SIGNIFICANT ACCOUNTING POLICIES
|12 Months Ended|
Dec. 31, 2014
|SIGNIFICANT ACCOUNTING POLICIES [Abstract]|
|SIGNIFICANT ACCOUNTING POLICIES||
NOTE 2 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, 2014, 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, 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 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.
At December 31, 2014 and 2013, the allowance for doubtful accounts was $1,840,000 and $1,050,000, respectively. The amount charged to operations for doubtful accounts was $1,375,000, $1,050,000, and $0 for the years ended December 31, 2014, 2013 and 2012, respectively. At December 31, 2014 and 2013, the amount charged against the allowance for doubtful accounts was $585,000 and $0, 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 $315,405, $325,859, and $409,888 for the years ended December 31, 2014, 2013 and 2012, respectively.
Full Cost Method
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, 2014, 2013 and 2012, respectively:
As of December 31, 2014, 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, 2014, 2013 and 2012, the Company sold acreage and interests in producing properties for $0, $0, and $908,000, respectively. The proceeds for these sales were applied to reduce the capitalized costs of crude oil and natural gas properties.
Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the years ended December 31, 2014, 2013 and 2012, the Company transferred into the full cost pool costs related to expired leases of $26.3 million, $14.1 million and $7.1 million, respectively.
The Company assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the years ended December 31, 2014, 2013 and 2012, the Company included $21.4 million, $5.1 million and $0, respectively, related to expiring leases within costs subject to the depletion calculation.
Capitalized costs of crude oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves’ future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. During the three year period ended December 31, 2014, the Company did not realize any impairment of its properties.
At December 31, 2014, the Company performed an impairment review using prices that reflect an average of 2014’s monthly prices as prescribed pursuant to the SEC’s guidelines. These average prices used in the December 31, 2014 impairment review are significantly higher than the actual and currently forecasted prices in 2015. As lower average monthly pricing is reflected in the trailing 12-month average pricing calculation, the present value of the Company’s future net revenues is expected to decline and impairment could be recognized. Given the current oil and natural gas pricing environment, the Company believes it could have noncash ceiling test write-downs of its oil and natural gas properties in 2015. The quarterly ceiling test considers many factors including reserves, capital expenditure estimates and trailing 12-month average prices. SEC defined prices for each quarter in 2014 were as follows:
Asset Retirement Obligations
Asset retirement obligation is included in other noncurrent liabilities and relates to future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition. Estimates are based on estimated remaining lives of those wells based on reserve estimates, external estimates to plug and abandon the wells in the future, inflation, credit adjusted discount rates and federal and state regulatory requirements. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
Debt Issuance Costs
Deferred financing costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes. These debt issuance costs are being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4).
The amortization of debt issuance costs for the years ended December 31, 2014, 2013 and 2012 was $2,776,024, $2,625,240 and $1,527,194, respectively.
Bond Premium on Senior Notes
At December 31, 2014, the Company had recorded a bond premium of $10.5 million in connection with the “8% Senior Notes Due 2020” (see Note 4). This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
The amortization of the bond premium for the years ended December 31, 2014, 2013 and 2012 was $1,486,726, $960,177 and $0, respectively.
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, 2014, 2013 and 2012, 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 customers is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.
The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants the Company calculates the stock based compensation expense based upon estimated fair value on the date of grant. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.
The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.
Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. No valuation allowance has been recorded as of December 31, 2014 and 2013.
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, 2014, 2013 and 2012 are as follows:
As of December 31, 2014, 2013 and 2012, potentially dilutive shares from stock options were 141,872, 241,872 and 251,963, respectively. These options are all exercisable at December 31, 2014, 2013 and 2012, at an exercise price of $5.18.
The Company also has potentially dilutive shares from restricted stock grants outstanding of 538,499, 592,565 and 777,437, at December 31, 2014, 2013, and 2012, 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.
All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to gain (loss) on settled derivatives and mark-to-market gains or losses are recorded to gains (losses) on the mark-to-market of derivative instruments on the statements of comprehensive income. See Note 14 for a description of the derivative contracts which the Company has entered into.
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 (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. There was no impairment recorded at December 31, 2014, 2013, and 2012.
New Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition. The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance will be effective for the Company in the annual period beginning after December 15, 2016. The Company is evaluating the effect of adopting this new accounting guidance but does not expect adoption will have a material impact on the Company’s statement of comprehensive income, balance sheets, cash flows or disclosures.
The entire disclosure for all significant accounting policies of the reporting entity.
Reference 1: http://www.xbrl.org/2003/role/presentationRef