UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


FORM 10-Q
T QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2011
 
£ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE EXCHANGE ACT
 
For the transition period from ____________ to____________
 
Commission File No. 001-33999
 
NORTHERN OIL AND GAS, INC.
(Exact name of Registrant as specified in its charter)

Minnesota
 
95-3848122
(State or Other Jurisdiction of
Incorporation or organization)
 
(I.R.S. Employer Identification No.)

315 Manitoba Avenue – Suite 200
Wayzata, Minnesota 55391
(Address of Principal Executive Offices)
 
(952) 476-9800
(Registrant’s Telephone Number)
 
N/A
(Former name, former address and former fiscal year,
if changed since last report)
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes T  No £
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes T  No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer  £
 
Accelerated Filer  T
     
Non-Accelerated Filer    £
 
Smaller Reporting Company  £
   (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes £ No T

As of November 1, 2011, there were 63,167,132 shares of our common stock, par value $0.001, outstanding.
 


 
 

 

GLOSSARY OF TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit.  Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of crude oil and natural gas:

Bbl” – barrel or barrels.

BOE” – barrels of crude oil equivalent.

Boepd barrels of crude oil equivalent per day.

MBbl” – thousand barrels.

MBoe thousand barrels of crude oil equivalent.

Mcf” – thousand cubic feet of gas.

Mcfe” – thousand cubic feet of gas equivalent.

MMBbls” – million barrels.

MMBoe – million barrels of crude oil equivalent.

MMcf” – million cubic feet of gas.


Terms used to describe our interests in wells and acreage:

Completion means the process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

Conventional play” is an area that is believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

Developed acreage” means acreage consisting of leased acres spaced or assignable to productive wells.  Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.

Dry hole” is an exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

Exploratory well” is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

Gross acres” refer to the number of acres in which we own a gross working interest.

Gross well” is a well in which we own a working interest.

Held by production is a provision in an oil and gas lease that extends a company’s right to operate a lease as long as the property produces a minimum quantity of oil and gas.

 
i

 

Infill well” is a subsequent well drilled in an established spacing unit to the addition of an already established productive well in the spacing unit.   Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

Net acres” represent our percentage ownership of gross acreage.  Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

“Net acres under the bit” or “net acreage under the bit” means those net leased acres on which wells are spud, drilling, drilled, awaiting completion or completing in the spacing unit only, and not yet classified as developed acreage, regardless of whether or not such acreage contains proved reserves.  Acreage included in spacing units of infill wells is not considered under the bit because such acreage was already previously classified as developed acreage when the initial well was completed in the subject spacing unit.

Net well” is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

Productive well” is an exploratory or a development well that is capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Unconventional play” is an area believed to be capable of producing curde oil and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability.  These areas tend to have low permeability and may be closely associated with source rock as this is the case with oil and gas shale, tight oil and gas sands and coal bed methane.

Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves.  Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.

Working interest” means the right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals.  The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

 
ii

 

NORTHERN OIL AND GAS, INC.
FORM 10-Q

September 30, 2011

C O N T E N T S

       
Page
PART I FINANCIAL INFORMATION
   
         
Item 1.
   
2
     
2
     
3
     
4
     
5
         
Item 2.
   
21
         
Item 3.
   
31
         
Item 4.
   
32
         
PART II OTHER INFORMATION
   
         
Item 1.
   
34
         
Item 1A.
   
34
         
Item 2.
   
34
         
Item 6.
   
34
         
 
35

 
1


PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

NORTHERN OIL AND GAS, INC.
CONDENSED BALANCE SHEETS
SEPTEMBER 30, 2011 AND DECEMBER 31, 2010
(UNAUDITED)

ASSETS
   
September 30,
   
December 31,
 
   
2011
   
2010
 
CURRENT ASSETS
           
Cash and Cash Equivalents
  $ 8,265,649     $ 152,110,701  
Trade Receivables
    44,561,467       22,033,647  
Prepaid Drilling Costs
    28,016,106       13,225,650  
Prepaid Expenses
    457,492       345,695  
Other Current Assets
    290,306       475,967  
Derivative Asset
    8,475,550       -  
Short - Term Investments
    -       39,726,700  
Deferred Tax Asset
    -       5,100,000  
Total Current Assets
    90,066,570       233,018,360  
                 
PROPERTY AND EQUIPMENT
               
Oil and Natural Gas Properties, Full Cost Method of Accounting
               
Proved
    400,904,005       158,846,475  
Unproved
    146,459,279       136,135,163  
Other Property and Equipment
    2,660,240       2,479,199  
Total Property and Equipment
    550,023,524       297,460,837  
Less - Accumulated Depreciation and Depletion
    48,329,024       22,152,356  
Total Property and Equipment, Net
    501,694,500       275,308,481  
                 
DERIVATIVE ASSET
    2,881,377       -  
                 
DEBT ISSUANCE COSTS
    1,329,302       1,367,124  
                 
Total Assets
  $ 595,971,749     $ 509,693,965  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
               
Accounts Payable
  $ 52,519,516     $ 48,500,204  
Accrued Expenses
    2,960,868       2,829  
Derivative Liability
    -       11,145,319  
Other Liabilities
    18,574       18,574  
Deferred Tax Liability
    2,531,000       -  
Total Current Liabilities
    58,029,958       59,666,926  
                 
LONG-TERM LIABILITIES
               
Revolving Credit Facility
    15,000,000       -  
Derivative Liability
    -       5,022,657  
Other Noncurrent Liabilities
    744,106       477,900  
Deferred Tax Liability
    27,699,000       9,167,000  
Total Long-Term Liabilities
    43,443,106       14,667,557  
                 
Total Liabilities
    101,473,064       74,334,483  
                 
COMMITMENTS AND CONTINGENCIES (NOTE 15)
               
STOCKHOLDERS' EQUITY
               
Preferred Stock, Par Value $.001; 5,000,000Authorized, No Shares Outstanding
    -       -  
Common Stock, Par Value $.001; 95,000,000 Authorized, (9/30/2011 -63,155,424 Shares Outstanding and 12/31/2010 – 62,129,424 Shares Outstanding)
    63,155       62,129  
Additional Paid-In Capital
    444,937,243       428,484,092  
Retained Earnings
    49,751,472       7,759,192  
Accumulated Other Comprehensive Loss
    (253,185 )     (945,931 )
Total Stockholders' Equity
    494,498,685       435,359,482  
                 
Total Liabilities and Stockholders' Equity
  $ 595,971,749     $ 509,693,965  

The accompanying notes are an integral part of these condensed financial statements.

 
2


NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010
(UNAUDITED)


   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
REVENUES
                       
Oil and Gas Sales
  $ 43,680,619     $ 15,541,520     $ 106,203,904     $ 35,575,240  
(Loss) Gain on Settled Derivatives
    (1,824,719 )     776,010       (10,695,006 )     902,946  
Mark-to-Market Gain (Loss) of Derivative Instruments
    27,105,400       (6,449,577 )     26,675,003       (3,189,194 )
Other Revenue
    88,738       15,868       218,984       48,116  
Total Revenues
    69,050,038       9,883,821       122,402,885       33,337,108  
                                 
OPERATING EXPENSES
                               
Production Expenses
    3,910,859       1,084,769       8,542,761       1,978,526  
Production Taxes
    4,261,407       1,604,608       10,188,308       3,274,751  
General and Administrative Expense
    4,073,988       1,624,071       10,113,995       5,242,582  
Depletion of Oil and Gas Properties
    10,749,384       3,767,712       25,962,463       8,252,153  
Depreciation and Amortization
    75,597       60,300       214,205       111,197  
Accretion of Discount on Asset Retirement Obligations
    7,781       18,025       20,305       30,777  
Total Expenses
    23,079,016       8,159,485       55,042,037       18,889,986  
                                 
INCOME FROM OPERATIONS
    45,971,022       1,724,336       67,360,848       14,447,122  
                                 
OTHER INCOME (EXPENSE)
                               
Interest Expense
    (182,499 )     (145,182 )     (425,687 )     (455,704 )
Interest Income
    1,699       28,072       567,327       303,860  
Gain (Loss) on Available for Sale Securities
    -       -       215,092       (197,556 )
Total Other Income (Expense)
    (180,800 )     (117,110 )     356,732       (349,400 )
                                 
INCOME BEFORE INCOME TAXES
    45,790,222       1,607,226       67,717,580       14,097,722  
                                 
INCOME TAX PROVISION
    17,173,000       620,000       25,725,300       5,430,000  
                                 
NET INCOME
  $ 28,617,222     $ 987,226     $ 41,992,280     $ 8,667,722  
                                 
Net Income Per Common Share – Basic
  $ 0.46     $ 0.02     $ 0.68     $ 0.18  
                                 
Net Income Per Common Share – Diluted
  $ 0.46     $ 0.02     $ 0.68     $ 0.18  
                                 
Weighted Average Shares Outstanding – Basic
    61,919,641       51,519,732       61,708,537       48,544,749  
                                 
Weighted Average Shares Outstanding – Diluted
    62,265,502       52,145,181       62,114,115       49,127,706  
 
The accompanying notes are an integral part of these condensed financial statements.

 
3


NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010
(UNAUDITED)


   
Nine Months Ended
 
   
September 30,
 
   
2011
   
2010
 
CASH FLOWS FROM OPERATING ACTIVITIES
           
Net Income
  $ 41,992,280     $ 8,667,722  
Adjustments to Reconcile Net Income to Net Cash Provided by
               
Operating Activities:
               
Depletion of Oil and Gas Properties
    25,962,463       8,252,153  
Depreciation and Amortization
    214,205       111,197  
Amortization of Debt Issuance Costs
    286,969       366,729  
Accretion of Discount on Asset Retirement Obligations
    20,305       30,777  
Deferred Income Taxes
    25,723,000       5,430,000  
Net (Gain) Loss on Sale of Available for Sale Securities
    (215,092 )     197,556  
Unrealized (Gain) Loss on Derivative Instruments
    (26,675,003 )     3,189,194  
Amortization of Deferred Rent
    (13,931 )     (13,930 )
Share - Based Compensation Expense
    5,552,245       2,730,779  
Changes in Working Capital and Other Items:
               
Increase in Trade Receivables
    (22,527,820 )     (10,816,333 )
Increase in Prepaid Expenses
    (111,797 )     (274,307 )
Decrease (Increase) in Other Current Assets
    185,661       (102,534 )
Increase in Accounts Payable
    (1,028,434 )     8,666,764  
Decrease (Increase) in Accrued Expenses
    20,815       (123,153 )
Net Cash Provided By Operating Activities
    49,385,866       26,312,614  
                 
CASH FLOWS FROM INVESTING ACTIVITIES
               
Purchases of Other Equipment and Furniture
    (181,041 )     (1,956,087 )
Increase in Prepaid Drilling Costs
    (14,790,456 )     (5,598,781 )
Proceeds from Sale of Oil and Gas Properties
    5,027,162       237,877  
Purchase of Available for Sale Securities
    (18,381,690 )     -  
Proceeds from Sale of Available for Sale Securities
    58,606,328       25,890,901  
Purchase of Oil and Gas Properties and Development Capital Expenditures
    (239,762,074 )     (92,812,276 )
Net Cash Used For Investing Activities
    (209,481,771 )     (74,238,366 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES
               
Payments on Line of Credit
    -       (834,492 )
Advances on Revolving Credit Facility
    21,000,000       5,300,000  
Payments on Revolving Credit Facility
    (6,000,000 )     (5,300,000 )
Repayment of Subordinated Notes
    -       (100,000 )
Debt Issuance Costs Paid
    (249,147 )     (386,179 )
Proceeds from Exercise of Warrants
    1,500,000       -  
Proceeds from Issuance of Common Stock - Net of Issuance Costs
    -       82,500,000  
Net Cash Provided by Financing Activities
    16,250,853       81,179,329  
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (143,845,052 )     33,253,577  
                 
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD
    152,110,701       6,233,372  
                 
CASH AND CASH EQUIVALENTS – END OF PERIOD
  $ 8,265,649     $ 39,486,949  
                 
                 
Supplemental Disclosure of Cash Flow Information
               
Cash Paid During the Period for Interest
  $ 17,965     $ 169,232  
Cash Paid During the Period for Income Taxes
  $ 2,300     $ -  
                 
Non-Cash Financing and Investing Activities:
               
Purchase of Oil and Gas Properties through Issuance of Common Stock
  $ -     $ 12,679,422  
Payment of Compensation through Issuance of Common Stock
  $ 17,391,413     $ 5,956,526  
Capitalized Asset Retirement Obligations
  $ 259,832     $ 151,009  

The accompanying notes are an integral part of these condensed financial statements

 
4


NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
SEPTEMBER 30, 2011
(Unaudited)

NOTE 1     ORGANIZATION AND NATURE OF BUSINESS
 
Northern Oil and Gas, Inc. (the “Company,” “our,” “we,” “us” and words of similar import) is a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of crude oil and natural gas properties.  The Company’s common stock trades on the NYSE Amex Equities Market under the symbol “NOG”.
 
The Company acquires interests in crude oil and natural gas acreage and drilling projects, primarily within the Williston Basin Bakken Shale formation. The Company is continuing to develop its substantial leasehold acreage in the Bakken play and will target additional opportunities in the Bakken and Three Forks play. The Company owns working interests in wells, and does not lease land to operators.  Management believes the Company’s experience gained by participating as a non-operating partner has given the Company valuable data on completions and will help its operating partners control well costs and enhance results as the Company continues to develop its higher working interest sections in the remainder of 2011 and beyond.
 
The Company participates on a heads up basis proportionate to its working interest in declared drilling units. As of September 30, 2011, the Company’s principal assets included approximately 160,000 net acres located in the northern region of the United States, of which the Company held leasehold interests on approximately 158,000 net mineral acres in the Williston Basin targeting the Bakken and Three Forks formations. The Company continues to expand its position through aggressive acquisition and leasing programs.
 
The Company’s land acquisition and field operations, along with various other services, are primarily outsourced through the use of consultants and drilling partners.  The Company will continue to retain independent contractors to assist in operating and managing the prospects and other administrative functions.  With the additional acquisition of crude oil and natural gas properties, the Company intends to continue to use both in-house employees and outside consultants to develop and exploit its leasehold interests.
 
As an independent crude oil and natural gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent on prevailing prices of crude oil and natural gas.  A substantial or extended decline in crude oil or natural gas prices could have a material effect on the Company’s financial position, results of operations, cash flows and access to capital, and on the quantities of natural gas and crude oil reserves that can be economically produced.
 
NOTE 2     SIGNIFICANT ACCOUNTING POLICIES
 
The financial information included herein is unaudited. The balance sheet as of December 31, 2010 has been derived from the Company’s audited financial statements as of December 31, 2010.  However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles), which 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 have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2010, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010.
 
Cash and Cash Equivalents
 
The Company 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.
 
 
5


Short-Term Investments
 
All United States Treasuries that are included in short-term investments are considered available-for-sale and are carried at fair value.  The short-term investments are considered current assets due to their maturity term or the Company’s ability and intent to use them to fund current operations.  The unrealized gains and losses related to these securities are included in Accumulated Other Comprehensive Income.  The realized gains and losses related to these securities are included in Other Income (Expense) in the condensed statements of operations.
 
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 fifteen 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 $214,205 and $111,197 for the nine months ended September 30, 2011 and 2010, respectively.
 
Debt Issuance Costs
 
The Company has incurred direct costs related to the revolving credit facility (see Note 8) of $2.5 million.  The debt issuance costs are being amortized over the term of the credit facility.
 
The amortization of debt issuance costs for the nine months ended September 30, 2011 and 2010 was $286,969 and $366,729, respectively.
 
Asset Retirement Obligations
 
The Company records the fair value of a liability for an asset retirement obligation in the period in which the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset.  The Asset Retirement Obligation is included in Other Noncurrent Liabilities on the condensed balance sheet.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
 
Revenue Recognition and Natural Gas Balancing
 
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 September 30, 2011 and December 31, 2010, 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.
 
Stock-Based Compensation
 
The Company records expense associated with the fair value of stock-based compensation.  For fully vested stock and restricted stock grants the Company calculates the stock based compensation expense based upon estimated fair value on the date of grant.  For stock options, the Company uses the Black-Scholes option valuation model to calculate stock based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.
 
 
6


Income Taxes
 
Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. No valuation allowance has been recorded as of September 30, 2011 and December 31, 2010.
 
Stock Issuance
 
The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.
 
Net Income Per Common Share
 
Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period.  Potential common shares include stock options and restricted stock.  The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
 
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2011 and 2010 are as follows:

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Weighted average common shares outstanding – basic
    61,919,641       51,519,732       61,708,537       48,544,749  
Plus: Potentially dilutive common shares
                               
Stock options, warrants, and restricted stock
    345,861       625,449       405,578       582,957  
Weighted average common shares outstanding – diluted
    62,265,502       52,145,181       62,114,115       49,127,706  
Restricted stock excluded from EPS due to the anti-dilutive effect
    44,242       -       37,065       -  


Full Cost Method
 
The Company 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 initially 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. The Company capitalized $13.4 million and $4.1 million of internal costs and $0 and $60,000 of interest for the nine months ended September 30, 2011 and 2010, respectively.
 
As of September 30, 2011, the Company held leasehold interests on acreage in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. The Company held leasehold interest on acreage in Billings, Burke, Divide, Dunn, Golden Valley, McKenzie, McLean, Mercer, Mountrail, Stark and Williams Counties, North Dakota and in Richland and Roosevelt Counties, Montana targeting the Bakken and Three Forks formations as well as acreage in Yates County, New York that is prospective for Trenton/Black River, Marcellus and Queenstown-Medina natural gas production.
 
 
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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.  The Company received $5.0 million of proceeds from property sales in the nine months ended September 30, 2011, which was credited to the full cost pool.
 
Capitalized costs associated with impaired properties and capitalized cost 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 on at least an annual basis.  In interim periods, the Company’s management estimates depletion taking into account estimated additional reserves and future development costs, as well as other variables.  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 nine months ended September 30, 2011, the Company included $8.1 million of costs related to expired leases in, Richland County, Montana; Burke County, Dunn County and Mountrail County, North Dakota; and Yates County, New York, which costs are subject to the depletion calculation.  Of the 24,112 net acres that expired in the nine months ended September 30, 2011, 13,884  net acres were prospective for the Bakken and Three Forks formations that the Company did not renew, extend or save by any other lease savings clause.  The remainder of the acreage consisted of 10,228 net acres in Sheridan County, Montana and Yates County, New York that the company did not renew, extend or save by any other lease savings clause.
 
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.  As of September 30, 2011, the Company has not realized any impairment of its properties. 
 
Use of Estimates
 
The preparation of these condensed financial statements under generally accepted accounting principles (“GAAP”) in the United States 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, fair value of certain investments, and deferred income taxes.  Actual results may differ from those estimates.
 
Derivative Instruments and Price Risk Management
 
The Company uses derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of crude oil and natural gas.  The Company may periodically enter 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 or natural gas 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.
 
On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and in addition, the Company has elected not to designate any subsequent derivative contracts as accounting hedges.  As such, all derivative positions are carried at their fair value on the condensed 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 unrealized gains or losses are recorded to Mark-to-Market of Derivative Instruments on the condensed statement of operations rather than as a component of Accumulated Other Comprehensive Income (Loss) or Other Income (Expense).  See Note 13 for a description of the derivative contracts which the Company executed during 2011 and 2010.
 
 
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Prior to November 1, 2009, the Company, at the inception of a derivative contract, designated the derivative as a cash flow hedge.  For all derivatives designated as cash flow hedges, the Company formally documented the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract.  To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis.  The Company historically measured hedge effectiveness on a quarterly basis and hedge accounting would be discontinued prospectively if it determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item.  Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered.  If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative are recognized in earnings immediately.
 
Derivatives, historically, were recorded on the balance sheet at fair value and changes in the fair value of derivatives were recorded each period in Current Earnings or Other Comprehensive Income, depending on whether a derivative was designated as part of a hedge transaction and, if it was, depending on the type of hedge transaction.  The Company’s derivatives historically consisted primarily of cash flow hedge transactions in which the Company was hedging the variability of cash flows related to a forecasted transaction.  Period to period changes in the fair value of derivative instruments designated as cash flow hedges were reported in Accumulated Other Comprehensive Income (Loss) and reclassified to earnings in the periods in which the hedged item impacts earnings.  The ineffective portion of the cash flow hedges were reflected in current period earnings as gain or loss from derivatives.  Gains and losses on derivative instruments that did not qualify for hedge accounting were included in income or loss from derivatives in the period in which they occur.  The resulting cash flows from derivatives were reported as cash flows from operating activities.
 
New Accounting Pronouncements
 
From time to time, new accounting pronouncements are issued by 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.

 
NOTE 3     SHORT-TERM INVESTMENTS
 
All United States Treasuries that are included in short-term investments are considered available-for-sale and are carried at fair value.  The short-term investments are considered current assets due to their maturity term or the Company’s ability and intent to use them to fund current operations.  The unrealized gains and losses related to these securities are included in Accumulated Other Comprehensive Income (Loss).  The realized gains and losses related to these securities are included in Other Income (Expense) in the condensed statements of operations.  For the nine months ended September 30, 2011, the Company realized gains of $215,092 on the sale of short-term investments.  For the nine months ended September 30, 2010, the Company realized losses of $197,556 on the sale of short-term investments.
 
The Company has no short-term investments as of September 30, 2011.
 
The following is a summary of the Company’s short-term investments as of December 31, 2010:
 
               
Fair Market
 
   
Cost at
         
Value at
 
   
December 31,
   
Unrealized
   
December 31,
 
   
2010
   
(Loss)
   
2010
 
United States Treasuries
  $ 40,009,546     $ (282,846 )   $ 39,726,700  

 
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NOTE 4     CRUDE OIL AND NATURAL GAS PROPERTIES

The value of the Company’s crude oil and natural gas properties consists of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs.  Each of these costs contributed to the Company’s approximate $252.4 million increase in crude oil and natural gas properties during the nine months ended September 30, 2011.
 
Acquisitions
 
For the nine months ended September 30, 2011, the Company completed acreage acquisitions involving properties spanning across the following counties of North Dakota:  Billings, Burke, Divide, Dunn, Golden Valley, Mclean, McKenzie, Mountrail, Stark and Williams and Richland and Roosevelt counties of Montana.  The Company generally values acreage subject to near-term drilling activities on a lease-by-lease basis because it believes each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear.  Consistent with that approach, the majority of the Company’s acreage acquisitions involve properties that are “hand-picked” by the Company on a lease-by-lease basis for their contribution to a well expected to be spud in the near future, and the subject leases are then aggregated to complete one single closing with the transferor.  As such, the Company generally views each acreage assignment from brokers, landmen and other parties as involving several separate acquisitions combined into one closing with the common transferor for convenience.  However, in certain instances an acquisition may involve a larger number of leases presented by the transferors as a single package without negotiation on a lease-by-lease basis.  In those instances, the Company still reviews each lease on a lease-by-lease basis to ensure that the package as a whole meets its acquisition criteria and drilling expectations.
 
Divestitures

In November 2009, the Company agreed to participate in the exploration and development of Slawson Exploration Company, Inc.’s (“Slawson”) Anvil project in Roosevelt and Sheridan Counties, Montana and Williams County, North Dakota.  In April 2011, the Company sold its interest in the Anvil project for $5.0 million.  As of the date of sale, the Company’s cost basis in the Anvil project was $1.8 million.  The Company sold its interest in the project along with Slawson, who also desired to sell its entire interest in the project.  Slawson had drilled and completed one well in the project area prior to the divestiture – the Mayhem #1-19H well – and the Company retained its interest in that wellbore in connection with the divestiture. The proceeds from the sale were applied to reduce the capitalized costs of oil and gas properties.

From time-to-time the Company may also trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage.

Unproved Properties
 
As of September 30, 2011, the Company’s unproved properties not being amortized comprise approximately 124,000 net acres of undeveloped leasehold interests.  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.
 
Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired.  The Company anticipates these excluded costs will be included in the depletion computation over the next five years.  The Company is unable to predict the future impact on depletion rates.

The Company had 178 gross (20.13 net) wells drilling, awaiting completion or completing as of September 30, 2011.  All properties that are not classified as proven properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion.  Once a property is classified as proven, all associated acreage and drilling costs are subject to depletion.
 
 
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The Company historically has acquired its properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators.  The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling, with the exception of the defined drilling projects with Slawson described below.
 
As of September 30, 2011, the Company was participating in three defined drilling projects with Slawson covering an aggregate of approximately 15,000 net acres of leasehold interests held by the Company.  The Windsor project area includes approximately 3,300 net acres held by the Company, primarily located in Mountrail and surrounding counties of North Dakota.  The South West Big Sky project includes approximately 3,400 total net acres held by the Company in Richland County, Montana.  The Lambert project includes approximately 8,400 net acres held by the Company in Richland County, Montana.

NOTE 5     PREFERRED AND COMMON STOCK

The Company’s Articles of Incorporation authorize the issuance of up to 100,000,000 shares.  The shares are classified in two classes, consisting of 95,000,000 shares of common stock, par value $.001 per share, and 5,000,000 shares of preferred stock, par value $.001 per share. The board of directors is authorized to establish one or more series of preferred stock, setting forth the designation of each such series, and fixing the relative rights and preferences of each such series.  The Company has neither designated nor issued any shares of preferred stock.
 
In January 2011, CIT exercised the 300,000 warrants that were issued as part of a prior revolving credit facility.  Total proceeds from the exercise of these warrants were $1.5 million.
 
In January 2011, the Company issued 2,000 shares of Common Stock to two employees of the Company as compensation for their services.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was approximately $56,000 or $27.98 per share, the market value of a share of common stock on the date the stock was issued.  The entire amount of this stock award was expensed in the nine months ended September 30, 2011.
 
In January 2011, the Company issued an aggregate of 15,265 shares of Common Stock to four executives of the Company as compensation for their services.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was approximately $427,000 or $27.98 per share, the market value of a share of common stock on the date the stock was issued.  The entire amount of this stock award was expensed in the nine months ended September 30, 2011.
 
In January 2011, the Company issued 100,000 shares of Common Stock to two executives of the Company as partial consideration for the amendment and restatement of their employment agreements, which included the extension of non-compete terms from one to three years along with various other modifications.  The executives were fully vested in the shares on the date of the grant.  The fair value of the stock issued was approximately $2.8 million, or $27.98 per share, the market value of a share of common stock on the date the stock was issued.  The entire amount of this stock award was expensed in the nine months ended September 30, 2011.
 
In April 2011, the Company issued 1,000 shares of Common Stock to an employee of the Company as compensation for their services.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was approximately $24,000 or $23.76 per share, the market value of a share of common stock on the date the stock was issued.  The entire amount of this stock award was expensed in the nine months ended September 30, 2011.
 
In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150 million shares of the Company’s outstanding common stock.  The stock repurchase program will allow the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.  The Company has not made any repurchases under this program to date.

 
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In August 2011, the Company issued 5,000 shares of Common Stock to five employees of the Company as compensation for their services.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was approximately $89,000 or $17.81 per share, the market value of a share of common stock on the date the stock was issued.  The entire amount of this stock award was expensed in the nine months ended September 30, 2011.
 
In August 2011, the Company issued 10,000 shares of Common Stock to two board members of the Company as compensation for their services.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was approximately $208,000 or $20.84 per share, the market value of a share of common stock on the date the stock was issued.  The entire amount of this stock award was expensed in the nine months ended September 30, 2011.
 
As of September 30, 2011, the Company had accrued bonuses of approximately $2.9 million based on the year to date results of operations in comparison to year-end bonus attainment expectations.  This includes, but is not limited to, operational metrics, such as increased well count, increased proven reserves, additional strategic acreage acquisitions, and various other targets.  Management anticipates these bonuses will be paid in the fourth quarter of 2011 through the issuance of shares of common stock.  The accrued bonuses as of September 30, 2011, are an estimate and are considered discretionary based on 2011 operations.  The Company’s Compensation Committee has approved a plan to grant bonuses and the bonus accrual is based on that plan, but the September 30, 2011 bonus accrual balance has not been approved by the Compensation Committee.  The Company expensed approximately $485,000 and $900,000 in share-based compensation related to this bonus accrual for the three and nine months ended September 30, 2011.  The remainder of bonus was capitalized into the full cost pool. The Company had accrued bonuses of approximately $405,000 and $2.2 million for the three and nine months ended September 30, 2010.  Approximately $190,000 and $950,000 were expensed in share-based compensation for the three and nine months ended September 30, 2010.  The bonuses accrued as of September 30, 2010 were paid in the fourth quarter of 2010 through the issuance of shares of common stock.

NOTE 6     RELATED PARTY TRANSACTIONS
 
The Company previously purchased leasehold interests from Gallatin Resources, LLC (“Gallatin”) in 2007. During the first nine months of 2011, the Company paid Gallatin a total of approximately $6,500 related to previously acquired leasehold interests.  Carter Stewart, one of the Company’s previous directors, owns a 25% interest in Gallatin.  Mr. Stewart resigned as a director of the Company on August 29, 2011.  Legal counsel for Gallatin informed the Company that Mr. Stewart does not have the power to control Gallatin Resources because each member of Gallatin has the right to vote on matters in proportion to their respective membership interest in the company and company matters are determined by a vote of the holders of a majority of membership interests.  Further, Mr. Stewart is neither an officer nor a director of Gallatin.  As such, Mr. Stewart does not have the ability to individually control company decisions for Gallatin.
 
The Company had a securities account with Morgan Stanley Smith Barney that was managed by Kathleen Gilbertson, a financial advisor with that firm who is the sister of the Company’s president and Director, Ryan Gilbertson.  The Company closed this account on August 4, 2011.
 
All transactions involving related parties were approved by the Company’s board of directors or Audit Committee.
 
NOTE 7     STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS
 
On April 26, 2011, the board of directors approved an amendment and restatement of the Northern Oil and Gas, Inc. 2009 Equity Incentive Plan (the “Plan”), which was approved at the annual meeting of shareholders.  An additional 1,000,000 shares were authorized for grant under the Plan, resulting in an aggregate of 4,000,000 shares authorized for past and future grants under the Plan.  The Plan is intended to provide a means whereby the Company may be able, by granting stock options and shares of restricted stock, to attract, retain and motivate capable and loyal employees, non-employee directors, consultants and advisors of the company, for the benefit of the Company and its shareholders.
 
 
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Stock Option Awards
 
On November 1, 2007, the board of directors granted options to purchase 560,000 shares of the Company’s common stock under the Company’s 2006 Incentive Stock Option Plan.  The Company granted options to purchase 500,000 shares of the Company’s common stock, to members of the board and options to purchase 60,000 shares of the Company’s common stock to one employee pursuant to an employment agreement.  These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date.  As of September 30, 2011, options to purchase a total of 265,963 shares remain outstanding but unexercised.  The board of directors determined that no future grants will be made pursuant to the 2006 Incentive Stock Option Plan. All future stock compensation will be issued under the 2009 Equity Incentive Plan.
 
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.  The Company used the simplified method to determine the expected term of the options due to the lack of sufficient historical data.  Changes in these assumptions can materially affect the fair value estimate.  The total fair value of the options is recognized as compensation over the vesting period.  There have been no stock options granted in the nine months ended September 30, 2011 under the 2006 Stock Option Plan or the 2009 Equity Incentive Plan.
 
The following summarizes activities concerning outstanding options to purchase shares of the Company’s common stock as of and for the period ending September 30, 2011:
 
 
·
No options were exercised or forfeited in the nine months ended September 30, 2011.
 
 
·
No options expired during the nine months ended September 30, 2011.
 
 
·
Options covering 265,963 shares are exercisable and outstanding at September 30, 2011.
 
 
·
There is no further compensation expense that will be recognized in future periods relative to any options that had been granted as of September 30, 2011, because the Company recognized the entire fair value of such compensation upon vesting of the options.
 
 
·
There were no unvested options at September 30, 2011.
 

Warrants Granted February 2009

On February 27,  2009, in conjunction with the closing of a prior revolving credit facility, the Company issued CIT warrants to purchase a total of 300,000 shares of common stock exercisable at $5.00 per share.   The total fair value of the warrants was calculated using the Black-Scholes valuation model based on factors present at the time the warrants were issued.  The fair value of the warrants is included in Debt Issuance Costs and is being amortized over the term of the facility.  CIT exercised the warrants in January 2011.
 
Restricted Stock Awards
 
During the nine months ended September 30, 2011, the Company issued 592,735 restricted shares of common stock as compensation to officers and employees of the Company, which were issued under the Plan. The restricted shares vest over various terms with all restricted shares vesting no later than January 1, 2014. As of September 30, 2011, there was approximately $18.4 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense will be recognized over the remaining vesting period of the grants. The Company has assumed a zero percent forfeiture rate for restricted stock.
 
 
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The following table reflects the outstanding restricted stock awards and activity related thereto for the nine months ended September 30, 2011:

   
Nine Months Ended
September 30, 2011
 
   
Number of
Shares
   
Weighted-Average
Price
 
Restricted Stock Awards:
           
Restricted Shares Outstanding at the Beginning of Period
    1,135,622     $ 13.28  
Shares Granted
    592,735     $ 27.93  
Lapse of Restrictions
    (536,464 )   $ 17.07  
Restricted Shares Outstanding at September 30, 2011
    1,191,893     $ 18.86  

NOTE 8     REVOLVING CREDIT FACILITY
 
In February 2009, the Company completed the closing of a revolving credit facility with CIT that provided up to a maximum principal amount of $25 million of working capital for exploration and production operations.
 
On May 26, 2010, the Company completed the assignment of its revolving credit facility to Macquarie from CIT.  In connection with the assignment the Company and Macquarie entered into an Amended and Restated Credit Agreement governing the facility.
 
On August 8, 2011, the Company and Macquarie entered into a Second Amended and Restated Credit Agreement (the “Restated Credit Agreement”) governing the Company’s credit facility (the “Credit Facility”).  The Credit Facility provides that the aggregate maximum credit may be increased in the future to up to $500 million.  The Restated Credit Agreement provides for an initial borrowing base of $150 million, subject to the aggregate maximum credit amount then in effect.  Initially, the Restated Credit Agreement provided for an aggregate maximum credit amount of $25 million in principal amount of borrowings to be used as working capital for exploration and production operations. Such aggregate maximum credit amount may be increased, subject to the conditions set forth in the Restated Credit Agreement, but in no event to more than $500 million.  One of the conditions to any such increase would be an additional commitment of such funds by Macquarie or another lender.   Financing available under the facility is equal to the lesser of the aggregate maximum credit amount and the borrowing base.  The borrowing base of funds available under the Credit Facility will be redetermined semi-annually. The aggregate maximum credit amount under the Credit Facility is currently $100 million.  The Credit Facility terminates on May 26, 2014.  The Company had $15 million of borrowings under Credit Facility at September 30, 2011 and no borrowings at December 31, 2010. As of September 30, 2011 the Company’s borrowings were fixed at a rate of 2.73%.
 
The Company has the option to designate the reference rate of interest for each specific borrowing under the Credit Facility as amounts are advanced.  Borrowings based upon the London Interbank Offered Rate (“LIBOR”) will bear interest at a rate equal LIBOR plus a spread ranging from 2.5% to 3.25% depending on the percentage of borrowings base that is currently advanced.  Any borrowings not designated as being based upon LIBOR will bear interest at a rate equal to the current prime rate published by the Wall Street Journal, plus a spread ranging from 2% to 2.5%, depending on the percentage of borrowing base that is currently advanced.  The Company has the option to designate either pricing mechanism.  Interest payments are due under the Credit Facility in arrears, in the case of a loan based on LIBOR on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December.  All outstanding principal is due and payable upon termination of the Credit Facility.
 
The applicable interest rate increases under the Credit Facility and the lenders may accelerate payments under the Credit Facility, or call all obligations due under certain circumstances, upon an event of default.  The Credit Facility references various events constituting a default, including, but not limited to, failure to pay interest on any loan under the Credit Facility, any material violation of any representation or warranty under the Restated Credit Agreement, failure to observe or perform certain covenants, conditions or agreements under the Restated Credit Agreement, a change in control of the Company, default under any other material indebtedness of the Company, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Credit Facility.  The Company was not in default on the Credit Facility as of September 30, 2011.

 
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All of the Company’s obligations under the Credit Facility and the swap agreements with Macquarie are secured by a first priority security interest in any and all assets of the Company.

NOTE 9     ASSET RETIREMENT OBLIGATION
 
The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, with a corresponding increase in the carrying amount of the related long lived asset.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.  The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.  
 
The following table summarizes the Company’s asset retirement obligation transactions recorded during the nine months ended September 30, 2011:
 
   
Nine Months Ended
September 30, 2011
 
Beginning Asset Retirement Obligation
  $ 459,326  
Liabilities Incurred for New Wells Placed in Production
    259,832  
Accretion of Discount on Asset Retirement Obligations
    20,305  
Ending Asset Retirement Obligation
  $ 739,462  

NOTE 10     INCOME TAXES
 
The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
 
The income tax provision for the nine months ended September 30, 2011 and 2010 consists of the following:

   
Nine Months
Ended September 30,
 
   
2011
   
2010
 
Current Income Taxes
  $ 2,300     $ -  
Deferred Income Taxes
               
Federal
    21,813,000       4,580,000  
State
    3,910,000       850,000  
Total Provision
  $ 25,725,300     $ 5,430,000  

Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement.  Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards.

The Company has no liabilities for unrecognized tax benefits.

The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense.  For the nine months ended September 30, 2011, the Company did not recognize any interest or penalties in its condensed statement of operations, nor did it have any interest or penalties accrued in its condensed balance sheet at September 30, 2011 relating to unrecognized benefits.

 
15


The tax years 2010, 2009, 2008 and 2007 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject.

NOTE 11     FAIR VALUE

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.  The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:
 
Level 1 - Quoted prices in active markets for identical assets or liabilities.
 
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets of liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
 
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
 
The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of September 30, 2011 and December 31, 2010.

   
Fair Value Measurements at
September 30, 2011 Using
 
   
Quoted Prices In Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Commodity Derivatives – Current Asset
  $ -     $ 8,475,550     $ -  
Commodity Derivatives – Non-Current Asset
  $ -     $ 2,881,377     $ -  
Total
  $ -     $ 11,356,927     $ -  

   
Fair Value Measurements at
December 31, 2010 Using
 
   
Quoted Prices In Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Commodity Derivatives – Current Liability
  $ -     $ (11,145,318 )   $ -  
Commodity Derivatives – Non-Current Liability
  $ -     $ (5,022,657 )   $ -  
Short-Term Investments (See Note 3)
  $ 39,726,700     $ -     $ -  
Total
  $ 39,726,700     $ (16,167,975 )   $ -  

There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the nine month period ended September 30, 2011.

Level 1 assets consist of US Treasury Notes, the fair value of these treasuries is based on quoted market prices.

 
16



Level 2 liabilities consist of derivative liabilities (see Note 13).  The fair value of the Company's derivative financial instruments is determined based on spot prices and the notional quantities.  The fair value of all derivative contracts is reflected on the condensed balance sheet.  The current derivative liability amounts represent the fair values expected to be settled in the subsequent year.

NOTE 12      FINANCIAL INSTRUMENTS
 
The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, short term investments, and accounts payable. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and line of credit approximate fair value because of their immediate or short-term maturities.
 
The Company’s accounts receivable relate to crude oil and natural gas sold to various industry companies.  Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral.  Management believes the Company’s accounts receivable at September 30, 2011 and December 31, 2010 do not represent significant credit risks as they are dispersed across many counterparties.  The Company has determined that no allowance for doubtful accounts is necessary at September 30, 2011 and December 31, 2010.

NOTE 13     DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
 
The Company utilizes commodity swap contracts and costless collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the crude oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.
 
On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and, in addition, the Company has elected not to designate any subsequent derivative contracts as cash flow hedges.  Beginning on November 1, 2009, 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 unrealized gains or losses are recorded to Mark-to-Market of Derivative Instruments on the condensed statement of operations rather than as a component of other comprehensive income (loss) or other income (expense).
 
Derivative instruments are presented on a gross basis, even when those instruments are subject to a master netting arrangement and qualify for net presentations on the balance sheet.  The Company has a master netting agreement on each of the individual crude oil contracts and therefore the current asset and liability are netted on the condensed balance sheet and the non-current asset and liability are netted on the condensed balance sheet.
 
Crude Oil Derivative Contracts Cash-flow Hedges
 
Prior to November 1, 2009, all derivative positions that qualified for hedge accounting were designated on the date the Company entered into the contract as a hedge against the variability in cash flows associated with the forecasted sale of future crude oil production. The cash flow hedges were valued at the end of each period and adjustments to the fair value of the contract prior to settlement were recorded on the statement of stockholders’ equity as other comprehensive income. Upon settlement, the gain (loss) on the cash flow hedge was recorded as an increase or decrease in revenue on the condensed statement of operations. The Company reports average crude oil and natural gas prices and revenues including the net results of hedging activities.
 
The net mark-to-market loss on the Company's remaining swaps that qualified for cash flow hedge accounting at the date the decision was made to discontinue hedge accounting totals approximately $409,000 and $1.3 million as of September 30, 2011 and December 31, 2010, respectively.  The Company has recorded that amount as accumulated other comprehensive income in stockholders' equity and the entire amount will be amortized into revenues as the original forecasted hedged crude oil production occurs in the following periods.
 
 
For the Quarter Ended
 
Commodity
Derivatives
 
December 31, 2011
  $ 307,875  
March 31, 2012
    101,310  
Total
  $ 409,185  

 
17



Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges
 
The Company realized a loss on settled derivatives of $10,695,006 and $1,824,719 and a mark-to-market of derivative gain of $26,675,003 and $27,105,400 on derivative instruments for the nine and three months ended September 30, 2011, respectively.  The Company realized a gain on settled derivatives of $902,946 and $776,010 and a mark-to-market of derivatives loss of $3,189,194 and $6,449,577 on derivative instruments for the nine and three months ended September 30, 2010, respectively.
 
The following table reflects open commodity swap contracts as of September 30, 2011, the associated volumes and the corresponding weighted average NYMEX reference price.
 
Settlement Period
 
Oil (Barrels)
   
Fixed Price
   
Weighted Avg
NYMEX Reference Price
 
Oil Swaps
                 
10/01/11 - 02/29/12
    9,000     $ 51.25     $ 79.46  
10/01/11 - 12/31/11
    4,500       66.15       79.36  
10/01/11 ­- 12/31/11
    12,000       82.60       79.38  
10/01/11 ­- 12/31/11
    4,500       84.25       79.38  
10/01/11 ­- 12/31/11
    13,749       80.90       79.38  
10/01/11 ­- 12/31/11
    22,500       88.00       79.39  
10/01/11 ­- 06/30/12
    150,751       80.00       80.19  
10/01/11 ­- 06/30/12
    302,000       81.50       79.95  
10/01/11 ­- 06/30/12
    87,000       85.50       80.00  
01/01/12 ­- 12/31/12
    376,000       95.15       81.56  
01/01/12 ­- 12/31/12
    240,000       100.00       81.15  

As of September 30, 2011, the Company had a total volume on open commodity swaps of 1,222,000 barrels at a weighted average price of approximately $89.29.

The following table reflects the weighted average price of open commodity swap contracts as of September 30, 2011, by year with associated volumes.

Weighted Average Price
Of Open Commodity Swap Contracts
 
Year
 
Volumes (Bbl)
   
Weighted
Average Price
 
2011
    207,000     $ 81.51  
2012
    1,015,000       90.87  

In addition to the open commodity swap contracts the Company has entered into a costless collar.  The costless collars are used to establish floor and ceiling prices on anticipated crude oil and natural gas production.  There were no premiums paid or received by the Company related to the costless collar agreement.  The Company purchased put options at $85.00 per barrel and sold call options at $101.75 per barrel.  At September 30, 2011 the Company has 108,000 barrels of crude oil collared between $85.00 and $101.75.  The costless collar amounts settle between October 2011 and December 2011.  See Note 16 regarding additional derivative activity subsequent to quarter end.

 
18

 
At September 30, 2011 and December 31, 2010, the Company had derivative financial instruments recorded on the balance sheet as set forth below:
 
Type of Contract
 
Balance Sheet Location
 
September 30, 2011
Estimated Fair Value
   
December 31, 2010 Estimated Fair Value
 
                 
Derivative Assets:
               
Oil Contracts
 
Other current assets
  $ 8,866,037     $ -  
Oil Contracts
 
Other non-current assets
    2,881,377       -  
Total Derivative Assets
      $ 11,747,414     $ -  
                     
Derivative Liabilities:
                   
Oil Contracts
 
Other current assets
  $ (390,487 )   $ (11,145,318 )
Oil Contracts
 
Other non-current liabilities
    -       (5,022,657 )
Total Derivative Liabilities
      $ 11,356,927     $ (16,167,975 )

The following disclosures are applicable to the Company’s financial statements, as of September 30, 2011 and  2010:
 
   
Location of Loss
 
Amount of Loss Reclassified from
 
   
for Effective and
 
AOCI into Income
 
   
Ineffective
 
Three Months Ended
   
Nine Months Ended
 
   
Portion of Derivative
 
September 30,
   
September 30,
 
Derivative Type
 
In Income
 
2011
   
2010
   
2011
   
2010
 
Commodity - Cash Flow
 
Loss on Settled Derivatives
  $ 295,950     $ 309,025     $ 849,900     $ 812,075  

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company has netting arrangements with Macquarie Bank Limited that provide for offsetting payables against receivables from separate derivative instruments.

NOTE 14     COMPREHENSIVE INCOME

In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to shareholders of the Company.

For the periods indicated, comprehensive income consisted of the following:

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Net Income
  $ 28,617,222     $ 987,226     $ 41,992,280     $ 8,667,722  
Unrealized gains on Marketable Securities (net of tax of $109,000 and $459,000 for the nine months ended September 30, 2011 and 2010)
    -       -       173,846       725,981  
Reclassification of derivative instruments included in income (net of tax of $119,000 and $119,000 for the three months ended September 30, 2011 and 2010 and $331,000 and $314,000 for the nine months ended September 30, 2011 and 2010)
    176,950       190,025       518,900       498,075  
Comprehensive income net
  $ 28,794,172     $ 1,177,251     $ 42,685,026     $ 9,891,778  

 
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NOTE 15     COMMITMENTS & CONTINGENCIES
 
Litigation — The Company is engaged in proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to, court rulings, negotiations between affected parties and governmental intervention. Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the consolidated financial position, results of operations or cash flows. Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance.

NOTE 16     SUBSEQUENT EVENTS

In addition to the open commodity swap contracts and costless collars (see Note 13), the Company entered into an additional costless collar on October 28, 2011.  The Company utilizes costless collars to establish floor and ceiling prices on anticipated crude oil and natural gas production.  The Company did not pay or receive any premiums related to the costless collar agreement.  The Company purchased put options at $85.00 per barrel and sold call options at $95.25 per barrel when it initiated the additional costless collar.  As such, at October 31, 2011 the Company had 216,116 barrels of crude oil collared between $85.00 and $95.25 in addition to the Company’s other costless collars in place at September 30, 2011.  These additional costless collar amounts settle between November 2011 and December 2012.

The Company entered into an additional costless collar on November 7, 2011.  The Company purchased put options at $85.00 per barrel and sold call options at $98.00 per barrel when it initiated the additional costless collar.  As such, the Company has 760,794 barrels of crude oil collared between $85.00 and $98.00 in addition to the Company’s other costless collars in place.  These additional costless collar amounts settle between January 2013 and December 2013.
 
In connection with preparing the unaudited financial statements for the nine months ended September 30, 2011, 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, except for what has been disclosed above, which required recognition or disclosure in the financial statements.

 
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Statement Concerning Forward-Looking Statements

This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding future events and our future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”).  All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements.  When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes.  Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our Company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following:  crude oil and natural gas prices, our ability to raise or access capital, general economic or industry conditions, nationally and/or in the communities in which our Company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, other economic, competitive, governmental, regulatory and technical factors affecting our Company’s operations, products and prices.

We have based any forward-looking statements on our current expectations and assumptions about future events.  While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.  Accordingly, results actually achieved may differ materially from expected results described in these statements.  Forward-looking statements speak only as of the date they are made.  You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, as updated by subsequent reports we file with the SEC, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.  Our Company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

Overview and Outlook

As an exploration and production company, our business strategy is to identify and exploit repeatable and scalable resource plays that can be quickly developed at low costs.  We also intend to take advantage of our expertise in aggressive land acquisition to continue to pursue exploration and development projects as a non-operating working interest partner, participating in drilling activities primarily on a heads-up basis proportionate to our working interest.  Our business does not depend upon any intellectual property, licenses or other proprietary property unique to our Company, but instead revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners.  We believe our competitive advantage lies in our ability to acquire property, specifically in the Williston Basin, in a nimble and efficient fashion.

We are focused on maintaining a low cash overhead structure.  We believe we are in a position to most efficiently exploit and identify high production oil and gas properties due to our unique non-operator model through which we are able to diversify our risk and participate in the evolution of technology by the collective expertise of those operators with which we partner.  We intend to continue to carefully pursue the acquisition of properties that fit our profile.

 
21


We control approximately 158,000 net acres in the Williston Basin targeting the Bakken and Three Forks formations.  We have no material lease expirations until the first half of 2012, and continue to expand our position through acquisition and leasing programs.  As of November 4, 2011, we had approximately 58,000 net acres developed or under the bit, which represents approximately 37% of Northern Oil’s total Bakken and Three Forks acreage position at September 30, 2011.

Our average daily production in the third quarter of 2011 was approximately 5,900 BOE per day (“BOEPD”).  September 2011 daily production averaged approximately 7,000 BOEPD.  Third quarter 2011 production consisted of approximately 93% crude oil and 7% associated natural gas and other liquids.

We have maintained a 100% drilling success rate in the Williston Basin Bakken and Three Forks trends since the company’s inception.

Our capital expenditures relating to drilling activities approximated $182 million for the nine months ending September 30, 2011 and are expected to approximate $260 million for the entire 2011 year based on wells currently drilling and expected to spud by 2011 year-end.

Acquisition Activity

During the third quarter of 2011, we acquired leasehold interests covering an aggregate of approximately 6,300  net acres for an average of approximately $1,880  per net acre for an aggregate of $11.8 million.  Of the acquired net acres in the third quarter, approximately 81% was permitted, or spaced for permit at the end of the third quarter of 2011.   For the nine months ended September 30, 2011, we have acquired approximately 30,600 net acres at an aggregate price of $55.7 million, or an average price of approximately $1,820 per net acre.
 
Completion Activity

During the third quarter of 2011, we continued to experience delays in fracture stimulation appointments for wells across all operators with whom we participate.  We believe this trend has been driven primarily by weather delays earlier in the year, and increases in the inventory of wells awaiting fracture stimulation throughout the Williston Basin.  Additionally, constraints in moving fracture stimulation supplies, such as frac sand, into the field have delayed well completions on occasion in the past.  We do not expect that this will affect the pace of drilling.  However, delays in fracture stimulation have the effect of delaying production additions.

Divestiture Activity
 
In November 2009, we agreed to participate in the exploration and development of Slawson’s Anvil project in Roosevelt and Sheridan Counties, Montana and Williams County, North Dakota.  In April 2011, we sold our interest in the Anvil project for $5.0 million along with Slawson, who also desired to sell its entire interest in the project.  As of the date of sale, the Company’s cost basis in the Anvil project was $1.8 million.  Slawson had drilled and completed one well in the project area prior to the divestiture –the Mayhem #1-19H well – and we retained our interest in that wellbore in connection with the divestiture. The proceeds from the sale under the agreement were applied to reduce the capitalized costs of our oil and gas properties.

From time-to-time we may also trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of our acreage.

2011 Drilling Activity

We are participating in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future.  During the third quarter of 2011, we added production from 88 gross (5.7 net) wells.  During the nine months ending September 30, 2011, we added production from 216 gross (17.4 net) wells.  We are currently participating in 201 gross (22.8 net) Bakken or Three Forks wells drilling, awaiting completion or completing in which we are participating with a working interest as of November 4, 2011.

 
22




During the third quarter we spud approximately 9 net wells.  From October 1, 2011 through November 4, 2011, we have spud an additional 5 net wells, bringing the cumulative net wells spud in 2011 to 31 through November 4, 2011.  We reaffirm that we expect to spud at least 40 net wells in 2011.
 
We continue to develop our core Bakken and Three Forks acreage position at an accelerating pace.  According to the North Dakota Industrial Commission, 195 rigs are actively drilling in North Dakota as of November 4, 2011.  Approximately 7 rigs are actively drilling in Montana as of November 4, 2011.  The significant rig increase in the play continues to accelerate the development of Northern Oil’s core acreage position.

As of September 30, 2011, we had a working interest in a total of 705 gross (63.74 net) wells that were either drilling, awaiting completion, completing or producing, consisting of 527 gross (43.6 net) wells producing and 178 gross (20.13 net) wells drilling, awaiting completion or completing.  Permits continue to be issued for spacing units in which we have undeveloped acreage interests within North Dakota and Montana.

Production History
 
The following table presents information about our produced crude oil and natural gas volumes during the three month and nine month periods ended September 30, 2011, compared to the three month and nine month periods ended September 30, 2010.  As of September 30, 2011, we were selling crude oil and natural gas from a total of 527 gross (43.6 net) wells, compared to 256 gross (20.1 net) wells at September 30, 2010.  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2011
   
% Change
   
2010
   
2011
   
% Change
   
2010
 
Net Production:
                                   
Oil (Bbl)
    491,646       104 %     240,717       1,203,057       128 %     526,672  
Natural Gas (Mcf)
    220,298       290 %     56,472       497,131       291 %     127,006  
Barrel of Oil Equivalent (Boe)
    528,362       111 %     250,129       1,285,912       135 %     547,840  
                                                 
Average Sales Prices:
                                               
Oil (per Bbl)
  $ 85.24       28 %   $ 66.42     $ 88.11       29 %   $ 68.13  
Effect of settled oil  derivatives on average price (per Bbl)
    (3.71 )     (215 )%     3.22       (8.89 )     (620 )%     1.71  
Oil net of settled derivatives (per Bbl)
    81.53       17 %     69.64       79.22       13 %     69.85  
Natural Gas and Other Liquids (per Mcf)
    6.03       22 %     4.96       5.69       20 %     4.74  
Effect of natural gas derivatives on average price (per Mcf)
    -       -       -       -       -       -  
Natural gas net of settled derivatives (per Mcf)
    6.03       22 %     4.96       5.69       20 %     4.74  
                                                 
Average Production Costs:
                                               
Oil (per Bbl)
    6.86       60 %     4.28       6.26       66 %     3.76  
Natural Gas (per Mcf)
    0.45       45 %     0.31       0.39       51 %     0.26  
Barrel of Oil Equivalent (per Boe)
    6.57       57 %     4.19       6.00       64 %     3.67  

 
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Depletion of oil and natural gas properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs.  The following table presents our depletion expenses for the three month and nine month periods ended September 30, 2011 compared to the three month and nine month periods ended September 30, 2010.

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Depletion of oil and natural gas properties
  $ 10,749,384     $ 3,767,712     $ 25,962,463     $ 8,252,153  


Productive Oil Wells
 
The following table summarizes gross and net productive oil wells by state at September 30, 2011 and September 30, 2010.  A net well represents our percentage ownership of a gross well.  No wells have been permitted or drilled on any of our Yates County, New York acreage.  The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.

   
September 30,
 
   
2011
   
2010
 
   
Gross
   
Net
   
Gross
   
Net
 
North Dakota
    509       40.50       247       18.35  
Montana
    18       3.10       9       1.75  
Total:
    527       43.60       256       20.10  


Results of Operations for the periods ended September 30, 2010 and September 30, 2011.

Our business activities are focused primarily on developing our current acreage position and identifying potential strategic acreage and production acquisitions to continue to consistently increase production and revenues.

During the nine months ended September 30, 2011, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  Our wells were drilled with a 100% success rate in the Bakken and Three Forks formations during the three months ended September 30, 2011.  As of September 30, 2011, we had established production from 527 total gross wells in which we hold working interests, compared to 256 as of September 30, 2010.  Since inception we have completed 521 gross (42.42 net) Bakken or Three Forks wells, and six gross (1.18 net) exploratory wells as of September 30, 2011.

We recognized $43.7 million in revenues from sales of crude oil and natural gas for the three months ended September 30, 2011, compared to $15.5 million for the three months ended September 30, 2010. We recognized $106.2 million in revenues from sales of crude oil and natural gas for the nine months ended September 30, 2011, compared to $35.6 million for the nine months ended September 30, 2010.  These increases in revenue from sales of crude oil and natural gas are primarily due to our continued addition of wells and an increase in our average realized crude oil prices period-over-period.  We have added wells each quarter since the first quarter of 2008 and, in particular, added production from 5.7 additional net wells during the third quarter of 2011.  During the three months ended September 30, 2011, we realized a $81.53 average price per barrel of crude oil (after the effect of settled oil derivatives), compared to a $69.64 average price per barrel of crude oil (after the effect of settled oil derivatives) during the three months ended September 30, 2010.  During the nine months ended September 30, 2011, we realized a $79.22 average price per barrel of crude oil (after the effect of settled oil derivatives), compared to a $69.85 average price per barrel of crude oil (after the effect of settled oil derivatives) during the nine months ended September 30, 2010.

 
24


We recognized a gain on the mark to market of derivative instruments of $27.1 million and a loss on the mark to market of derivative instruments of $6.4 million for the three months ended September 30, 2011 and 2010. We recognized a gain on the mark to market of derivative instruments of $26.7 million and a loss on the mark to market of derivative instruments of $3.2 million for the nine months ended September 30, 2011 and 2010. The recognized gain on the mark to market of derivative instruments is primarily due to the decrease in oil prices over the three and nine months ended September 30, 2011 relative to our weighted average price of our total derivative position as well as the increase in volumes related to our total derivative position. We realized a loss on settled derivatives of $1.8 million and a gain on settled derivatives of $776,010 for the three months ended September 30, 2011 and 2010. We realized a loss of $10.7 million and a gain of $902,946 for the nine months ended September 30, 2011 and 2010. The gain and loss on the settled derivatives is due to the contract price of our derivative positions relative to the spot price of oil on the settlement date.

We realized net income of $28.6 million (representing approximately $0.46 per diluted share) for the three months ended September 30, 2011 and net income of $987,226 (representing approximately $0.02 per diluted share) for the three months ended September 30, 2010.  We realized net income of $42.0 million (representing approximately $0.68 per diluted share) for the nine months ended September 30, 2011 and net income of $8.7 million (representing approximately $0.18 per diluted share) for the nine months ended September 30, 2010.  These increases in income are primarily due to our continued addition of wells, an increase in our average realized crude oil prices period-over-period and a gain on the mark to market of our derivative instruments, partially offset by settled hedging losses.

Total operating expenses were $23.1 million for the three months ended September 30, 2011, compared to total operating expenses of $8.2 million for the three months ended September 30, 2010.  Total operating expenses were $55.0 million for the nine months ended September 30, 2011, compared to total operating expenses of $18.9 million for the nine months ended September 30, 2010.  These increases in operating expenses are due primarily to increased depletion of oil and gas properties, production expenses, production taxes and general and administrative expenses associated with our continued addition of crude oil and natural gas production from new wells.

During the three months ended September 30, 2011, we had production expenses of $3.9 million compared to production expenses of $1.1 million during the three months ended September 30, 2010.  During the nine months ended September 30, 2011, we had production expenses of $8.5 million compared to production expenses of $1.9 million during the nine months ended September 30, 2010. These increases in production expense are primarily due to the continued addition of wells and the related increase in sales volumes, exposure to new operators and new development areas, an increase in working interests, salt water disposal, mature wells utilizing artificial lift and the general aging of our production.

During the three months ended September 30, 2011, we incurred production taxes of $4.3 million, compared to production taxes of $1.6 million during the three months ended September 30, 2010.  During the nine months ended September 30, 2011, we incurred production taxes of $10.2 million, compared to production taxes of $3.3 million during the nine months ended September 30, 2010. The increase in production taxes is primarily due to the continued addition of producing oil and gas properties and related sales.

We recorded depletion of $10.7 million during the three months ended September 30, 2011, compared to depletion of $3.8 million during the three months ended September 30, 2010.  We recorded depletion of $26.0 million during the nine months ended September 30, 2011, compared to depletion of $8.3 million during the nine months ended September 30, 2010.  These increases in depletion are primarily due to the addition of proven properties subject to the depletion calculation as well as the continued addition of producing oil and gas properties.  Depletion expense for the three months ended September 30, 2011, was $20.34 per BOE, compared to $15.06 per BOE, for the three months ended September 30, 2010.  Depletion expense for the nine months ended September 30, 2011, was $20.19 per BOE, compared to $15.06 per BOE, for the nine months ended September 30, 2010. These increases in depletion per BOE are primarily attributed to the increase in acreage and well development costs relative to the increase in our proved reserves.

 
25


We had general and administrative expenses of $4.1 million and $1.6 million during the three months ended September 30, 2011 and 2010, which included $1.9 million and $899,661 net of share based compensation expense, respectively. We had general and administrative expenses of $10.1 million and $5.2 million during the nine months ended September 30, 2011 and 2010, which included $4.6 million and $2.5 million net of share based compensation expense, respectively.   The increases in general and administrative expenses are primarily due to the increase in share based compensation, headcount, and professional service fees.

Use of Non-GAAP Financial Measures

Our non-GAAP net income which excludes unrealized mark-to-market hedging gains and losses net of tax, was $11.9 million (representing approximately $0.19 per diluted share) for the three months ended September 30, 2011, as compared to $4.9 million (representing approximately $0.09 per diluted share) in the quarter ended September 30, 2010.  Our non-GAAP net income which excludes unrealized mark-to-market hedging gains and losses net of tax, was $25.5 million (representing approximately $0.41 per diluted share) for the nine months ended September 30, 2011, as compared to $10.6 million (representing approximately $0.22 per diluted share) in the nine months ended September 30, 2010.  These increases in non-GAAP net income are primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices period over period.

We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) accretion of abandonment liability, (v) pre-tax unrealized gain and loss on the mark to market of derivative instruments and (vii) non-cash expenses relating to share based payments recognized under ASC Topic 718.  Adjusted EBITDA for the three months ended September 30, 2011 was $31.9 million (representing approximately $0.51 per diluted share), compared to Adjusted EBITDA of $12.8 million (representing approximately $0.24 per diluted share) for the third quarter of 2010.  Adjusted EBITDA for the nine months ended September 30, 2011 was $73.2 million (representing approximately $1.18 per diluted share), compared to Adjusted EBITDA of $28.9 million (representing approximately $0.59 per diluted share) for the nine months ended September 30, 2010.  These increases in Adjusted EBITDA are primarily due to our continued addition of crude oil and natural gas production from new wells and higher realized commodity prices period over period.

We believe the use of non-GAAP financial measures provides useful information to investors to gain an overall understanding of our current financial performance.  Specifically, we believe the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that our management believes are not indicative of our core operating results.  In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes.  We consider these non-GAAP measures to be useful in evaluating our core operating results as they more closely reflect our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities.  Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.

The non-GAAP financial information is presented using consistent methodology from quarter-to-quarter.  These measures should be considered in addition to results prepared in accordance with GAAP.  In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles.  We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.
Net income excluding unrealized mark-to-market hedging gains (losses) and Adjusted EBITDA are non-GAAP measures.  A reconciliation of these measures to GAAP is included below:

 
26


USE OF NON GAAP FINANCIAL MEASURES

Northern Oil and Gas, Inc.
Reconciliation of GAAP Net Income to Non-GAAP Net Income Excluding
Unrealized Mark-to-Market Hedging Gains and Losses

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Net Income
  $ 28,617,222     $ 987,226     $ 41,992,280     $ 8,667,722  
                                 
Mark-to-Market of Derivative Instruments
    (27,105,400 )     6,449,577       (26,675,003 )     3,189,194  
                                 
Tax Impact
    10,339,000       (2,516,000 )     10,171,000       (1,244,000 )
                                 
Net Income without Effect of Certain Items
  $ 11,850,822     $ 4,920,803     $ 25,488,277     $ 10,612,916  
                                 
Net Income Per Common Share - Basic
  $ 0.19     $ 0.10     $ 0.41     $ 0.22  
                                 
Net Income Per Common Share - Diluted
  $ 0.19     $ 0.09     $ 0.41     $ 0.22  
                                 
Weighted Average Shares Outstanding - Basic
    61,919,641       51,519,732       61,708,537       48,544,749  
                                 
Weighted Average Shares Outstanding - Diluted
    62,265,502       52,145,181       62,114,115       49,127,706  
                                 
Net Income Per Common Share - Basic
  $ 0.46     $ 0.02     $ 0.68     $ 0.18  
                                 
Change due to Mark-to-Market of Derivative Instruments
    (0.44 )     0.13       (0.43 )     0.07  
                                 
Change due to Tax Impact
    0.17       (0.05 )     0.16       (0.03 )
                                 
Net Income without Effect of Certain Items Per Common Share - Basic
  $ 0.19     $ 0.10     $ 0.41     $ 0.22  
                                 
Net Income Per Common Share - Diluted
  $ 0.46     $ 0.02     $ 0.68     $ 0.18  
(As Reported)
                               
                                 
Change due to Mark-to-Market of Derivative Instruments
    (0.44 )     0.12       (0.43 )     0.07  
                                 
Change due to Tax Impact
    0.17       (0.05 )     0.16       (0.03 )
                                 
Net Income without Effect of Certain Items Per Common Share - Diluted
  $ 0.19     $ 0.09     $ 0.41     $ 0.22  

 
27


Northern Oil and Gas, Inc.
Reconciliation of Adjusted EBITDA

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Net Income
  $ 28,617,222     $ 987,226     $ 41,992,280     $ 8,667,722  
                                 
Add Back:
                               
                                 
Income Tax Provision
    17,173,000       620,000       25,725,300       5,430,000  
                                 
Depreciation, Depletion, Amortization, and Accretion
    10,832,762       3,846,037       26,196,973       8,394,127  
                                 
Share Based Compensation
    2,188,900       724,410       5,552,245       2,730,779  
                                 
Mark-to-Market of Derivative Instruments
    (27,105,400 )     6,449,577       (26,675,003 )     3,189,194  
                                 
Interest Expense
    182,499       145,182       425,687       455,704  
                                 
Adjusted EBITDA
  $ 31,888,983     $ 12,772,432     $ 73,217,482     $ 28,867,526  
                                 
Adjusted EBITDA Per Common Share - Basic
  $ 0.52     $ 0.25     $ 1.19     $ 0.59  
                                 
Adjusted EBITDA Per Common Share - Diluted
  $ 0.51     $ 0.24     $ 1.18     $ 0.59  
                                 
Weighted Average Shares Outstanding - Basic
    61,919,641       51,519,732       61,708,537       48,544,749  
                                 
Weighted Average Shares Outstanding - Diluted
    62,265,502       52,145,181       62,114,115       49,127,706  

 
28


Northern Oil and Gas, Inc.
Reconciliation of Adjusted EBITDA Per Common Share - Basic

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Net Income Per Common Share - Basic
  $ 0.46     $ 0.02     $ 0.68     $ 0.18  
(As Reported)
                               
                                 
Add Back:
                               
                                 
Income Tax Provision
    0.28       0.01       0.42       0.11  
                                 
Depreciation, Depletion, Amortization,and Accretion
    0.18       0.08       0.42       0.17  
                                 
Share Based Compensation
    0.04       0.01       0.09       0.06  
                                 
Mark-to-Market of Derivative Instruments
    (0.44 )     0.13       (0.43 )     0.06  
                                 
Interest Expense
    0.00       0.00       0.01       0.01  
                                 
Adjusted EBITDA Per Common Share - Basic
  $ 0.52     $ 0.25     $ 1.19     $ 0.59  
(Adjusted for Non-GAAP Measurements)
                               

Northern Oil and Gas, Inc.
Reconciliation of Adjusted EBITDA Per Common Share - Diluted

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Net Income Per Common Share - Diluted
  $ 0.46     $ 0.02     $ 0.68     $ 0.18  
(As Reported)
                               
                                 
Add Back:
                               
                                 
Income Tax Provision
    0.28       0.01       0.41       0.11  
                                 
Depreciation, Depletion, Amortization, and Accretion
    0.17       0.08       0.42       0.17  
                                 
Share Based Compensation
    0.04       0.01       0.09       0.06  
                                 
Mark-to-Market Derivative Instruments
    (0.44 )     0.12       (0.43 )     0.06  
                                 
Interest Expense
    0.00       0.00       0.01       0.01  
                                 
Adjusted EBITDA Per Common Share - Diluted
  $ 0.51     $ 0.24     $ 1.18     $ 0.59  
(Adjusted for Non-GAAP Measurements)
                               

 
29


Liquidity and Capital Resources

We have historically met our capital requirements through the issuance of common stock and by borrowings.  In the future, we anticipate we will be able to provide the necessary liquidity by the revenues generated from the sales of our crude oil and natural gas reserves in our existing properties, credit facility borrowings and potential equity issuances.  However there is no guarantee the capital markets will be available to us on favorable terms or at all.

The following table summarizes total current assets, total current liabilities and working capital at September 30, 2011.

Current Assets
  $ 90,066,570  
Current Liabilities
  $ 58,029,958  
Working Capital
  $ 32,036,612  

Credit Facility with Macquarie Bank Limited

On May 26, 2010, we completed the closing of the assignment of our revolving credit facility to Macquarie Bank Limited (“Macquarie”) from CIT Capital USA Inc., and entered into an amended credit agreement in connection with such assignment.  On August 8, 2011, we entered into a second amended and restated credit agreement (the “Restated Credit Agreement”) governing the credit facility with Macquarie (the “Credit Facility”).  The Credit Facility now provides that the aggregate maximum credit amount may be increased in the future to up to $500 million.  The Restated Credit Agreement provides for an initial borrowing base of $150 million, subject to the aggregate maximum credit amount then in effect.  The aggregate maximum credit amount is currently $100 million.  Such aggregate maximum credit amount may be increased, subject to various conditions, but in no event to more than $500 million.  One of the conditions to any such increase would be an additional commitment of such funds by Macquarie or another lender.  Financing available under the facility is equal to the lesser of the aggregate maximum credit amount and the borrowing base.

The Credit Facility may be used to provide working capital for exploration and production operations.  The Credit Facility has a four year term and does not contain any minimum interest rate on borrowings.  Borrowings, if any, will bear interest at a spread ranging from 2.0% to 3.25% over the London Interbank Offered Rate (LIBOR) or prime rate, as the case may be, based upon the percentage of borrowing base that is advanced at any given time.

As of September 30, 2011, we had $15 million in borrowings outstanding under the Credit Facility.

All of our obligations under the Credit Facili