SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In connection with preparing the financial statements for the year ended December 31, 2016, the Company has evaluated subsequent events for potential recognition and disclosure through the date of this filing and determined that there were no subsequent events which required recognition or disclosure in the financial statements through the date of this filing.

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.

Reclassifications

Certain prior period balances in the balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net loss, cash flows or stockholders’ deficit previously reported.

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 balance sheets.

As of December 31, 2016 and 2015, the allowance for doubtful accounts was $4.9 million and $4.5 million, respectively. The amount charged to operations for doubtful accounts was $0.8 million, $6.2 million and $1.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016 and 2015, the amount charged against the allowance for doubtful accounts was $0.4 million and $3.5 million, respectively.

As of December 31, 2016 and 2015, the Company included accounts receivable of $6.8 million in Other Noncurrent Assets, Net due to their long-term nature.

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 $0.2 million, $0.3 million, and $0.3 million for the years ended December 31, 2016, 2015 and 2014, 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 years ended December 31, 2016, 2015 and 2014, respectively:



	Years Ended December 31,
	2016		2015		2014
Capitalized Certain Payroll and Other Internal Costs	$	1,890,480	$	2,717,913	$	2,153,448
Capitalized Interest Costs	356,196		1,506,172		4,409,544
Total	$	2,246,676	$	4,224,085	$	6,562,992

As of December 31, 2016, 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 years ended December 31, 2016, 2015 and 2014, 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.

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 years ended December 31, 2016 and 2015 of $237.0 million, and $1.2 billion, respectively. The Company did not have any impairment of its proved oil and gas properties during 2014. 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, we expect we could be required to further writedown the value of our 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 years ended December 31, 2016, 2015 and 2014, the Company expired leases of $13.4 million, $19.0 million, and $26.3 million, respectively.

At December 31, 2016, the Company performed an impairment review using prices that reflect an average of 2016‘s monthly prices as prescribed pursuant to the SEC’s guidelines. If lower average monthly pricing is reflected in the trailing twelve-month average pricing calculation, the present value of the Company’s future net revenues could decline and further impairment could be recognized. SEC defined prices for each quarter-end in 2016 were as follows:



SEC Defined Prices for 12-Months Ended	NYMEX Oil Price (per Bbl)		Henry Hub Gas Price (per MMBtu)
December 31, 2016	$	42.75	$	2.49
September 30, 2016	41.68		2.28
June 30, 2016	43.12		2.24
March 31, 2016	46.26		2.39

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 years ended December 31, 2016, 2015 and 2014 was $3.8 million, $3.7 million and $2.8 million, respectively.

During the year ended December 31, 2016, $1.1 million of debt issuance costs were written-off as a result of a reduction in the borrowing base of the Revolving Credit Facility, which became effective in May 2016 and was due to the impact that lower commodity prices had on our oil and gas reserve valuation. There were no debt issuance costs written-off during the years ended December 31, 2015 and 2014, respectively.

As a result of the adoption of ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”), the Company reclassified unamortized debt issuance costs associated with its 8% Senior Notes, which totaled $12.5 million as of December 31, 2015, from “Debt Issuance Costs, Net” to a reduction of “Long-term Debt, Net” on the balance sheets. Adoption of ASU 2015-03 had no impact on the Company’s current and previously reported stockholders’ deficit, results of operations, or cash flows. Unamortized debt issuance costs associated with the Company’s revolving credit facility, which amounted to $1.6 million and $3.3 million as of December 31, 2016 and 2015, respectively, were not reclassified and remain reflected in “Other Noncurrent Assets, Net” on the 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% 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 was $1.5 million for each of the years ended December 31, 2016, 2015 and 2014.

On May 18, 2015, the Company recorded a bond discount of $10.0 million in connection with the “8% 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 years ended December 31, 2016, 2015 and 2014 was $2.0 million, $1.2 million and zero, 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. As of December 31, 2016, 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

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.

Restructuring Costs

The Company accounts for restructuring costs in accordance with FASB ASC Topic 420, “Exit or Disposal Cost Obligations.” Under these standards, the costs associated with restructuring are recorded during the period in which the liability is incurred. During the year ended December 31, 2015, the Company recognized $0.5 million in restructuring costs for employee severance and related benefit costs incurred as part of a reduction in workforce and the closing of its Denver office, which included $0.1 million of non-cash expense related to acceleration of certain equity awards previously granted under the Company’s 2013 Incentive Plan. There were no restructuring costs incurred for the years ended December 31, 2016 and 2014, respectively.

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, 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 December 31, 2016, 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 December 31, 2016, 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 December 31, 2016 and 2015 was $341.3 million and $232.3 million, respectively. No valuation allowance was recorded at December 31, 2014.

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 years ended December 31, 2016, 2015 and 2014 are as follows:



	Years Ended December 31,
	2016	2015	2014
Weighted Average Common Shares Outstanding – Basic	61,173,547	60,652,447	60,691,701
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock	—	—	169,068
Weighted Average Common Shares Outstanding – Diluted	61,173,547	60,652,447	60,860,769
Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect	829,313	322,393	15,590

As of December 31, 2016, 2015 and 2014, potentially dilutive shares from stock options were 391,872, 141,872, and 141,872, respectively. There options were all exercisable at December 31, 2016, 2015 and 2014. The Company also has potentially dilutive shares from restricted stock grants outstanding of 1,905,104, 2,365,396, and 538,499 at December 31, 2016, 2015 and 2014, 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 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” 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 statements of operations. See Note 13 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. In 2016 and 2015, the Company recorded $237.0 million and $1.2 billion, respectively, in impairment related to crude oil and natural gas properties. There was no impairment related to crude oil and natural gas properties in 2014. There was no impairment of other long-lived assets recorded for the years ended December 31, 2016, 2015 and 2014.

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the 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 Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers – Deferral of the Effective Date,” which approved a one year deferral of ASU 2014-09 for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early application is permitted as of the original effective date for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company will adopt this ASU on January 1, 2018. The Company is evaluating the impact of this ASU on our financial statements and, based on the continuing evaluation of our revenue streams, this ASU is not expected to have a material impact on our financial statements. The Company expects it will use the modified retrospective approach to implementation.

In February 2016, the FASB issued ASU 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 our financial statements, however, based on our current operating leases, it is not expected to have a material impact.

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting, which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. Early adoption is permitted for any entity in

any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the fourth quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy for forfeitures. See Note 10 for discussion of additional accounting consequences related to the adoption of this ASU.

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 our 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 after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on our financial statements.

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on our financial statements.