Quarterly report pursuant to Section 13 or 15(d)

SIGNIFICANT ACCOUNTING POLICIES (Policies)

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SIGNIFICANT ACCOUNTING POLICIES (Policies)
3 Months Ended
Mar. 31, 2015
SIGNIFICANT ACCOUNTING POLICIES [Abstract]  
Use of Estimates
Use of Estimates
 
The preparation of financial statements under 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.  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, impairment of oil and natural gas properties, and deferred income taxes.  Actual results may differ from those estimates.
Cash and Cash Equivalents
Cash and Cash Equivalents
 
Northern 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.
 
Accounts Receivable
Accounts Receivable
 
Accounts receivable are carried on a gross basis, with no discounting.  The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances.
 
The allowance for doubtful accounts at March 31, 2015 and December 31, 2014 was $2,340,000 and $1,840,000, respectively.
Advances to Operators
Advances to Operators
 
The Company participates in the drilling of crude oil and natural gas wells with other working interest partners.  Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs.  The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.
Other Property and Equipment
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 seven 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 $79,775 and $79,668 for the three months ended March 31, 2015 and 2014, respectively.
Oil and Gas Properties
Oil and Gas Properties

Northern 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 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.  Capitalized costs are summarized as follows for the three months ended March 31, 2015 and 2014, respectively:

   
Three Months Ended
March 31,
 
   
2015
   
2014
 
Capitalized Certain Payroll and Other Internal Costs
  $ 425,428     $ 648,876  
Capitalized Interest Costs
    737,750       1,197,410  
    $ 1,163,178     $ 1,846,286  

As of March 31, 2015, the Company held leasehold interests in the Williston Basin on acreage located in North Dakota and Montana targeting the Bakken and Three Forks formations.

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.  There were no property sales in the three months ended March 31, 2015 and 2014 that resulted in a significant alteration.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.  The test determines a limit, or ceiling, on the book value of the proved oil and gas properties.  Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling.  The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties.  If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.
 
As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded a non-cash ceiling test impairment of $360.4 million in the three-month period ended March 31, 2015.  The Company did not have any impairment of its proved oil and gas properties for the three-month period ended March 31, 2014.  The impairment charge affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation.  In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers.  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 three months ended March 31, 2015 and 2014, the Company transferred into the full cost pool costs related to expired leases of $5.5 million and $7.3 million, respectively.
Asset Retirement Obligations
Asset Retirement Obligations

The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Debt Issuance Costs
Debt Issuance Costs

Deferred financing costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes.  These debt issuance costs are being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4).

The amortization of debt issuance costs for the three months ended March 31, 2015 and 2014 was $722,144 and $634,592, respectively.
Bond Premium on Senior Notes
Bond Premium on Senior Notes

At March 31, 2015, the Company had recorded a bond premium of $10.5 million in connection with the “8% Senior Notes Due 2020” (see Note 4).  This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.

The amortization of the bond premium for the three months ended March 31, 2015 and 2014 was $371,681, in each period.
Revenue Recognition
Revenue Recognition

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.  For the three months ended March 31, 2015 and 2014, 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.
Concentrations of Market and Credit Risk
Concentrations of Market and Credit Risk

The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas.  The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production sector of the crude oil and natural gas industry.  The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production.  While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term.

The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk.  Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments.  The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.  The Company attempts to limit the amount of credit exposure to any one financial institution or company.  The Company believes the credit quality of its customers is generally high.  In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.
Stock-Based Compensation
Stock-Based Compensation

The Company records expense 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.
Stock Issuance
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.
Income Taxes
Income Taxes

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 March 31, 2015 and December 31, 2014.
Net Income Per Common Share
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 months ended March 31, 2015 and 2014 are as follows:
 
   
Three Months Ended
March 31,
 
   
2015
   
2014
 
Weighted Average Common Shares Outstanding – Basic
    60,556,180       61,203,725  
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock
    -       242,549  
Weighted Average Common Shares Outstanding – Diluted
    60,556,180       61,446,274  
                 
Restricted Stock Excluded From EPS Due To The Anti-Dilutive Effect
    144,420       5,213  
Derivative Instruments and Price Risk Management
Derivative Instruments and Price Risk Management

The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil.  The Company enters 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 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.

The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value and marked-to-market at the end of each period.  Any realized gains and losses are recorded to gain (loss) on settled derivatives and mark-to-market gains or losses are recorded to gains (losses) on the mark-to-market of derivative instruments on the statements of operations.  See Note 11 for a description of the derivative contracts which the Company has entered into.
New Accounting Pronouncements
New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“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.

In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition.  The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This guidance will be effective for the Company in the annual period beginning after December 15, 2016.  The Company is evaluating the effect of adopting this new accounting guidance but does not expect adoption will have a material impact on the Company’s statements of operations, balance sheets, cash flows or disclosures.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40).”  The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company does not believe that the adoption of this guidance will have a material impact on its financial statements.

In April 2015, the FASB issued ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.  An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle.  These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items.  We are evaluating the impact that this new guidance will have on our financial statements.