Quarterly report pursuant to Section 13 or 15(d)

SIGNIFICANT ACCOUNTING POLICIES

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SIGNIFICANT ACCOUNTING POLICIES
9 Months Ended
Sep. 30, 2017
Accounting Policies [Abstract]  
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES

The financial information included herein is unaudited, except for the balance sheet as of December 31, 2016, which has been derived from the Company’s audited financial statements for the year ended December 31, 2016.  However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles) that 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 (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2016, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

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

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 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. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net on the condensed balance sheets.

As of September 30, 2017 and December 31, 2016, the Company included accounts receivable of $5.6 million and $6.8 million, respectively, in Other Noncurrent Assets, Net due to their long-term nature.

The allowance for doubtful accounts at September 30, 2017 and December 31, 2016 was $5.6 million and $4.9 million, respectively.

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

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 $39,101 and $50,652 for the three months ended September 30, 2017 and 2016, respectively. Depreciation expense was $124,888 and $155,813 for the nine months ended September 30, 2017 and 2016, respectively.

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 and nine months ended September 30, 2017 and 2016, respectively.

 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2017
 
2016
 
2017
 
2016
Capitalized Certain Payroll and Other Internal Costs
$
201,875

 
$
239,132

 
$
647,519

 
$
1,674,015

Capitalized Interest Costs
36,919

 
79,805

 
108,687

 
289,409

Total
$
238,794

 
$
318,937

 
$
756,206

 
$
1,963,424



As of September 30, 2017, 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.  In the nine months ended September 30, 2017 and 2016, there were no property sales 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 twelve-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, 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.

The Company did not have any ceiling test impairment for the three and nine months ended September 30, 2017, respectively. As a result of low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the three and nine months ended September 30, 2016 of $43.8 million and $237.0 million, respectively.  The impairment charges affected the Company’s reported net income but did not reduce the Company’s cash flow. If a significantly lower pricing environment reoccurs, the Company’s expects it could be required to further writedown the value of its oil and natural gas properties. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the Company’s 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.   Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate.  The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period.  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 September 30, 2017 and 2016, the Company expired leases of $5.1 million and $5.2 million, respectively. For the nine months ended September 30, 2017 and 2016, the Company expired leases of $14.8 million and $10.5 million, respectively.

Asset Retirement Obligations

The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board (“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 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.

Business Combinations

The Company accounts for its acquisitions that qualify as a business using the acquisition method under FASB ASC Topic 805, “Business Combinations.” Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Debt Issuance Costs

Debt issuance 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 September 30, 2017 and 2016 was $1.0 million and $0.9 million, respectively. The amortization of debt issuance costs for the nine months ended September 30, 2017 and 2016 was $2.9 million and $2.9 million, respectively.

There were no debt issuance costs written off during the three months ended September 30, 2017 and 2016. During the nine months ended September 30, 2017 and 2016, $0.1 million and $1.1 million, respectively, of debt issuance costs were written off as a result of a reduction in the borrowing base of the Revolving Credit Facility.

Unamortized debt issuance costs associated with the Company’s revolving credit facility, which amounted to $1.1 million and $1.6 million as of September 30, 2017 and December 31, 2016, respectively, are reflected in “Other Noncurrent Assets, Net” on the condensed balance sheets.

Bond Premium/Discount on Senior Notes

On May 13, 2013, the Company recorded a bond premium of $10.5 million in connection with the “8.000% 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 September 30, 2017 and 2016 was $0.4 million and $0.4 million, respectively. The amortization of the bond premium for the nine months ended September 30, 2017 and 2016 was $1.1 million and $1.1 million, respectively.

On May 18, 2015, the Company recorded a bond discount of $10.0 million in connection with the “8.000% Senior Notes Due 2020” (see Note 4).  This bond discount 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 discount for the three months ended September 30, 2017 and 2016 was $0.5 million and $0.5 million, respectively. The amortization of the bond discount for the nine months ended September 30, 2017 and 2016 was $1.5 million and $1.5 million, respectively.

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 and nine months ended September 30, 2017 and 2016, 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

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 counterparties 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

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.  In determining the fair value of performance-based share awards subject to market conditions, the Company utilizes a Monte Carlo simulation prepared by an independent third party. 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

The Company records any 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

The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid.  The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis.  The Company’s only taxing jurisdiction is the United States (federal and state).

Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future.  In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations.  In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences.  The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses.

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.  In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended September 30, 2017, driven primarily by the full cost ceiling impairments over that period.  Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas.  The markets for these commodities continue to be volatile.  Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flows.  Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control.  Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance.

In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the three-year period ended September 30, 2017, is difficult to overcome with any forms of positive evidence that may exist.  Accordingly, the valuation allowance against the Company’s deferred tax asset at September 30, 2017 and December 31, 2016 was $335.6 million and $341.3 million, respectively.

Net Income (Loss) Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (loss) (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income (loss) 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 nine months ended September 30, 2017 and 2016 are as follows:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2017
 
2016
 
2017
 
2016
Weighted Average Common Shares Outstanding – Basic
61,843,377

 
61,237,627

 
61,645,920

 
61,127,577

Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock

 

 
345,372

 

Weighted Average Common Shares Outstanding – Diluted
61,843,377

 
61,237,627

 
61,991,292

 
61,127,577

 
 
 
 
 
 
 
 
Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect
1,838,101

 
574,862

 
760,782

 
885,200



As of September 30, 2017 and 2016, potentially dilutive shares from stock option awards were 391,872, respectively. These options were all exercisable at September 30, 2017 and 2016. The Company also has potentially dilutive shares from restricted stock awards outstanding of 1,978,651 and 1,790,617 at September 30, 2017 and 2016, respectively.

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 may also 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” 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 on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the condensed statements of operations.  See Note 11 for a description of the derivative contracts into which the Company has entered.

Impairment

Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Crude oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules.  There was no impairment of other long-lived assets recorded for the three and nine months ended September 30, 2017 and 2016.

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 a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance 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 company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. However, the Company is still evaluating the impact this standard will have on its financial statements upon adoption. The Company does not anticipate the standard to have a material impact on its financial statements upon adoption based on its ongoing evaluation process which will be completed in the fourth quarter of 2017. This evaluation requires, among other things, a review of the contracts it has with customers within each of the revenue streams identified within the Company's business, including oil sales, natural gas sales and NGL sales. The Company has limited revenue streams under which revenue is recognized when control is transferred and ownership passes to the other party. The Company is currently assessing the requirements for additional disclosures and documentation of new policies, procedures, and control activities requirements. The Company’s expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, the Company has not identified any material impact on its financial statements other than additional disclosures requirements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842).  The standard requires lessees to recognize the assets and liabilities that arise from leases on the balance sheet.  A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term.  The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018.  The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period.  The Company is currently evaluating the impact of the new guidance on its financial statements, however, based on its current operating leases, it is not expected to have a material impact.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on its financial statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods beginning after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition and early adoption is permitted. The Company is in the process of evaluating the impact of this guidance on its financial statements.