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 June 30, 2010
 
 
£ 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 £  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 August 6, 2010, there were 51,537,329 shares of our common stock, par value $0.001, outstanding.

 
 

 

NORTHERN OIL AND GAS, INC.
FORM 10-Q

June 30, 2010

C O N T E N T S

   
Page
 
PART I
     
       
Item 1.                     Financial Statements
    2  
Condensed Balance Sheets
    2  
Condensed Statements of Operations
    4  
Condensed Statements of Cash Flows
    5  
Notes to Unaudited Condensed Financial Statements
    6  
         
Item 2.                    Management’s Discussion and Analysis of Financial Condition and Results of Operations
    22  
         
Item 3.                     Quantitative and Qualitative Disclosures about Market Risk
    29  
         
Item 4.                     Controls and Procedures
    30  
         
PART II
       
         
Item 1.                      Legal Proceedings
    31  
         
Item 1A.                  Risk Factors
    31  
         
Item 2                       Unregistered Sales of Equity Securities and Use of Proceeds
    31  
         
Item 6.                      Exhibits
    31  
         
Signatures
    32  



 
 

 

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

NORTHERN OIL AND GAS, INC.
CONDENSED BALANCE SHEETS
JUNE 30, 2010 AND DECEMBER 31, 2009


ASSETS

   
June 30,
     
   
2010
   
December 31,
   
(UNAUDITED)
   
2009
 CURRENT ASSETS                
 Cash and Cash Equivalents
  $ 70,167,911     $ 6,233,372  
 Trade Receivables
    11,311,742       7,025,011  
 Prepaid Drilling Costs
    6,431,446       1,454,034  
 Prepaid Expenses
    481,371       143,606  
 Other Current Assets
    272,392       201,314  
 Short - Term Investments
    -       24,903,476  
 Derivative Asset
    1,068,924       -  
 Deferred Tax Asset
    863,000       2,057,000  
 Total Current Assets
    90,596,786       42, 017,813  
                 
 PROPERTY AND EQUIPMENT
               
 Oil and Natural Gas Properties, Full Cost Method (including unevaluated cost of
               
 $86,422,227 at 6/30/2010 and $53,862,529 at 12/31/2009)
    156,185,056       96,801,626  
 Other Property and Equipment
    2,193,447       439,656  
 Total Property and Equipment
    158,378,503       97,241,282  
 Less - Accumulated Depreciation and Depletion
    9,626,536       5,091,198  
 Total Property and Equipment, Net
    148,751,967       92,150,084  
                 
 DEBT ISSUANCE COSTS
    1,525,703       1,427,071  
                 
 Total Assets
  $ 240,874,456     $ 135,594,968  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 CURRENT LIABILITIES
         
 Accounts Payable
  $ 9,987,487      $ 6,419,534   
 Line of Credit
    -       834,492   
 Accrued Expenses
    1,938,696       316,977   
 Derivative Liability
    -       1,320,679   
 Other Liabilities
    18,574       18,574   
 Total Current Liabilities
    11,944,757       8,910,256   
                 

 
2

 


 LONG-TERM LIABILITIES
           
 Revolving Credit Facility
    -       -  
 Derivative Liability
    85,544       1,459,374  
 Subordinated Notes
    400,000       500,000  
 Other Noncurrent Liabilities
    315,727       243,888  
 Total Long-Term Liabilities
    801,271       2,203,262  
 
               
 DEFERRED TAX LIABILITY
    5,192,000       922,000  
                 
 Total Liabilities
    17,938,028       12,035,518  
                 
 STOCKHOLDERS' EQUITY
               
 Common Stock, Par Value $.001; 100,000,000 Authorized, 51,079,143
               
 Outstanding (2009 – 43,911,044 Shares Outstanding)
    51,080       43,912  
 Additional Paid-In Capital
    215,539,549       124,884,266  
 Retained Earnings
    8,522,388       841,892  
 Accumulated Other Comprehensive Income (Loss)
    (1,176,589 )     (2,210,620 )
 Total Stockholders' Equity
    222,936,428       123,559,450  
                 
 Total Liabilities and Stockholders' Equity
  $ 240,874,456     $ 135,594,968  
                 
 The accompanying notes are an integral part of these condensed financial statements.
               
                 






 
3

 

NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010 AND 2009
(UNAUDITED)

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
         
2009
         
2009
 
   
2010
   
Adjusted *
   
2010
   
Adjusted *
 
REVENUES
                       
Oil and Gas Sales
  $ 11,664,873     $ 2,418,496     $ 20,033,720     $ 3,059,230  
Gain (Loss) on Settled Derivatives
    303,919       (143,412 )     126,936       (125,878 )
Mark-to-Market of Derivative Instruments
    4,251,199       -       3,260,383       -  
Other Revenue
    11,782       -       32,248       -  
      16,231,773       2,275,084       23,453,287       2,933,352  
                                 
OPERATING EXPENSES
                               
Production Expenses
    561,427       119,751       893,757       214,140  
Production Taxes
    1,024,277       189,400       1,670,143       247,715  
General and Administrative Expense
    718,471       519,014       1,612,142       910,674  
Share Based Compensation
    1,193,072       36,302       2,006,369       213,277  
Depletion of Oil and Gas Properties
    2,600,836       548,124       4,484,441       850,326  
Depreciation and Amortization
    26,267       22,777       50,897       45,456  
Accretion of Discount on Asset Retirement Obligations
    9,215       2,077       12,752       3,471  
Total Expenses
    6,133,565       1,437,445       10,730,501       2,485,059  
                                 
INCOME FROM OPERATIONS
    10,098,208       837,639       12,722,786       448,293  
                                 
OTHER EXPENSE
    (144,342 )     (139,243 )     (232,290 )     (182,770 )
                                 
INCOME BEFORE INCOME TAXES
    9,953,866       698,396       12,490,496       265,523  
                                 
INCOME TAX PROVISION
    3,833,000       280,000       4,810,000       106,000  
                                 
NET INCOME
  $ 6,120,866     $ 418,396     $ 7,680,496     $ 159,523  
                                 
                                 
Net Income Per Common Share - Basic
  $ 0.12     $ 0.01     $ 0.16     $ 0.00  
                                 
Net Income Per Common Share - Diluted
  $ 0.12     $ 0.01     $ 0.16     $ 0.00  
                                 
Weighted Average Shares Outstanding – Basic
    49,934,409       34,582,282       47,032,602       34,404,093  
                                 
Weighted Average Shares Outstanding - Diluted
    50,609,944       34,741,036       47,593,962       34,484,966  
                                 
*See Note 2
                               
                                 
The accompanying notes are an integral part of these condensed financial statements.
                 

 
4

 

NORTHERN OIL AND GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2010 AND 2009
(UNAUDITED)


   
Six Months Ended
   
June 30,
         
   
2010
 
 2009
Adjusted*
 CASH FLOWS FROM OPERATING ACTIVITIES
       
 Net Income
  $ 7,680,496     $ 159,523
 Adjustments to Reconcile Net Income to Net Cash Provided by
             
 Operating Activities:
             
    Depletion of Oil and Gas Properties
    4,484,441       850,326
    Depreciation and Amortization
    50,897       45,456
    Amortization of Debt Issuance Costs
    280,768       168,790
    Accretion of Discount on Asset Retirement Obligations
    12,752       3,471
    Income Tax Provision
    4,810,000       106,000
    Loss on Sale of Available for Sale Securities
    197,556       -
    Market Value adjustment of Derivative Instruments
    (3,260,383 )     -
    Amortization of Deferred Rent
    (9,287 )     (9,286
    Share - Based Compensation Expense
    2,006,369       213,277
 Changes in Working Capital and Other Items:
             
    Increase in Trade Receivables
    (4,286,731 )     (775,192
    Increase in Prepaid Expenses
    (337,765 )     (44,892
    Decrease (Increase) in Other Current Assets
    71,078       -
    Increase in Accounts Payable
    3,567,953       2,585,014
    Decrease in Accrued Expenses
    (138,281 )     (934,162
    Net Cash Provided By Operating Activities
    14,987,707       2,368,325
               
 CASH FLOWS FROM INVESTING ACTIVITIES
             
 Purchases of Other Equipment and Furniture
    (1,753,791 )     (6,943
 Decrease (Increase) in Prepaid Drilling Costs
    (4,977,412 )     19
 Proceeds from Sale of Oil and Gas Properties
    237,877       -
 Proceeds from Sale of Available for Sale Securities
    25,890,901       -
 Increase in Oil and Gas Properties
    (51,636,851 )     (17,506,249
    Net Cash Used For Investing Activities
    (32,239,276 )     (17,513,173
               
 CASH FLOWS FROM FINANCING ACTIVITIES
             
 Payments on Line of Credit
    (834,492 )     (12,338
 Advances on Revolving Credit Facility
    5,300,000       16,000,000
 Payments on Revolving Credit Facility
    (5,300,000 )     -
 Increase (Decrease) in Subordinated Notes, net
    (100,000 )     500,000
 Debt Issuance Costs Paid
    (379,400 )     (1,190,061
 Proceeds from Issuance of Common Stock - Net of Issuance Costs
    82,500,000       12,701,049
    Net Cash Provided by Financing Activities
    81,186,108       27,998,650
               
 NET INCREASE IN CASH AND CASH EQUIVALENTS
    63,934,539       12,853,802
               
 CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD
    6,233,372       780,716
               
 CASH AND CASH EQUIVALENTS – END OF PERIOD
  $ 70,167,911     $ 13,634,518
               
               
 Supplemental Disclosure of Cash Flow Information
             
 Cash Paid During the Period for Interest
  $ 125,135     $ 189,128
 Cash Paid During the Period for Income Taxes
  $ -     $ -
               
 Non-Cash Financing and Investing Activities:
             
     Purchase of Oil and Gas Properties through Issuance of Common Stock
  $ 5,698,337     $ 224,879
     Payment of Compensation through Issuance of Common Stock
  $ 4,224,114     $ 261,280
     Capitalized Asset Retirement Obligations
  $ 69,802     $ 61,403
     Fair Value of Warrants Issued for Debt Issuance Costs
  $ -     $ 221,153
     Payment of Debt Issuance Costs through Issuance of Common Stock
  $ -     $ 475,200
               
* See Note 2
             
               
The accompanying notes are an integral part of these condensed financial statements.
     
               

 
 
5

 

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
JUNE 30, 2010
(Unaudited)

NOTE 1     ORGANIZATION AND NATURE OF BUSINESS

Northern Oil and Gas, Inc. (the “Company,” “we,” “us,” “our” and words of similar import) is a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of 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 oil and gas acreage and drilling projects, primarily within the Williston Basin Bakken Shale formation. The Company has begun to develop its substantial leasehold acreage in the Bakken play and will target additional opportunities in emerging plays utilizing its first mover leasing advantage.   The Company owns working interests in wells, and does not lease land to operators.  We believe the advantage gained by participating as a non-operating partner has given us valuable data on completions and will help our operating partners control well costs and enhance results as we continue to develop our higher working interest sections in the remainder of 2010 and beyond.
 
The Company participates on a heads up basis proportionate to its working interest in declared drilling units with working interests ranging from approximately 0.5% to 63%.  As of June 30, 2010, we controlled approximately 109,913 net acres in the Williston Basin targeting the Bakken and Three Forks formations.  As of August 9, 2010, we control approximately 115,700 net mineral acres in the Williston Basin targeting the Bakken and Three Forks formations, which provides the potential to drill approximately 1,085 net wells using 640 acre spacing units assuming three horizontal Bakken and three horizontal Three Forks wells per spacing unit.  We have no material lease expirations until late 2011 and continue to expand our position through aggressive acquisition and leasing programs.

Our 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 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 oil and gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent on prevailing prices of crude oil and natural gas.  Historically, the energy markets have been very volatile and it is likely that oil and gas prices will continue to be subject to wide fluctuations in the future.  A substantial or extended decline in crude oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital, and on the quantities of natural gas and oil reserves that can be economically produced.

 
NOTE 2     SIGNIFICANT ACCOUNTING POLICIES

The financial information included herein is unaudited, except the balance sheet as of December 31, 2009, which has been derived from our audited financial statements as of December 31, 2009.  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.  The financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2009, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

 
6

 
 
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.  Our cash positions represent assets held in checking and money market accounts.  These assets are generally available to us on a daily or weekly basis and are highly liquid in nature.  Due to the balances being greater than $250,000, we do not have FDIC coverage on the entire amount of bank deposits.  The Company believes this risk is minimal.  In addition, we are subject to Security Investor Protection Corporation (SIPC) protection on a vast majority of our financial assets.

Short-Term Investments

All marketable debt and equity securities and 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).  There are no unrealized gains and losses included in accumulated other comprehensive income (loss) as of June 30, 2010, as the Company has no short-term investments.  When securities are sold, their cost is determined based on the first-in first-out method.  The realized gains and losses related to these securities are included in other expense in the statements of operations.

Other Property and Equipment

Property and equipment that are not oil and 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 oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  We have not recognized any impairment losses on non oil and gas long-lived assets.  Depreciation expense was $50,897 for the six months ended June 30, 2010.

Debt Issuance Costs

In February 2009, the Company entered into a revolving credit facility with CIT Capital USA, Inc. (“CIT”) (See Note 9).  The Company incurred costs related to this facility that were capitalized on the Balance Sheet as Debt Issuance Costs.  Included in the Debt Issuance Costs are direct costs paid to third parties for broker fees and legal fees, 180,000 shares of restricted common stock paid as additional compensation for broker fees, and the fair value of 300,000 warrants issued to CIT.  The fair value of the warrants was calculated using the Black-Scholes valuation model based on factors present at the time of closing.  CIT can exercise these warrants at any time until the warrants expire in February 2012.  The exercise price of the warrants is $5.00 per warrant.  The total amount capitalized for Debt Issuance Costs is $1,670,000 related to the original agreement with CIT.  In May 2009, the Company amended the revolving credit facility with CIT to allow for additional borrowings.  The Company incurred and capitalized $216,414 of direct costs related to this amendment.

In May 2010, the Company completed an assignment of its revolving credit facility to Macquarie Bank Limited (“Macquarie”) from CIT.  In connection with the assignment, the Company and Macquarie entered into an Amended and Restated Credit Agreement governing the facility.  The Company incurred and capitalized $379,400 of direct costs related to this assignment and amendment.

The remaining capitalized costs from the original February 2009 agreement and the May 2009 amendment to the agreement and the additional costs from the assignment and amendment of the facility in May 2010 are being amortized over the remaining term of the amended facility using the effective interest method.

The amortization of debt issuance costs for the six months ended June 30, 2010 was $280,768.  

 
7

 

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 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 Gas Balancing

We recognize oil and gas revenues from our 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.  We use the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation.  As of June 30, 2010 and December 31, 2009, our gas production was in balance, meaning our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (“ASC”) 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment). This standard requires us to record an expense associated with the fair value of stock-based compensation.  We use 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.

Income Taxes

The Company accounts for income taxes under FASB ASC 740-10-30 (Prior authoritative literature, FASB Statement 109, Accounting for 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.

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 on the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in FASB ASC 505-50-30 (Prior authoritative literature, EITF 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring or in Conjunction with Selling, Goods, or Services).

Net Income (Loss) 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, warrants, and restricted stock.  The number of potential common shares outstanding relating to stock options, warrants, and restricted stock is computed using the treasury stock method.
 

 
8

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2010 and 2009 are as follows (in thousands):


   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Weighted average common shares outstanding - basic
    49,934,409       34,582,282       47,032,602       34,404,093  
Plus: Potentially dilutive common shares
                               
Stock options, warrants, and restricted stock
    675,534       158,754       561,359       80,873  
Weighted average common shares  outstanding - diluted
    50,609,944       34,741,036       47,593,962       34,484,966  
Stock options and warrants excluded from EPS due to the anti-dilutive effect
    -       -       -       62,529  

As of June 30, 2010 there were 300,000 potentially dilutive shares from stock options that became exercisable in 2007.

In addition, as of June 30, 2010, there were 300,000 warrants that were issued in conjunction with the February 2009 revolving credit facility with CIT that remained outstanding and exercisable.  These warrants are presently exercisable and represent potentially dilutive shares.  Each of these warrants has an exercise price of $5.00.

The remaining potential dilutive shares are the result of applying the Codification requirements to unamortized compensation in accordance with the treasury stock method.

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and 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 $2,771,704 of internal costs and $59,711 of interest and fees for the six months ended June 30, 2010.

As of June 30, 2010 we controlled acreage in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. We controlled acreage in North Dakota targeting the Bakken Shale and Three Forks/Sanish as well as acreage in Yates County, New York that is prospective for Marcellus Shale and Trenton-Black River natural gas production.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In March 2010, we entered into an agreement to sell wellbore interests in certain wells where our net working interest is less than one-half of one percent (0.5%) of all working interests in such wells.  The transaction was entered into in March 31, 2010, and the initial divestitures pursuant to the transaction were effective December 31, 2009. Estimated proceeds from the transaction are approximately $238,000.  The proceeds for this agreement were applied to reduce the capitalized costs of oil and gas properties.


 
9

 

Capitalized costs associated with impaired properties and capitalized cost related to properties having proved reserves, plus the estimated future development costs, asset retirement costs under FASB ASC 410-20-25 (Prior
authoritative literature: FASB Statement 143, Accounting for Asset Retirement Obligations) are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers.  The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. As of June 30, 2010, the Company included $765,037 of costs related to expired leases in Sheridan County, Montana and Yates County, New York, which costs are subject to depletion calculation.

Capitalized costs of oil and 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 oil and gas reserves plus the cost of unevaluated 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 oil and natural gas based on the prices in effect at the beginning of each month to estimated future production of proved oil and 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. To this point the Company has not realized any impairment of its properties due to our low basis in the acreage and productivity and economics of our producing wells. 

Use of Estimates

The preparation of 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 oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, fair value of derivative instruments, and deferred income taxes.  Actual results may differ from those estimates.
 
Reclassifications

Certain reclassifications have been made to prior periods’ reported amounts in order to conform with the current year presentation. These reclassifications did not impact our net income, stockholders’ equity or cash flows.

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 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 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 oil at a future date.

At the inception of a derivative contract, the Company historically 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.  See Note 14 for a description of the derivative contracts which the Company executed during 2010.

 
10

 

Derivatives, historically, are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction.  The Company’s derivatives historically consist primarily of cash flow hedge transactions in which the Company is 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 other comprehensive income and reclassified to earnings in the periods in which the contracts are settled.  The ineffective portion of the cash flow hedges was reflected in current period earnings as gain or loss from derivative.  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 are reported as cash flows from operating activities.

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 under FASB ASC 815-20-25 (Prior authoritative literature: FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities).  As such, 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 and unrealized gains or losses are recorded as gain (loss) on derivatives net, as an increase or decrease in revenues on the Statement of Operations rather than as a component of other comprehensive income (loss) or other Income (expense).

Impairment

FASB ASC 360-10-35-21 (Prior authoritative literature: FASB Statement 144, Accounting for the Impairment and Disposal of Long-Lived Assets), requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Oil and gas properties accounted for using the full cost method of accounting (which we use) are excluded from this requirement but continue to be subject to the full cost method’s impairment rules.  

Change in Accounting Principle Related to Drilling Costs

In 2009, the Company changed its method of accounting for drilling costs from the accrual of drilling costs at the time drilling commenced for a well to recording the costs when amounts are invoiced by operators.  Recording drilling costs when the amounts are invoiced by operators is deemed preferable as it better represents the Company’s actual drilling costs.  The recording of drilling costs in this method also is consistent with other companies in the oil and gas industry.  Generally accepted accounting principles require that the impact of the change in accounting be applied retrospectively to all periods presented.  As a result, all prior period financial statements have been adjusted to give effect to the cumulative impact of this change.

The following table shows the effect on the Company’s Statement of Operations:

   
Three Months Ended
June 30, 2009
 
Six Months Ended
June 30, 2009
 
   
As
Reported
   
Adjusted
   
Effect of Change
 
As
Reported
   
Adjusted
   
Effect of Change
 
Depletion Expense
719,596
 
548,124
 
(171,472)
  $
1,101,250
    $
850,326
    $
(250,924)
 
Income Tax Provision
 
211,000
   
280,000
   
69,000
   
6,000
     
106,000
     
100,000
 
Net Income
315,924
 
418,396
 
102,472
  $
8,599
    $
159,523
    $
150,924
 
Earnings Per Share – Basic and Diluted
0.01
 
0.01
 
0.00
  $
0.00
    $
0.00
    $
0.00
 


 
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The following table shows the effect on the Company’s Statement of Cash Flows:

   
Six Months Ended
June 30, 2009
 
   
As
Reported
   
Adjusted
   
Effect of
Change
 
Net Income
  $ 8,599     $ 159,523     $ 150,924  
Depletion of Oil and Gas Properties
    1,101,250       850,326       (250,924 )
Income Tax Provision
    6,000       106,000       100,000  
Decrease in Accrued Drilling Costs
    (181,900 )     -       181,900  
Increase in Oil and Gas Properties
    (17,324,349 )     (17,506,249 )     (181,900 )

New Accounting Pronouncements

In February 2010, the FASB issued ASU 2010-09, "Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements."  ASU 2010-09 requires an entity that is a filer with the United States Securities and Exchange Commission (the “SEC”) to evaluate subsequent events through the date that the financial statements are issued and removes the requirement that an SEC filer disclose the date through which subsequent events have been evaluated. ASC 2010-09 was effective upon issuance.  The adoption of this standard had no effect on our results of operation or our financial position.

In April 2010, the FASB issued ASU 2010-13, "Compensation - Stock Compensation (Topic 718) - Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades." ASU 2010-13 provides amendments to Topic 718 to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity's equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The amendments in ASU 2010-13 are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The adoption of this standard will not have an effect on our results of operation or our financial position.
 
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 marketable debt and equity securities and 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).   When securities are sold, their cost is determined based on the first-in first-out method.  The realized gains and losses related to these securities are included in other income in the statements of operations.  For the six months ended June 30, 2010, we realized losses of $197,556 on the sale of short-term investments.

The Company has no short-term investments as of June 30, 2010.
  
 

 
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NOTE 4     PROPERTY AND EQUIPMENT

Property and equipment at June 30, 2010 consisted of the following:

   
June 30,
2010
 
Oil and Gas Properties, Full Cost Method
     
Unevaluated Costs, Not Subject to Amortization or Ceiling Test
  $ 86,939,327  
Evaluated Costs
    69,245,729  
      156,185,056  
Other Property and Equipment
    2,193,447  
      158,378,503  
Less: Accumulated Depreciation, Depletion and Amortization
       
Property and Equipment
    9,626,536  
Total
  $ 148,751,967  

The following table shows depreciation, depletion, and amortization expense by type of asset:


   
Six Months
Ended June 30,
 
   
2010
   
2009
Adjusted
 
Depletion of Costs for Evaluated Oil and Gas Properties
  $ 4,484,441     $ 850,326  
Depreciation of Other Property and Equipment
    50,897       45,456  
Total Depreciation, Depletion, and Amortization Expense
  $ 4,535,338     $ 895,782  


NOTE 5     OIL AND GAS PROPERTIES

North Dakota Acquisitions

In the second quarter of 2010 the Company acquired approximately 16,861 net mineral acres in all of our key prospect areas in the form of both effective leases and top-leases.  Of the approximate 16,861 net mineral acres acquired approximately 5,800 net mineral acres were acquired organically.  The Company spent an average of approximately $1,015 per net mineral acre acquired in the second quarter of 2010.
JAG Oil Limited Partnership and G.G. Rose, L.L.C. Acreage Acquisition

In June of 2010 the Company acquired approximately 3,498.47 net acres for $1,750 per net acre in Williams and McKenzie Counties of North Dakota.  The Company issued shares of its common stock and $761,463 to JAG Oil Limited Partnership and G.G. Rose, L.L.C. in consideration for the acreage.
 

NOTE 6     PREFERRED AND COMMON STOCK

The Company’s Articles of Incorporation authorize the issuance of up to 5,000,000 shares of preferred stock, par value $0.001 per share.  Our 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 2010, the Company agreed to issue 4,000 shares of Common Stock to two employees of the Company.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was $50,280 or $12.57 per share, based upon the market value of one share of our common stock on the date the stock was obligated to be issued.  The entire amount of this stock award was expensed in the three months ended March 31, 2010.
  

 
13

 

In January 2010, the Company agreed to issue 1,000 shares of Common Stock to a consultant of the Company.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was $12,320 or $12.32 per share, based upon the market value of one share of common stock on the date the stock was obligated to be issued.  The entire amount of this stock award was expensed in the three months ended March 31, 2010.

In March 2010, the Company issued 10,287 shares of Common Stock as part of an acquisition of leasehold interests in North Dakota. The fair value of the stock issued was $99,475 or $9.67 per share, based upon the market value of one share of common stock on the date the leasehold interests were acquired.

In March 2010, pursuant to employment agreements the Company issued 50,000 shares of Common Stock to executives of the Company.  The shares were fully vested on the date of the grant.  The fair value of the stock issued was $664,500 or $13.29 per share, based upon the market value of one share of common stock on the date the stock was obligated to be issued.  The Company expensed $307,331 in share-based compensation related to the issuance for the three month period ended March 31, 2010. The remainder of the expense was capitalized into the full cost pool.

In April 2010, the Company entered into an underwriting agreement to sell 5,750,000 shares of common stock at a price of $15.00 less an underwriting discount of $0.60 per share for total gross proceeds of $82.8 million.  The Company incurred costs of $300,000 related to this offering.  These costs were netted against the proceeds of the offering through Additional Paid-In Capital.

On June 14, 2010, the Company issued 382,645 shares of Common Stock as part of an acquisition of leasehold interests in North Dakota.  The fair value of the stock issued was $5,360,856 or $14.01 per share, based upon the market value of one share of common stock on the date the shares were registered with the SEC for resale, which is the date the leasehold interests were acquired.

On June 18, 2010, the Company granted 14,167 shares of Common Stock related to acquisitions of leasehold interests in North Dakota.  The fair value of the stock granted was $238,006 or $16.80 per share, based upon the market value of one share of common stock on the date the leasehold interests were acquired.  The common stock related to these grants was issued in July 2010.

As of June 30, 2010 the Company has accrued bonuses based on the year to date results of operations in comparison to year-end bonus attainment expectations.  Management anticipates these bonuses will be paid in the fourth quarter of 2010 through the issuance of stock.  The accrued bonuses as of June 30, 2010, are an estimate and are considered discretionary based on 2010 operations.  The Company’s compensation committee has approved a plan to grant bonuses and the bonus accrual is based on that plan, but the June 30, 2010 bonus accrual balance has not been approved by the compensation committee.  The Company expensed $801,775 in share -based compensation related to this bonus accrual for the six month period ended June 30, 2010.  The remainder of bonus was capitalized into the full cost pool.

Restricted Stock Awards

During the six months ended June 30, 2010, the Company issued 956,000 restricted shares of common stock as compensation to officers and employees of the Company. The restricted shares vest over various terms with all restricted shares vesting no later than December 31, 2013. As of June 30, 2010, the Company had approximately $13.7 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.  


 
14

 

The following table reflects the outstanding restricted stock awards and activity related thereto for the six months ended June 30, 2010:

   
Six Months Ended
June 30, 2010
 
   
Number of
Shares
   
Weighted-Average
Price
 
Restricted Stock Awards:
           
Restricted Shares Outstanding at the Beginning of Period
    325,330     $ 9.01  
Shares Granted
    956,000     $ 13.29  
Lapse of Restrictions
    (76,854 )   $ 9.59  
Restricted Shares Outstanding at June 30, 2010
    1,204,476     $ 12.37  


NOTE 7     RELATED PARTY TRANSACTIONS

The Company has purchased leasehold interests from South Fork Exploration, LLC (“SFE”).  In the second quarter of 2010, the Company paid a total of $5,000 related to a previously executed leasehold agreement.  SFE’s president is J.R. Reger, the brother of the Company’s Chief Executive Officer, Michael Reger.  J.R. Reger is also a stockholder in the Company.

The Company has also purchased leasehold interests in 2007 from Gallatin Resources, LLC.  In the second quarter of 2010, the company paid a total of $6,277 related to a previously executed leasehold agreement. Carter Stewart, one of the Company’s directors, owns a 25% interest in Gallatin Resources, LLC.

The Company has an investment account with Morgan Stanley that is managed by Kathleen Gilbertson, a financial advisor with that firm who is the sister of our President and Director, Ryan Gilbertson.

All transactions involving related parties were approved by the Company’s Board of Directors or Audit Committee.
 

NOTE 8     STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS

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 Stock Option Plan.  The Company granted options to purchase an aggregate of 500,000 shares of common stock to members of the Company’s Board of Directors and options to purchase an additional 60,000 shares of common stock to one employee pursuant to an employment agreement.  These options were granted at an exercise price of $5.18 per share and were fully vested on the grant date.  Options to purchase an aggregate of 260,000 shares granted in 2007 have been exercised as of June 30, 2010.

The Company accounts for stock-based compensation under the provisions of FASB ASC 718-10-55 (Prior authoritative literature: FASB Statement 123(R), Share-Based Payment). This statement requires us to record an expense associated with the fair value of stock-based compensation.  We use 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 are recognized as compensation over the vesting period.  There have been no stock options granted since November 2007 under the 2006 Stock Option Plan.


 
15

 

The following summarizes activities concerning outstanding options to purchase shares of the Company’s common stock as of and for the period ending June 30, 2010:
 
·    
No options were exercised in the six months ended June 30, 2010.
 
·    
No options were forfeited or expired during the six months ended June 30, 2010.
 
·    
300,000 options are exercisable and outstanding as June 30, 2010.
 
·    
There is no further compensation expense that will be recognized in future years relative to any options that had been granted as of June 30, 2010, because the Company recognized the entire fair value of such compensation upon vesting of the options.
 
·    
There were no unvested options at June 30, 2010.

Warrants Granted February 2009

On February 27, 2009, in conjunction with the closing of the revolving credit facility (see Note 9), the Company issued to 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 are being amortized over the amended term of the facility using the effective interest method.  CIT can exercise the warrants at any time until the warrants expire in February 2012.
 

NOTE 9     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 (the “Facility”).  

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.

The Facility provides up to a maximum principal amount of $100 million of working capital for exploration and production operations.  The borrowing base of the funds available under the Facility is re-determined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from its interests in proved reserves estimated to be produced from its oil and gas properties.  $25 million of financing is currently available under the Facility.  The Facility terminates on May 26, 2014.  The Company had no borrowings under the Facility at June 30, 2010.

The Company has the option to designate the reference rate of interest for each specific borrowing under the Facility as amounts are advanced.  Borrowings based upon the London interbank offering 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 borrowing base that is currently advanced.  Any borrowings not designated as being based upon LIBOR will bear interest at a rate equal to the greater of (a) the current prime rate published by the Wall Street Journal, or (b) the current one month LIBOR rate plus 1.0%, plus in either case 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.  Payments are due under the 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 Facility.
 

 
16

 

The applicable interest rate increases under the Facility and the lenders may accelerate payments under the Facility, or call all obligations due under certain circumstances, upon an event of default.  The Facility references various events constituting a default on the Facility, including, but not limited to, failure to pay interest on any loan under the Facility, any material violation of any representation or warranty under the Amended and Restated Credit Agreement, failure to observe or perform certain covenants, conditions or agreements under the Amended and Restated Credit Agreement, a change in control of the Company, default under any other material indebtedness the Company might have, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Facility.  The Company was not in default on the Facility as of June 30, 2010, and is not expected to be in default in the future.

The Facility requires that the Company enter into swap agreements with Macquarie for each month of the thirty-six (36) month period following the date on which each such swap agreement is executed, the notional volumes for which when aggregated with other commodity swap agreements and additional fixed-price physical off-take contracts then in effect, as of the date such swap agreement is executed, is not less than 50%,  nor exceeds 90%, of the reasonably anticipated projected production from the Company’s proved developed producing reserves, as defined at the time of the agreement.  The Company entered into swap agreements as required at the time, and presently there are no material hedging requirements imposed by Macquarie.

All of the Company’s obligations under the Facility and the swap agreements with Macquarie are secured by a first priority security interest in any and all assets of the Company.
   
 
NOTE 10     ASSET RETIREMENT OBLIGATION

The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities.  Under the provisions of FASB ASC 410-20-25 (Prior authoritative literature: FASB Statement 143, Accounting for Asset Retirement Obligations), the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and 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 in accordance with the provisions of FASB ASC 410-20-25 during the six months ended June 30, 2010:

   
Six Months Ended
June 30, 2010
 
Beginning Asset Retirement Obligation
  $ 206,741  
Liabilities Incurred for New Wells Placed in Production
    69,802  
Liabilities Settled
    (1,428 )
Accretion of Discount on Asset Retirement Obligations
    12,752  
Ending Asset Retirement Obligation
  $ 287,867  

 
 NOTE 11     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 in accordance with FASB ASC 740-10-30 (Prior authoritative literature: FASB Statement 109, Accounting for Income Taxes). 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.


 
17

 

The income tax provision (benefit) for the six months ended June 30, 2010 and 2009 consists of the following:

   
Six Months
Ended June 30,
 
   
2010
   
2009
Adjusted
 
Current Income Taxes
  $ -     $ -  
Deferred Income Taxes
    -       -  
Federal
    3,915,000       87,000  
State
    895,000       19,000  
Total Provision
  $ 4,810,000     $ 106,000  

In June 2006, FASB issued FASB ASC 740-10-05-6 (Prior authoritative literature: FASB Statement 48, Accounting for Uncertainty in Income Taxes).  We adopted FASB ASC 740-10-05-6 on January 1, 2007.  Under FASB ASC 740-10-05-6, 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 our tax returns that do not meet these recognition and measurement standards.

Upon the adoption of FASB ASC 740-10-05-6, we had no liabilities for unrecognized tax benefits and, as such, the adoption had no impact on our financial statements, and we have recorded no additional interest or penalties.  The adoption of FASB ASC 740-10-05-6 did not impact our effective tax rates.

Our policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense.  For the six months ended June 30, 2010, we did not recognize any interest or penalties in our Statement of Operations, nor did we have any interest or penalties accrued in our Balance Sheet at June 30, 2010 relating to unrecognized benefits.

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

NOTE 12     FAIR VALUE

FASB ASC 820-10-55 (Prior authoritative literature: FASB Statement 157, Fair Value Measurements) defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and enhances disclosures about fair value measurements.  Fair value is defined under FASB ASC 820-10-55 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 under FASB ASC 820-10-55 must maximize the use of observable inputs and minimize the use of unobservable inputs.  The standard describes 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.


 
18

 

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of June 30, 2010.

   
Quoted Prices In Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Current Derivative Assets
  $ -     $ 1,068,924     $ -  
Non-Current Derivative Liabilities
    -       (85,544 )     -  
Total
  $ -     $ 983,380     $ -  


Level 2 assets and liabilities consist of derivative assets and liabilities (see Note 14).  Under FASB ASC 820-10-55 (Prior authoritative literature: FASB Statement 157, Fair Value Measurements), 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 balance sheet.  The current asset amounts represent the fair values expected to be included in the results of operations for the subsequent year.
 
The following table provides a reconciliation of the beginning and ending balances for the assets measured at fair value using significant unobservable inputs (Level 3):


   
Fair Value Measurements
at Reporting
Date Using Significant
Unobservable
Inputs (Level 3)
Level 3 Financial Assets
 
Balance at January 1, 2010
  $ 1,818,356  
Sales
    (2,025,003 )
Unrealized Gain Included in Other Comprehensive Income (Loss)
    206,787  
Realized Loss on Sales
    (140 )
Balance at June 30, 2010
  $ -  


The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of the Company’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of the asset retirement obligations is reflected on the balance sheet as follows.

   
Fair Value Measurements at
June 30, 2010 Using
 
Description
 
Quoted Prices in Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Other Non-Current Liabilities
  $ -     $ -     $ (287,867 )
Total
  $ -     $ -     $ (287,867 )

See Note 10 for a rollforward of the Asset Retirement Obligation.

 
19

 

NOTE 13       FINANCIAL INSTRUMENTS

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and line of credit. 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 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.  The Company’s accounts receivable at June 30, 2010 and December 31, 2009 do not represent significant credit risks as they are dispersed across many counterparties.
 

NOTE 14     DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity swap contracts to (i) reduce the effects of volatility in price changes on the 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.

Crude Oil Derivative Contracts Cash-flow Hedges

Historically, 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 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 statement of operations. The Company reports average oil and gas prices and revenues including the net results of hedging activities.

On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivates 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 under FASB ASC 815-20-25 (Prior authoritative literature: FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities).  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 and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the statement of operations rather than as a component of other comprehensive income or as other income (expense).

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 totaled $1,913,590 as of June 30, 2010.  The Company has recorded that as accumulated other comprehensive income in stockholders’ equity, and the entire amount will be amortized into revenues as the original forecasted hedged oil production occurs in 2010 and 2011.

The Company realized a settled derivative gain of $126,936 and maintained a mark-to-market value of an unrealized gain of $3,260,383 on derivative instruments for the six months ended June 30, 2010.
 
The following table reflects the weighted average price of open commodity derivative contracts as of June 30, 2010, by year with associated volumes.

Weighted Average Price
Of Open Commodity Contracts
 
 
Year
 
Volumes (Bbl)
   
Weighted Average Price
 
2010
    225,400     $ 80.64  
2011
    263,996     $ 80.45  
2012
    3,000     $ 51.25  


 
20

 

In addition to the hedges listed above, on July 22, 2010 the Company entered into a swap agreement covering delivery of 374,504 barrels of oil for delivery in various quantities beginning August 1, 2010 until June 30, 2012 at a fixed price of $80.00 per barrel.  As of July 31, 2010, the Company has a total hedged volume of 828,500 barrels at a weighted average price of approximately $80.18.

At June 30, 2010, the Company had derivative financial instruments under FASB ASC 815-20-25 recorded on the consolidated balance sheet as set forth below:

Type of Contract
 
Balance Sheet Location
 
June 30, 2010
Estimated Fair Value
   
December 31, 2009 Estimated Fair Value
 
Derivatives Designated as Hedging Instruments
               
Derivative Assets:
               
Oil Contracts
 
Other current assets
  $ 2,072,249     $ 96,163  
Oil Contracts
 
Other non-current assets
    469,001       -  
Total Derivative Assets
      $ 2,541,250     $ 96,163  
                     
Derivative Liabilities:
                   
Oil Contracts
 
Other current liabilities
  $ (1,003,325 )   $ (1,402,910 )
Oil Contracts
 
Other non-current liabilities
    (554,545 )     (1,473,306 )
Total Derivative Liabilities
      $ (1,557,870 )   $ (2,876,216 )


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 16     COMPREHENSIVE INCOME

The Company follows the provisions of FASB ASC 220-10-55 (Prior authoritative literature: FASB Statement 130, Reporting Comprehensive Income) which establishes standards for reporting 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 stockholders of the Company.

For the periods indicated, comprehensive income (loss) consisted of the following:


   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Net Income
  $ 6,120,866     $ 418,396     $ 7,680,496     $ 159,523  
Unrealized gains on Marketable Securities (net of tax of $459,000 and $68,000 at June 30, 2010 and 2009)
    529,516       8,311       725,981       90,556  
Net unrealized gains/losses on hedges (net of tax of $195,000 and $1,133,000 at June 30, 2010 and 2009)
    167,950       (1,101,600 )     308,050       (1,700,323 )
Other Comprehensive income (loss) net
  $ 6,818,332     $ (674,893 )   $ 8,714,527     $ (1,450,244 )


 
21

 

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:  oil prices, 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, our ability to raise or access capital, 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, services 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, 2009, as updated by subsequent reports we file with the United States Securities and Exchange Commission (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.  We accelerated our acreage acquisition activities throughout the Williston Basin in the first and second quarters of 2010 and continue to monitor various larger acquisitions.


 
22

 

We control approximately 115,700 net acres in the Williston Basin targeting the Bakken and Three Forks formations, which we believe provides the potential to drill approximately 1,085 net wells using 640 acre spacing units assuming three horizontal Bakken and three horizontal Three Forks wells per spacing unit.  We have no material lease expirations until late 2011 and continue to expand our position through aggressive acquisition and leasing programs.

During the three months ended June 30, 2010, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  We drilled, completed, and commenced production in an additional 41 gross wells (approximately 3.89 net wells) during the quarter.  As of June 30, 2010, we owned working interests in 202 successful discoveries, consisting of 198 targeting the Bakken/Three Forks formation and four targeting the Red River formation.

We believe recent discoveries in western Williams and McKenzie Counties of North Dakota have substantially expanded the delineated area of high quality Bakken and Three Forks production and the rapidly accelerating pace of drilling has dramatically changed the dynamics of this oil play.  Acreage acquisition represents our core competency and we expect to continue to leverage our leasing expertise as the Bakken and Three Forks plays continue to increase in size and scope.
 
                 As of August 9, 2010, we are participating in the drilling or completion of an additional 63 gross Bakken or Three Forks wells and one gross Red River well, for an aggregate of 7.24 net wells currently drilling or awaiting completion.  We have spud approximately 13.85 net wells in 2010.  We expect to spud approximately 18 net wells throughout 2010 and increase production volumes by 30 to 35% in the quarter ending September 30, 2010 compared to the quarter ended June 30, 2010.
 
Completion Activity

During the second quarter, 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 an increased inventory of wells awaiting fracture stimulation throughout the Williston Basin caused by a low supply of sub-contractors responsible for fracture stimulation.  Additionally, we believe the constraint in moving fracture stimulation supplies, such as frac sand, into the field have added to this delay.  We expect that for the next quarter, delay between fracture stimulation and completion may continue to average as much as six weeks.  We do not expect that this will affect the pace of drilling and we continue to see wells drilled to total depth at an accelerated pace.  However, delays in fracture stimulation have the effect of delaying production additions.

2010 Drilling Projects

We are engaged in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future.  We drilled, completed, and commenced production in an additional 41 gross wells (approximately 3.89 net wells) during the quarter.  We intend to continue drilling efforts on our existing acreage in North Dakota and Montana.  We reaffirm our previous guidance to spud approximately 18 net wells in 2010, through participations in approximately 120 gross wells in which we expect to own an average 15% working interest.

As of June 30, 2010, we had interest in a total of 268 gross wells that were either drilling, completing or producing, including 202 producing wells and 66 drilling or completing wells.  Permits continue to be issued for spacing units in which we have acreage interests within North Dakota and Montana.

We continue to develop our acreage position we acquired from Windsor Bakken LLC in 2009 with our operating partner, Slawson Exploration.  The development program consists of Northern owning a working interest in the majority of the wells, with an average working interest in such wells expected to approximate 20%.  As of June 30, 2010, 58 wells have been drilled, completed, and turned over to production with six rigs drilling ahead.

During the second quarter of 2010, we entered into an agreement with GeoResources, Inc. to begin development of a block of approximately 3,000 net acres located in Roosevelt County, Montana, more commonly known as the Rip Rap prospect.  We believe this important extensional exploration into Montana may serve to further delineate the productive area of the Bakken and Three Forks formations.  We will participate in the program on a heads-up basis, with our operating partner Slawson Exploration, in drilling and all future acreage acquisitions for a 15% interest in the program.

 
23

 
 
Production History
 
The following table presents information about our produced oil and gas volumes during the three month and six month periods ended June 30, 2010, compared to the three month and six month periods ended June 30, 2009.  As of June 30, 2010, we were selling oil and natural gas from a total of 202 gross wells (approximately 14.36 net wells), compared to 104 gross wells (approximately 4.97 net wells) at June 30, 2009.  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.


   
Three Months Ended June 30,
 
Six Months Ended June 30,
   
2010
 
% Change
   2009  
2010
 
% Change
 
2009
Net Production:
                         
Oil (Bbl)
    166,341     230 %   50,396     285,955     267 %   77,956
Natural Gas (Mcf)
    37,931     474 %   6,604     70,534     716 %   8,647
Barrel of Oil Equivalent (Boe)
    172,663     235 %   51,497     297,711     275 %   79,397
                                     
Average Sales Prices:
                                   
Oil (per Bbl)
    69.15     25 %   55.21     69.58     42 %   48.95
Effect of settled oil  hedges on average price (per Bbl)
    1.83     164 %   (2.85     0.44     128 %   (1.61
Oil net of settled hedging (per Bbl)
    70.98     36 %   52.36     70.02     48 %   47.34
Natural Gas and Other Liquids (per Mcf)
    5.07     0 %   5.05     4.56     (13 %)   5.26
Effect of natural gas hedges on average price (per Mcf)
    0.00     --     0.00     0.00     --     0.00
Natural gas net of hedging (per Mcf)
    5.07     0 %   5.05     4.56     (13 %)   5.26
                                     
Average Production Costs:
                                   
Oil (per Bbl)
    3.37     39 %   2.43     3.32     19 %   2.78
Natural Gas (per Mcf)
    0.27     13 %   0.24     0.23     (13 %)   0.26
Barrel of Oil Equivalent (Boe)
    3.30     37 %   2.41     3.25     18 %   2.76


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 six month periods ended June 30, 2010 compared to the three month and six month periods ended June 30, 2009.

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Depletion of oil and natural gas properties
  $ 2,600,836     $ 548,124     $ 4,484,441     $ 850,326  
 

 
 
24

 

Productive Oil Wells
 
The following table summarizes gross and net productive oil wells by state at June 30, 2010 and June 30, 2009.  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.

   
June 30,
 
   
2010
   
2009
 
   
Gross
   
Net
   
Gross
   
Net
 
North Dakota
    194       12.98       97       4.16  
Montana
    8       1.38       7       0.81  
Total:
    202       14.36       104       4.97  


Results of Operations for the periods ended June 30, 2009 and June 30, 2010.

Our current 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 six months ended June 30, 2010, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  As of June 30, 2010, we had established production from 202 total gross wells in which we hold working interests, only 104 of which had established production as of June 30, 2009.  During the second quarter of 2010 we produced an average of approximately 1,828 barrels of oil per day, compared to an average of approximately 554 barrels of oil per day during the second quarter of 2009.  Our production at June 30, 2010 approximated 2,550 barrels of oil per day, compared to approximately 967 barrels of oil per day at June 30, 2009.

We drilled with a 100% success rate in the six months ended June 30, 2010.  We have 198 Bakken or Three Forks wells completed and four successful Red River discoveries at June 30, 2010.  As of June 30, 2010, we expect to participate in the drilling of approximately 120 gross (approximately 18 net) oil wells in 2010.

We recognized $11,664,873 in revenues from sales of oil and natural gas for the three months ended June 30, 2010, compared to $2,418,496 for the three months ended June 30, 2009.  We recognized $20,033,720 in revenues from sales of oil and natural gas for the six months ended June 30, 2010, compared to $3,059,230 for the six months ended June 30, 2009.  These increases in revenue are due primarily to our continued addition of wells period-over-period, our realization of production from such wells, as well as a substantial increase in oil prices.

We had net income of $6,120,866 (representing approximately $0.12 per share) for the three-month period ended June 30, 2010, and net income of $418,396 (representing approximately $0.01 per share) for the three-month period ended June 30, 2009.  Total operating expenses were $6,133,565 for the three-month period ended June 30, 2010, compared to operating expenses of $1,437,445 for the three-month period ended June 30, 2009.  These increases in expenses are due primarily to increased production expenses, severance taxes, depletion and general and administrative expenses associated with our continued addition of oil and gas production.
 

 
25

 
 
Our net income for the three months ended June 30, 2010, excluding unrealized mark-to-market hedging gains, was $3,502,667 (representing approximately $0.07 per diluted share) as compared to net income in the quarter ended March 31, 2010, excluding unrealized mark-to-market hedging losses of $2,172,446 (representing approximately $0.05 per diluted share).
 
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 losses on commodity risk and (vii) non-cash expenses relating to share based payments recognized under ASC Topic 718.  Adjusted EBITDA for the three months ended June 30, 2010 was $9,677,386 (representing approximately $0.19 per diluted share), compared to adjusted EBITDA of $6,417,708 (representing approximately $0.14 per diluted share) for the first quarter of 2010.
 
Net income excluding unrealized mark-to-market hedging gains and adjusted EBITDA are non-GAAP measures.  A reconciliation of these measures to GAAP is included below:
 
Northern Oil and Gas, Inc.
Reconciliation of Adjusted EBITDA
           
   
Three Months Ended
   
March 31,
   June 30,  
   
2010
   2010  
Net Income
  $ 1,559,630   $ 6,120,866  
               
Add Back:
             
               
Income Tax Provision
    977,000     3,833,000  
               
Depreciation, Depletion, Amortization, and Accretion
    2,062,170      2,766,688   
               
Share Based Compensation
    813,297     1,193,072  
               
Unrealized Gain on Commodity
             
    Price Risk Management Activities
    990,816     (4,251,199 )
               
Interest Expense
    14,795     14,959  
               
                  Adjusted EBITDA   $ 6,417,708   $ 9,677,386  
               
 EBITDA Per Common Share - Basic
  $ 0.15   $ 0.19  
               
 EBITDA Per Common Share - Diluted
  $ 0.14   $ 0.19  
               
Weighted Average Shares Outstanding – Basic
    44,098,553     49,934,409  
               
Weighted Average Shares Outstanding - Diluted
    44,544,469     50,609,944  


 
26

 


Northern Oil and Gas, Inc.
 
Reconciliation of GAAP Net Income to Earnings Without
 
the Effect of Certain Items
 
             
   
Three Months Ended
 
   
March 31,
   
June 30,
 
   
2010
   
2010
 
Net Income, as Reported
  $ 1,559,630     $ 6,120,866  
                 
Unrealized Derivative Gains
    990,816       (4,251,199 )
                 
Tax Impact
    (378,000 )     1,633,000  
                 
Earnings without the Effect of Certain Items
  $ 2,172,446     $ 3,502,667  
                 
Net Income Per Common Share – Basic
  $ 0.05     $ 0.07  
                 
Net Income Per Common Share – Diluted
  $ 0.05     $ 0.07  
                 
Weighted Average Shares Outstanding – Basic
    44,098,553       49,934,409  
                 
Weighted Average Shares Outstanding - Diluted
    44,544,469       50,609,944  
                 

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 oil and 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.


 
27

 

The following table summarizes total current assets, total current liabilities and working capital at June 30, 2010.

Current Assets
  $ 90,596,786  
Current Liabilities
  $ 11,944,757  
Working Capital
  $ 78,652,029  
 

Assignment of CIT Capital USA, Inc. Credit Facility to 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.

The new facility with Macquarie provides us with an increased initial borrowing base of $25 million and maximum borrowings of up to $100 million (the “Credit Facility”).  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 2.00% 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 June 30, 2010, we had no borrowings outstanding under the Credit Facility.

All of our obligations under the Credit Facility and the swap agreements with Macquarie (as discussed in Item 3) continue to be secured by a first priority security interest in any and all of our assets pursuant to the terms of an Amended and Restated Guaranty and Collateral Agreement and perfected by an amended and restated mortgage, notice of pledge and security and similar documents.

Follow-On Equity Offering

On April 20, 2010, we completed the sale of 5,750,000 shares of our common stock (the “Offering”), which included 750,000 shares that were issued pursuant to the underwriters full exercise of their over-allotment option.  Pursuant to an underwriting agreement, we sold the shares at a price per share of $15.00 to the public, less an underwriting discount of $0.60 per share.  We received approximately $82.5 million net proceeds from the Offering after deducting the underwriters discounts and expenses.  We intend to use the net proceeds from the Offering to continue to pursue acquisition opportunities, to fund our accelerated drilling program, to repay short-term borrowings, and for other working capital purposes.  This Offering was completed as a firm commitment underwritten offering in which the underwriters purchased the shares directly from us at a predetermined price, prior to marketing any of the shares.
 
The shares of common stock sold in the Offering were registered under an existing shelf registration statement on Form S-3 (Registration No. 333-158320), which the Securities and Exchange Commission declared effective on May 21, 2009.
 
Satisfaction of Our Cash Obligations for the Next 12 Months
 
With the addition of equity capital during 2009 and 2010 and our Credit Facility, we believe we have sufficient capital to meet our drilling commitments and expected general and administrative expenses for the next twelve months at a minimum.  Nonetheless, any strategic acquisition of assets may require us to seek additional capital.  We may also choose to seek additional capital rather than our Credit Facility or other debt instruments to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions.  We will evaluate any potential opportunities for acquisitions as they arise.  Given our non-leveraged asset base and anticipated growing cash flows, we believe we are in a position to take advantage of any appropriately priced sales that may occur.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.


 
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Over the next 24 months it is possible that our existing capital, the Credit Facility and anticipated funds from operations may not be sufficient to sustain continued acreage acquisitions.  Consequently, we may seek additional capital in the future to fund growth and expansion through additional equity or debt financing or credit facilities.  No assurance can be made that such financing would be available, and if available it may take either the form of debt or equity.  In either case, the financing could have a negative impact on our financial condition and our stockholders.

Though we achieved profitability in 2008 and remained profitable throughout 2009 and into 2010, our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of operations, particularly companies in the oil and gas exploration industry.  Such risks include, but are not limited to, an evolving and unpredictable business model and the management of our growth.  To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel.  There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Contractual Obligations and Commitments

Our material long-term debt obligations, capital lease obligations and operating lease obligations or purchase obligations are included in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and have not materially changed since that report was filed.

Critical Accounting Policies

A description of our critical accounting policies was provided in Note 2 to the Financial Statements provided in Part II, Item 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.


Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Our quantitative and qualitative disclosures about market risk for changes in commodity prices and interest rates are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and, except as set forth below, have not materially changed since that report was filed.

Commodity Price Risk
 
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future.  The prices we receive for our production depend on numerous factors beyond our control.  Our revenue during 2009 and the first and second quarter of 2010 generally would have increased or decreased along with any increases or decreases in crude oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.
 
We have previously entered into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil and natural gas price volatility.  On November 1, 2009, due to the volatility of price differentials in the Williston Basin, we de-designated all derivatives that were previously classified as cash flow hedges and in addition, we have elected not to designate any subsequent derivative contracts as accounting hedges.  As such, 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 or losses on derivatives are recorded in Gain (Loss) on Settled Derivatives and unrealized gains or losses are recorded in Mark-to-Market of Derivative Instruments on the Statement of Operations rather than as a component of other comprehensive income (loss) or other Income (expense).


 
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The following table reflects the weighted average price of open commodity derivative contracts as of June 30, 2010, by year with associated volumes


Weighted Average Price
Of Open Commodity Contracts
 
 
Year
 
Volumes (Bbl)
   
Weighted Average Price
 
2010
    225,400     $ 80.64  
2011
    263,996     $ 80.45  
2012
    3,000     $ 51.25  


In addition to the hedges listed above, on July 22, 2010 the Company entered into a swap agreement covering delivery of 374,504 barrels of oil for delivery in various quantities beginning August 1, 2010 until June 30, 2012 at a fixed price of $80.00 per barrel.  As of July 31, 2010, the Company has a total hedged volume of 828,500 barrels at a weighted average price of approximately $80.18.

 Interest Rate Risk
 
We did not have outstanding any borrowings under our credit facilities or other obligations that would subject us to significant interest rate risk at June 30, 2010.  Our Credit Facility would, however, subject us to interest rate risk on borrowings under that facility.

Our Credit Facility allows us to fix the interest rate of borrowings under it for all or a portion of the principal balance for a period up to six months.  To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows.  Conversely, for the portion of our borrowings that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
 
As of June 30, 2010, our management, including our Chief Executive Officer and Chief Financial Officer, had evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act.  Based upon and as of the date of the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports.  Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of June 30, 2010.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the period of this report that materially affected or are reasonably likely to materially affect our internal control over financial reporting.



 
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PART II - OTHER INFORMATION

Item 1.  Legal Proceedings.

Our company is subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  One of the opposing parties in a pending litigation seeking the quieting of title for a leasehold interest filed a motion for summary judgment in the case.  We have opposed the summary judgment motion and also filed our own motion seeking summary judgment in our favor.  No other developments have occurred in any pending litigation during the period of this report.  Our management believes that all litigation matters in which we are involved are not likely to have a material adverse effect on our financial position, cash flows or results of operations.

Item 1A.  Risk Factors.

    There have been no material changes to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated by our subsequent filings on Form 10-Q (and otherwise) with the SEC.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

In May 2010, we issued an aggregate of 382,645 shares of common stock as part of an acquisition of leasehold interests in Williams County, North Dakota and McKenzie County, North Dakota, consisting of 107,052 shares issued to JAG Oil, LP and 275,593 shares issued to G.G. Rose, LLC.  The fair value of the stock issued was $5,360,856 or $14.01 per share, based upon the market value of our common stock on the date the shares were registered with the SEC for resale, which is the date the leasehold interests were acquired.

In June 2010, we agreed to issue an aggregate of 14,167 shares of common stock related to acquisitions from four separate parties of leasehold interests in North Dakota.  The fair value of the stock issued was an aggregate of $238,006 or $16.80 per share, based upon the market value of our common stock on the date the leasehold interests were acquired.  The common stock related to these transactions was issued in July 2010.

In July 2010, we issued 444,186 shares of common stock to Lario Oil & Gas Company as part of an acquisition of leasehold interests in Divide County, North Dakota.  The fair value of the stock issued was $6,529,534.20 or $14.70 per share, based upon the market value of our common stock on the date the leasehold interests were acquired.

Each of the foregoing issuances was exempt from registration pursuant to Section 4(2) of the Securities Act of 193, as amended.


Item 6.  Exhibits.
 
The exhibits listed in the accompanying exhibit index are filed as part of this Quarterly Report on Form 10-Q.
 


 
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SIGNATURES
 
In accordance with the requirements of the Exchange Act, the Registrant has caused this Quarterly Report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
NORTHERN OIL AND GAS, INC.
 
Date:
August 9, 2010
 
By:
/s/ Michael L. Reger
       
Michael L. Reger, Chief Executive Officer and Director
         
Date:
August 9, 2010
 
By:
/s/ Chad D. Winter
       
Chad D. Winter, Chief Financial Officer


 
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EXHIBIT INDEX


Exhibit Number
 
 
Exhibit Description
     
     
2.1
 
Plan of Merger of Northern Oil and Gas, Inc. a Nevada corporation with and into Northern Oil and Gas, Inc., a Minnesota corporation (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 2, 2010)
     
3.1
 
Articles of Incorporation of Northern Oil and Gas, Inc. (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 2, 2010.)
 
3.2
 
Bylaws of Northern Oil and Gas, Inc. (Incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 2, 2010.)
 
4.1
 
Form of Stock Certificate of Northern Oil and Gas, Inc. (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 2, 2010)
     
10.1
 
Amended and Restated Credit Agreement dated as of May 26, 2010 among Northern Oil and Gas, Inc. as Borrower, Macquarie Bank Limited, as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 1, 2010)
     
31.1
 
Certification pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
31.2
 
Certification pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
32.1
 
Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S. C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 

 
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