CIT to allow for additional borrowings.  The Company incurred and capitalized $216,414 of direct costs related to this amendment.
 
In May 2010, the Company completed an assignment of its revolving credit facility to Macquarie Bank Limited (“Macquarie”) from CIT.  In connection with the assignment, the Company and Macquarie entered into an Amended and Restated Credit Agreement governing the credit facility.  The Company incurred and capitalized $386,179 of direct costs related to this assignment and amendment.
 
The debt issuance costs are being amortized over the term of the facility.
 
The amortization of debt issuance costs for the six months ended June 30, 2011 and 2010 was $180,341 and $280,768, respectively.
 
Asset Retirement Obligations
 
The Company records the fair value of a liability for an asset retirement obligation in the period in which the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset.  The Asset Retirement Obligation is included in Other Noncurrent Liabilities on the condensed balance sheet.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
 
Revenue Recognition and Natural Gas Balancing
 
The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable.  The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation.  As of June 30, 2011 and December 31, 2010, the Company's natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.  
 
Stock-Based Compensation
 
The Company records expenses associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants the Company calculates the stock based compensation expense based upon estimated fair value on the date of grant.   For stock options, the Company uses the Black-Scholes option valuation model to calculate stock based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.
 
Income Taxes
 
The Company accounts for income taxes under FASB ASC 740-10-30.  Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. No valuation allowance has been recorded as of June 30, 2011 and December 31, 2010.
 
Stock Issuance
 
The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in FASB ASC 505-50-30.
 
Net Income Per Common Share
 
Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period.  Potential common shares include stock options and restricted stock.  The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
 
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2011 and 2010 are as follows:

 
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
 
2011
   
2010
   
2011
   
2010
 
Weighted average common shares outstanding - basic
    61,686,463       49,934,409       61,586,603       47,032,602  
Plus: Potentially dilutive common shares
                               
Stock options, warrants, and restricted stock
    367,425       675,534       441,689       561,359  
Weighted average common shares  outstanding - diluted
    62,053,888       50,609,944       62,028,292       47,593,962  
Stock options, warrants, and restricted stock excluded from EPS due to the anti-dilutive effect
    -       -       -       -  
                           
 
Full Cost Method
 
The Company follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”).  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities.  Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities.  Costs associated with production and general corporate activities are expensed in the period incurred. The Company capitalized $9,604,131 and $2,771,704 of internal costs and $0 and $59,711 of interest for the six months ended June 30, 2011and 2010, respectively.
 
As of June 30, 2011, the Company held leasehold interests on acreage in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. The Company held leasehold interest on acreage in Billings, Burke, Divide, Dunn, Golden Valley, McKenzie, McLean, Mercer, Mountrail, Stark and Williams Counties, North Dakota and in Richland and Roosevelt Counties, Montana targeting the Bakken and Three Forks formations as well as acreage in Yates County, New York that is prospective for Trenton/Black River, Marcellus and Queenstown-Medina natural gas production.
 
Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.  The Company received $5,027,162 of proceeds from property sales in the six months ended June 30, 2011, which was credited to the full cost pool.
 
Capitalized costs associated with impaired properties and capitalized cost related to properties having proved reserves, plus the estimated future development costs, asset retirement costs under FASB ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers on an annual basis. In interim periods, the Company's management estimates depletion taking into account estimated additional reserves, future development costs, amongst other variables.  The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations.  For the six months ended June 30, 2011, the Company included $5,550,022 of costs related to expired leases in, Richland County Montana, Burke County, Dunn County and Mountrail County North Dakota and Yates County, New York, which costs are subject to the depletion calculation.  Of the 17,607 net acres (34,846 gross acres) that expired in the six months ended June 30, 2011, 12,349 net acres were prospective for the Bakken and Three Forks formations that the Company did not renew, extend or save by any other lease savings clause.  The remainder of the acreage consisted of 5,258 net acres in Yates County, New York that the company decided not to renew, extend or save by any other lease savings clause.
 
Capitalized costs of crude oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties (adjusted for related income tax effects).  Should capitalized costs exceed this ceiling, impairment is recognized.  The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.  Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet.  Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense.  As of June 30, 2011, the Company has not realized any impairment of its properties. 
 
Use of Estimates
 
The preparation of these condensed financial statements under generally accepted accounting principles (“GAAP”) in the United States 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.  The most significant estimates relate to proved crude oil and natural gas reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of certain investments, and deferred income taxes.  Actual results may differ from those estimates.
 
Reclassifications
 
Certain reclassifications have been made to prior years' reported amounts in order to conform with the current period presentation. In prior periods the Company separately indentified share based compensation on its condensed statement of operations.  These amounts have been reclassified to be included in general and administrative expense.  These reclassifications did not impact the Company's net income, stockholders' equity or cash flows.
 
Derivative Instruments and Price Risk Management
 
The Company uses derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of crude oil and natural gas.  The Company may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments are based on expected production from existing wells.  The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.
 
At the inception of a derivative contract, the Company historically designated the derivative as a cash flow hedge.  For all derivatives designated as cash flow hedges, the Company formally documented the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract.  To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis.  The Company historically measured hedge effectiveness on a quarterly basis and hedge accounting would be discontinued prospectively if it determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item.  Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered.  If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative are recognized in earnings immediately.  See Note 13 for a description of the derivative contracts which the Company executed during 2011, and 2010.
 
Derivatives, historically, were recorded on the balance sheet at fair value and changes in the fair value of derivatives were recorded each period in Current Earnings or Other Comprehensive Income, depending on whether a derivative was designated as part of a hedge transaction and, if it was, depending on the type of hedge transaction.  The Company's derivatives historically consisted primarily of cash flow hedge transactions in which the Company was hedging the variability of cash flows related to a forecasted transaction.  Period to period changes in the fair value of derivative instruments designated as cash flow hedges were reported in Accumulated Other Comprehensive Income (Loss) and reclassified to earnings in the periods in which the hedged item impacts earnings.  The ineffective portion of the cash flow hedges were reflected in current period earnings as gain or loss from derivatives.  Gains and losses on derivative instruments that did not qualify for hedge accounting were included in income or loss from derivatives in the period in which they occur.  The resulting cash flows from derivatives were reported as cash flows from operating activities.
 
On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and in addition, the Company has elected not to designate any subsequent derivative contracts as accounting hedges under FASB ASC 815-20-25.  As such, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period.  Any realized gains and losses are recorded to Gain (Loss) on Settled Derivatives and unrealized gains or losses are recorded to Mark-to-Market of Derivative Instruments on the Condensed Statement of Operations rather than as a component of Accumulated Other Comprehensive Income (Loss) or Other Income (Expense).
 
New 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.