SIGNIFICANT ACCOUNTING POLICIES
|12 Months Ended|
Dec. 31, 2020
|Accounting Policies [Abstract]|
|SIGNIFICANT ACCOUNTING POLICIES||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, 2020, 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.
Reverse Stock Split
On September 18, 2020, the Company effected a 1-for-10 reverse stock split of its common stock. Unless otherwise noted, impacted amounts and share information included in the financial statements and notes thereto, and elsewhere in this Form 10-K, have been retroactively adjusted as if the reverse stock split occurred on the first day of the first period presented. Certain amounts may be slightly different than previously reported due to the settlement of fractional shares as a result of the reverse stock split and rounding. See Note 5 below for more information regarding the reverse stock split.
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 reserves, which includes limited control over future development plans as a non-operator, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of oil and natural gas properties, asset retirement obligations and deferred income taxes. Actual results may differ from those estimates.
The Company considered the impact of the novel coronavirus 2019 (“COVID-19”) pandemic on the assumptions and estimates used by management in the financial statements for the reporting periods presented. As a result of significant fluctuations in commodity prices during the year, the Company recognized a material impairment charge during the year ended December 31, 2020 (see Note 3). Management’s estimates and assumptions were based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, which is heightened by the possibility of unforeseen additional impacts from the COVID-19 pandemic, actual results may differ from the estimates and assumptions used, and conditions may change, which could materially affect amounts reported in the financial statements in the near term.
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. The Company’s cash positions represent assets held in checking and money market accounts. Cash and cash equivalents 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 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 balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net in the balance sheets.
As of December 31, 2020 and 2019, the allowance for doubtful accounts was $3.9 million and $4.6 million, respectively. The amount charged to operations for doubtful accounts was $0.3 million, zero and zero for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020 and 2019, the amount charged against the allowance for doubtful accounts was $1.0 million and $0.7 million, respectively.
As of December 31, 2020 and 2019, the Company included accounts receivable of $4.4 million and $4.7 million, respectively, 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 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.
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 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, 2020, 2019 and 2018, respectively:
As of December 31, 2020, the Company held leasehold interests primarily in the Williston Basin of the United States on acreage 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, 2020, 2019 and 2018, 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 in 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 recorded a ceiling test impairment of $1,066.7 million for the year ended December 31, 2020. The Company did not have any ceiling test impairment for the years ended December 31, 2019 and 2018. Impairment charges affect the Company’s reported net income but do not reduce the Company’s cash flow.
The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are considered proved or impaired. The following table presents depletion and depletion per BOE sold of the Company’s proved oil and natural gas properties for the periods presented:
The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.
Capitalized costs associated with impaired unproved 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 proved or impaired. 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, 2020, 2019 and 2018, the Company expired leases of $2.9 million, $3.6 million, and $9.4 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 upon initial recognition. 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 relieved. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
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.
The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration, debt exchange derivative liability, and long-term debt. The carrying amounts of cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s derivative instruments assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration and debt exchange derivative liabilities are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as (i) the Company’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) volatility of the Company’s common stock, and (iv) expected average daily trading volumes.
The carrying amount of long-term debt associated with borrowings outstanding under the Company’s Revolving Credit Facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s Second Lien Notes may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the Second Lien Notes bear interest at fixed rates. See Note 11 for additional discussion.
Debt Issuance Costs
Debt issuance costs related to the Company’s Second Lien Notes and Unsecured VEN Bakken Note (see Note 4 below) are included as a deduction from the carrying amount of long-term debt in the balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the Revolving Credit Facility are included in other noncurrent assets and are amortized to interest expense on a straight-line basis over the term of the agreement.
Debt Premiums and Discounts
Debt discounts and premiums related to the Company’s Second Lien Notes and Unsecured VEN Bakken Note are included as a deduction from or addition to the carrying amount of the long-term debt in the balance sheets and are amortized to interest expense using the effective interest method over the term of the related notes.
The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in trade receivables, net in the balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company’s oil is typically sold at delivery points under contracts terms that are common in our industry. The Company’s natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.
A wellhead imbalance liability equal to the Company’s share is recorded to the extent that the Company’s well operators have sold volumes in excess of its share of remaining reserves in an underlying property. However, for the years ended December 31, 2020, 2019 and 2018, 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.
The Company’s disaggregated revenue has two revenue sources, which are oil sales and natural gas and NGL sales, and substantially all of the Company’s revenue comes from one geographic area, the Williston Basin in the United States, primarily in North Dakota and Montana. Oil sales for the years ended December 31, 2020, 2019 and 2018 were $305.2 million, $574.6 million and $450.1 million, respectively. Natural gas and NGL sales for the years ended December 31, 2020, 2019 and 2018 were $18.8 million, $26.6 million and $43.8 million, respectively.
Concentrations of Market, Credit Risk and Other Risks
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, economic disruptions resulting from the COVID-19 pandemic, 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, indirectly via the third-party operators of the wells, from purchasers of its crude oil and natural gas production. While certain of these customers, as well as third-party operators of the wells, 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 have been immaterial.
As a non-operator, 100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the development, exploitation, production and exploration activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operation could be adversely affected. These risks are heightened in the current low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests,
and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators. For the years ended December 31, 2020, 2019 and 2018, the Company’s top four operators made up 49%, 51% and 55%, respectively, of total oil and gas sales.
The Company faces concentration risk due to the fact that substantially all of its oil and natural gas properties are located in the Williston Basin, primarily in North Dakota and Montana. As a result, the Company is disproportionately exposed to risks affecting this geographic area of operations.
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.
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.
Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees’ election.
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.
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 jurisdictions 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 current year book loss and cumulative book losses in recent years, 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. Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance. Accordingly, the valuation allowance against the Company’s deferred tax asset at December 31, 2020 and 2019 was $337.5 million and $144.2 million, 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 statements of operations. See Note 12 for a description of the derivative contracts into which the Company has entered.
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. Proved 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 years ended December 31, 2020, 2019 and 2018.
Employee Benefit Plans
The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. Employees are 100% vested in the employer contributions upon receipt.
Net Income (Loss) Per Common Share
Basic earnings per share (“EPS”) are computed by dividing net income (loss) attributable to common stockholders (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) attributable to common stockholders by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares issuable upon exercise of stock options and vesting of restricted stock awards, and shares issuable upon conversion of the Series A Preferred Stock (see Note 5). The number of potential common shares outstanding are calculated using the treasury stock or if-converted method.
In those reporting periods in which the Company has reported net income available to common stockholders, anti-dilutive shares generally are comprised of the restricted stock that has average unrecognized stock compensation expense greater than the average stock price. In those reporting periods in which the Company has a net loss, anti-dilutive shares are comprised of the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would be anti-dilutive had the company had net income.
Restricted stock awards are excluded from the calculation of basic weighted average common shares outstanding until they vest. For restricted stock awards that vest based on achievement of performance and/or market conditions, the number of contingently issuable common shares included in diluted weighted-average common shares outstanding is based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the end of the reporting period were the end of the contingency period, assuming the result would be dilutive.
Supplemental Cash Flow Information
The following reflects the Company’s supplemental cash flow information for the years ended December 31, 2020, 2019 and 2018 :
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 June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326), Measurement of credit losses on financial instruments, which requires a company immediately recognize management’s current estimated credit losses (“CECL”) for all financial instruments that are not accounted for at fair value through net income. Previously, credit losses on financial assets were only required to be recognized when they were incurred. The Company adopted ASU 2016-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement, Changes to the Disclosure Requirements for Fair Value Measurement (Topic 820), to modify disclosure requirements. The amendments in this ASU remove, modify, and add certain disclosure requirements as a part of the disclosure framework project, which primarily focus on improving the effectiveness of disclosures in the notes to the financial statements. The Company adopted ASU 2018-13 on January 1, 2020. The guidance did not have a significant impact on the financial statements or notes accompanying the financial statements.
In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740), Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles and also simplification of areas such as separate entity financial statements and interim recognition of enactment of tax laws or rate changes. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim reporting periods within those years. The Company adopted the new standard on January 1, 2021 on a prospective basis, which did not have a material impact on its financial position, results of operations, or cash flows.
The entire disclosure for all significant accounting policies of the reporting entity.
Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef