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 March 31, 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)

Nevada
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 May 4, 2010, there were 50,676,331 shares of our common stock, par value $0.001, outstanding.

 
 

 

NORTHERN OIL AND GAS, INC.
FORM 10-Q

March 31, 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
    23  
         
Item 3.                     Quantitative and Qualitative Disclosures about Market Risk
    28  
         
Item 4.                     Controls and Procedures
    29  
         
         
PART II
       
         
Item 1.                      Legal Proceedings
    30  
         
Item 1A.                   Risk Factors
    30  
         
Item 2                       Unregistered Sales of Equity Securities and Use of Proceeds
    30  
         
Item 6.                      Exhibits
    30  
         
Signatures
       



 
 

 

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

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

ASSETS
 
   
March 31,
       
   
2010
   
December 31,
 
   
(UNAUDITED)
   
2009
 
 CURRENT ASSETS
           
 Cash and Cash Equivalents
  $ 1,153,583     $ 6,233,372  
 Trade Receivables
    7,993,935       7,025,011  
 Other Receivables
    237,877       -  
 Prepaid Drilling Costs
    5,949,234       1,454,034  
 Prepaid Expenses
    209,347       143,606  
 Other Current Assets
    313,285       201,314  
 Short - Term Investments
    17,483,941       24,903,476  
 Deferred Tax Asset
    863,000       2,057,000  
 Total Current Assets
    34,204,202       42,017,813  
                 
 PROPERTY AND EQUIPMENT
               
Oil and Natural Gas Properties, Full Cost Method (including unevaluated cost of
 
 $69,531,236 at 3/31/10 and $53,862,529 at 12/31/2009)
    119,597,744       96,801,626  
 Other Property and Equipment
    470,016       439,656  
 Total Property and Equipment
    120,067,760       97,241,282  
 Less - Accumulated Depreciation and Depletion
    6,999,433       5,091,198  
 Total Property and Equipment, Net
    113,068,327       92,150,084  
                 
 DEBT ISSUANCE COSTS
    1,276,673       1,427,071  
                 
 Total Assets
  $ 148,549,202     $ 135,594,968  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 CURRENT LIABILITIES
               
 Accounts Payable
  $ 13,495,727     $ 6,419,534  
 Line of Credit
    31,377       834,492  
 Accrued Expenses
    676,376       316,977  
 Derivative Liability
    2,170,153       1,320,679  
 Other Liabilities
    18,574       18,574  
 Total Current Liabilities
    16,392,207       8,910,256  
                 

 
2

 


 
 LONG-TERM LIABILITIES
           
 Revolving Line of Credit
    2,300,000       -  
 Derivative Liability
    1,371,616       1,459,374  
 Subordinated Notes
    500,000       500,000  
 Other Noncurrent Liabilities
    257,512       243,888  
 Total Long-Term Liabilities
    4,429,128       2,203,262  
                 
 DEFERRED TAX LIABILITY
    922,000       922,000  
                 
 Total Liabilities
    21,743,335       12,035,518  
                 
 STOCKHOLDERS’ EQUITY
               
Common Stock, Par Value $.001; 100,000,000 Authorized, 44,932,331
         
 Outstanding (2009 – 43,911,044 Shares Outstanding)
    44,933       43,912  
 Additional Paid-In Capital
    126,233,467       124,884,266  
 Retained Earnings
    2,401,522       841,892  
 Accumulated Other Comprehensive Income (Loss)
    (1,874,055 )     (2,210,620 )
 Total Stockholders’ Equity
    126,805,867       123,559,450  
                 
 Total Liabilities and Stockholders’ Equity
  $ 148,549,202     $ 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 MONTHS ENDED MARCH 31, 2010 AND 2009
(UNAUDITED)

   
Three Months Ended
   
March 31,
         
 
   
2010
 2009
Adjusted *
   
 REVENUES
         
 Oil and Gas Sales
  $ 8,368,847     $ 640,734    
 Gain (Loss) on Settled Derivatives
    (176,983 )     17,534    
 Mark-to-Market of Derivative Instruments
    (990,816 )     -    
 Other Revenue
    20,466       -    
      7,221,514       658,268    
 OPERATING EXPENSES
                 
 Production Expenses
    332,330       94,389    
 Production Taxes
    645,866       58,315    
 General and Administrative Expense
    893,671       391,660    
 Share Based Compensation
    813,297       176,975    
 Depletion of Oil and Gas Properties
    1,883,605       302,202    
 Depreciation and Amortization
    24,630       22,679    
 Accretion of Discount on Asset Retirement Obligations
    3,537       1,394    
 Total Expenses
    4,596,936       1,047,614    
                   
 INCOME (LOSS) FROM OPERATIONS
    2,624,578       (389,346 )  
                   
 OTHER EXPENSE
    (87,948 )     (43,527 )  
                   
 INCOME (LOSS) BEFORE INCOME TAXES
    2,536,630       (432,873 )  
                   
 INCOME TAX PROVISION (BENEFIT)
    977,000       (174,000 )  
                   
 NET INCOME (LOSS)
  $ 1,559,630     $ (258,873 )  
                   
 Net Income (Loss) Per Common Share - Basic
  $ 0.04     $ (0.01 )  
                   
 Net Income (Loss) Per Common Share - Diluted
  $ 0.04     $ (0.01 )  
                   
 Weighted Average Shares Outstanding – Basic
    44,098,553       34,223,925    
                   
 Weighted Average Shares Outstanding - Diluted
    44,544,469       34,223,925    
                   
*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 THREE MONTHS ENDED MARCH 31, 2010 AND 2009
(UNAUDITED)

               
Three Months Ended
               
March 31,
                       
2009
               
 2010
     
Adjusted *
 CASH FLOWS FROM OPERATING ACTIVITIES
           
 
 Net Income (Loss)
      1,559,630
     $
        (258,873)
 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by
           
     
 Operating Activities:
           
   
 Depletion of Oil and Gas Properties
 
        1,883,605
     
            302,202
   
 Depreciation and Amortization
 
             24,630
     
              22,679
   
 Amortization of Debt Issuance Costs
 
           150,398
     
              40,231
   
 Accretion of Discount on Asset Retirement Obligations
 
               3,537
     
                1,394
   
 Income Tax Provision (Benefit)
 
           977,000
     
          (174,000)
   
 Loss on Sale of Available for Sale Securities
 
           104,217
     
                    -
   
 Market Value adjustment of Derivative Instruments
 
           990,816
     
                    -
   
 Amortization of Deferred Rent
 
             (4,643)
     
              (4,643)
   
 Share - Based Compensation Expense
 
           813,297
     
            176,975
   
 Changes in Working Capital and Other Items:
           
       
 Decrease (Increase) in Trade Receivables
 
         (968,924)
     
            276,542
       
 Increase in Other Receivables
 
         (237,877)
     
            (61,431)
       
 Increase in Prepaid Expenses
 
           (65,741)
     
            (50,719)
       
 Increase in Other Current Assets
 
         (111,971)
     
                    -
       
 Increase in Accounts Payable
 
        7,076,193
     
         2,042,335
       
 Decrease in Accrued Expenses
 
           (45,601)
     
          (942,307)
       
 Net Cash Provided By (Used For) Operating Activities
 
      12,148,566
     
         1,370,385
                         
 CASH FLOWS FROM INVESTING ACTIVITIES
           
 
 Purchases of Office Equipment and Furniture
 
            (30,360)
     
              (4,527)
 
 Increase in Prepaid Drilling Costs
 
       (4,495,200)
     
          (240,734)
 
 Proceeds from Sale of Oil and Gas Properties
 
            237,877
     
                    -
 
 Proceeds from Sale of Available for Sale Securities
 
         7,639,783
     
                    -
 
 Increase in Oil and Gas Properties
 
     (22,077,340)
     
        (6,783,427)
       
 Net Cash Used For Investing Activities
 
     (18,725,240)
     
        (7,028,688)
                         
 CASH FLOWS FROM FINANCING ACTIVITIES
           
 
 Payments on Line of Credit
 
         (803,115)
     
              (8,663)
 
 Advances on Revolving Credit Facility
 
        2,300,000
     
         6,000,000
 
 Increase in Subordinated Notes, net
 
                   -
     
            500,000
 
 Debt Issuance Costs Paid
 
                   -
     
          (973,646)
       
 Net Cash Provided by Financing Activities
 
        1,496,885
     
         5,517,691
                         
 NET DECREASE IN CASH AND CASH EQUIVALENTS
 
       (5,079,789)
     
          (140,612)
                         
 CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD
 
        6,233,372
     
            780,716
                         
 CASH AND CASH EQUIVALENTS – END OF PERIOD
 $
    1,153,583
     $
          640,104
                         
                         
 Supplemental Disclosure of Cash Flow Information
           
 
 Cash Paid During the Period for Interest
 $
           26,515
     $
            14,048
 
 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
 $
           99,475
     $
                  -
   
 Payment of Compensation through Issuance of Common Stock
 $
      1,655,747
     $
          261,280
   
 Capitalized Asset Retirement Obligations
 $
           16,158
     $
            22,299
   
 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
MARCH 31, 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 focuses on acreage acquisition and drilling projects in the oil and gas industry primarily based in the Rocky Mountains and specifically the Williston Basin Bakken Shale formation. The Company has begun to develop its substantial leasehold in the Bakken play and will continue to do so as well as target additional opportunities in emerging plays utilizing its first mover leasing advantage.  The Company participates on a heads up basis in the drilling of wells on our leasehold.  The Company owns working interests in wells, and does not lease land to operators.  To this point we have participated only in wells operated by others but have a substantial inventory of high working interest locations that we have begun to develop.  We believe the advantage gained by participating as a non-operating partner in approximately 164 gross oil wells completed as of March 31, 2010 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 a declared drilling unit.  Although to this point we have participated with interests ranging from approximately 0.5% to 62.5%, we expect to participate in incrementally higher working interest drilling units.  Our current North Dakota and Montana acreage position in the growing Williston Basin Bakken and Three Forks Play exposes us to approximately 321 net wells based on 640 acre spacing units and approximately 643 net wells based on 320 acre spacing units.  With 640-acre spacing units we have the ability to drill approximately 321 net wells, including 143 net wells targeting the Bakken formation, 143 net wells targeting the Three Forks formation and 35 net wells targeting the Red River formation. With 320-acre spacing units we have the ability to drill approximately 643 net wells, including approximately 286 net wells targeting the Bakken formation, approximately 286 net wells targeting the Three Forks formation and approximately 70 net wells targeting the Red River formation.

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 as well as to carry out the principal and necessary functions incidental to the oil and gas business.  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 natural gas and oil.  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 natural gas and oil 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 solely of normal recurring adjustments), 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.

 
6

 

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.

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).  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 (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 five 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 $24,630 for the three months ended March 31, 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.  The capitalized costs are being amortized for three years over the term of the facility using the effective interest method.  In May 2009, the Company amended the revolving credit facility with CIT to allow for additional borrowings.  The Company incurred $216,414 of direct costs related to this amendment.   The capitalized costs are being amortized over the remaining term of the facility using the effective interest method.

The amortization of debt issuance costs for the three months ended March 31, 2010 was $150,398.
 

 
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 March 31, 2010 and December 31, 2009, our gas production was in balance, i.e., 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 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.  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 months ended March 31, 2010 and 2009 are as follows:
 
   
Three Months Ended
   
March 31,
   
2010
 
2009
Weighted average common shares outstanding - basic
   
44,098,553
 
34,223,925
Plus: Potential issuance of  common shares
         
Stock options, warrants, and restricted stock.
   
445,915
 
-
Weighted average common shares  outstanding - diluted
   
44,544,469
 
34,223,925
Stock options and warrants excluded from EPS due to the anti-dilutive effect
   
-
 
 2,621
 
         
 
As of March 31, 2010 there were 300,000 potentially dilutive shares from stock options that became exercisable in 2007.

In addition, as of March 31, 2010, there were 300,000 warrants that were issued in conjunction with the February 2009 revolving credit facility with CIT Capital USA, Inc. 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.

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 $1,071,804 of internal costs and $26,515 of interest for the three months ended March 31, 2010.

As of March 31, 2010 we controlled acreage in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. We controlled acreage in North Dakota, primarily in Mountrail County, 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.

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.

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 12-month average price of oil and natural gas to estimated future production of proved oil and gas reserves

 
9

 

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, fair value of certain investments, 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.

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.

 
10

 

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
March 31, 2009
 
   
As
Reported
   
Adjusted
   
Effect of Change
 
Depletion Expense
  $ 381,654     $ 302,202     $ (79,452 )
Income Tax Provision (Benefit)
    (205,000 )     (174,000 )     31,000  
Net Loss
  $ (307,325 )   $ (258,873 )   $ 48,452  
Earnings Per Share – Basic and Diluted
  $ (0.01 )   $ (0.01 )   $ -  


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

   
Three Months Ended
March 31, 2009
 
   
As
Reported
   
Adjusted
   
Effect of Change
 
Net Loss
  $ (307,325 )   $ (258,873 )   $ 48,452  
Depletion of Oil and Gas Properties
    381,654       302,202       (79,452 )
Income Tax Benefit
    (205,000 )     (174,000 )     31,000  
Decrease in Accrued Drilling Costs
    (4,579,458 )     -       4,579,458  
Increase in Oil and Gas Properties
    (2,203,969 )     (6,783,427 )     (4,579,458 )




 
11

 

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 an SEC filer 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.
  
The following summarizes our short-term investments as of March 31, 2010:

   
Cost at
March 31, 2010
   
 
Unrealized
(Loss)
   
Fair Market Value at March 31, 2010
 
Auction Rate Municipal Bonds
  $ 950,000     $ (137,002 )   $ 812,998  
Auction Rate Preferred Stock
    275,143       (7,840 )     267,303  
United States Treasuries
    17,119,314       (715,674 )     16,403,640  
Total Short-Term Investments
  $ 18,344,457     $ (860,516 )   $ 17,483,941  


For the three months ended March 31, 2010 we realized losses of $104,217 on the sale of investments.  In November 2008 we received, in a settlement agreement from UBS AG (“UBS”), rights which allow us to put back the auction rate securities at par value to UBS starting in June 2010.  We expect to liquidate these investments at par no later than June 2010, in the meantime they continue to pay interest at various rates.  Under the settlement agreement with UBS, we also have the ability to borrow up to 75% of the loan-to-market value of eligible auction rate securities on a no-net cost basis.  As of March 31, 2010, we have borrowed $31,377 under this agreement, with an additional $887,373 of borrowings available under the agreement. 

The Company reviews these investments on a quarterly basis to determine if it is probable that the Company will realize some portion of the unrealized loss in accordance with FASB ASC 320-10-35 (Prior authoritative literature, FASB Statement 115, 115-1, and 124-1, The Meaning of Other-Than-Temporary Impairment and Its Application to

 
12

 

Certain Investments).   In determining if the difference between cost and estimated fair value of the short-term investments was deemed either temporary or other-than-temporary impairment, the Company evaluated each type of short-term investment using a set of criteria including decline in value, duration of the decline, period until anticipated recovery, nature of investment, probability of recovery, financial condition and near-term prospects of the issuer, the Company’s intent and ability to retain the investment, attributes of the decline in value, status with rating agencies, status of principal and interest payments and any other issues related to the underlying securities. The Company determined the decline in the fair values in all of the short-term investments were temporary as of March 31, 2010 and December 31, 2009, primarily based on estimated cash flows of the investments, the settlement agreement entered into with UBS, and the Company’s ability to hold the investments until settlement.
 
NOTE 4     PROPERTY AND EQUIPMENT

Property and equipment at March 31, 2010 consisted of the following:

         
   
March 31,
2010
 
Oil and Gas Properties, Full Cost Method
     
Unevaluated Costs, Not Subject to Amortization or Ceiling Test
 
$
69,531,236
 
Evaluated Costs
   
50,066,508
 
     
119,597,744
 
Office Equipment, Furniture, Leasehold Improvements and Software
   
470,016
 
     
120,067,760
 
Less: Accumulated Depreciation, Depletion and Amortization
       
Property and Equipment
   
6,999,433
 
Total
 
$
113,068,327
 


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

   
Three Months
Ended March 31,
 
   
2010
   
2009
Adjusted
 
Depletion of Costs for Evaluated Oil and Gas Properties
 
$
1,883,605
   
$
302,202
 
Depreciation of Office Equipment, Furniture, and Software
   
24,630
     
22,679
 
     Total Depreciation, Depletion, and Amortization Expense
 
$
1,908,235
   
$
324,881
 


NOTE 5     OIL AND GAS PROPERTIES

Acquisitions

North Dakota Acquisitions

In the first quarter of 2010 the Company has organically acquired approximately 10,227 net mineral acres in all of our key prospect areas in the form of both effective leases and top-leases.  In this organic acquisition program we have spent an average of approximately $925 per net acre acquired.


 
13

 

NOTE 6     PREFERRED AND COMMON STOCK

The Company has neither authorized 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.
  
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.

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, the Company agreed to issue 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 entire amount of this stock award was expensed in the three months ended March 31, 2010.
 
As of March 31, 2010 the Company has accrued bonuses based on the year to date results of operations. Management anticipates these bonuses will be paid in the fourth quarter of 2010 through the issuance of stock.  These bonuses have not been approved by the Company’s compensation committee and are discretionary based on 2010 operations.  The Company expensed $184,441 in share -based compensation related to this bonus accrual for the three month period ended March 31, 2010.  The remainder of bonus was capitalized into the full cost pool.

Restricted Stock Awards

During the three months ended March 31, 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 March 31, 2010, the Company had approximately $14.9 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.  

The following table reflects the outstanding restricted stock awards and activity related thereto for the three months ended March 31, 2010:
 
   
Three Months Ended
   
March 31, 2010
   
Number of
 
Weighted-
Average
   
Shares
 
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
   
(35,427)
 
$
9.70
    Restricted Shares Outstanding at March 31, 2010
   
1,245,903
 
$
12.27
             

NOTE 7     RELATED PARTY TRANSACTIONS

The Company has purchased leasehold interests from South Fork Exploration, LLC (SFE).   SFE’s president is J.R. Reger, the brother of the Company’s CEO, Michael Reger.  J.R. Reger is also a stockholder in the Company.

The Company has also purchased leasehold interests in 2006 and 2007 from MOP.  MOP is controlled by Mr. Tom Ryan and Mr. Steven Reger, both are relatives of the Company’s CEO, Michael Reger.

The Company has also purchased leasehold interests in 2007 from Gallatin Resources, LLC.  Carter Stewart, one of the Company’s directors, owns a 25% interest in Gallatin Resources, LLC.

 
14

 

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 March 31, 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 in 2009 and 2008 under the 2006 Stock Option Plan.

The following summarizes activities concerning outstanding options to purchase shares of the Company’s common stock as of and for the period ending March 31, 2010:
 
·  
No options were exercised in the three months ended March 31, 2010.
 
·  
No options were forfeited or expired during the three months ended March 31, 2010.
 
·  
300,000 options are exercisable and outstanding as March 31, 2010.
 
·  
There is no further compensation expense that will be recognized in future years relative to any options that had been granted as of March 31, 2010, because the Company recognized the entire fair value of such compensation upon vesting of the options.
 
·  
There were no unvested options at March 31, 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 CIT Capital USA, Inc. (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 for three years over the 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 Capital USA Inc. (“CIT”) that will provide up to a maximum principal amount of $25 million of working capital for exploration and production operations (the “Facility”).  The borrowing base of funds available under the Facility is redetermined 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.  $16 million of financing is currently available under the Facility.  An additional $9 million of financing could become available upon subsequent borrowing base redeterminations.  The Facility terminates on February 27, 2012, with all outstanding borrowings due at that time.  The Company had borrowings of $2.3 million under the facility at March 31, 2010.

 
15

 
 

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 be outstanding for a period of one, three or six months (as designated by us) and bear interest at a rate equal to 5.50% over the one-month, three-month or six-month LIBOR rate to be no less than 2.50%.  Any borrowings not designated as being based upon LIBOR will have no specified term and generally will bear interest at a rate equal to 4.50% over the greater of (a) the current three-month LIBOR rate plus 1.0% or (b) the current prime rate as published by JP Morgan Chase Bank, N.A.  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 loan 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.

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 Credit Agreement in connection with the Facility, failure to observe or perform certain covenants, conditions or agreements under the Facility, 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 March 31, 2010, and is not expected to be in default in the future.

The Facility required that the Company enter into swap agreements with Macquarie Bank Limited (“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 other than basis differential swaps on volumes already hedged pursuant to other swap agreements), as of the date such swap agreement is executed, is not less than 50% of, nor exceeds 80% 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 CIT.

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 pursuant to the terms of a Guaranty and Collateral Agreement and perfected by a mortgage, notice of pledge and security and similar documents.
   
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 three months ended March 31, 2010:

    Three Months Ended    
     March 31, 2010    
Beginning Asset Retirement Obligation
  $ 206,741  
Liabilities Incurred for New Wells Placed in Production
    16,158  
Liabilities Settled
    (1,428 )
Accretion of Discount on Asset Retirement Obligations
    3,537  
Ending Asset Retirement Obligation
    225,008  

 
 
 
16

 
 
 
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.

The income tax provision (benefit) for the three months ended March 31, 2010 and 2009 consists of the following:

   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
Adjusted
 
Current Income Taxes
 
$
-
   
$
-
 
D Deferred Income Taxes
               
     Federal
   
800,000
     
(148,000
)
     State
   
177,000
     
(26,000
)
Total Provision (Benefit)
 
$
977,000
   
$
(174,000
)

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 three months ended March 31, 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 March 31, 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:

 
17

 


Level 1 - Quoted prices in active markets for identical assets or liabilities.

Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets of liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of March 31, 2010.


   
Quoted Prices In Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
Current Derivative Liabilities
 
$
-
   
$
(2,170,153
)
 
$
-
 
Non-Current Derivative Liabilities
   
-
     
(1,371,616
)
   
-
 
Auction Rate Securities
   
-
     
-
     
1,080,301
 
United States Treasuries
   
16,403,640
     
-
     
-
 
      Total
 
$
16,403,640
   
$
(3,541,769
)
 
$
1,080,301
 

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

Level 2 liabilities consist of derivative 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 liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.

Level 3 assets consist of municipal bonds and floating rate preferred stock (see Note 3) with an auction reset feature (“auction rate securities” or ARS).  The underlying assets for the municipal bonds are student loans which are substantially backed by the federal government.  Auction-rate securities are long-term floating rate bonds or floating rate perpetual preferred stock tied to short-term interest rates.  After the initial issuance of the securities, the interest rate on the securities is reset periodically, at intervals established at the time of issuance (primarily every twenty-eight days), based on market demand for a reset period.  Auction-rate securities are bought and sold in the marketplace through a competitive bidding process often referred to as a “Dutch auction”.  If there is insufficient interest in the securities at the time of an auction, the auction may not be completed and the rates may be reset to predetermined “penalty” or “maximum” rates based on mathematical formulas in accordance with each security’s prospectus.

In February 2008, auctions began to fail for these securities and each auction since then has failed.  Consequently, the investments are not currently liquid.  In the event the Company needed to access these funds, they are not expected to be accessible until one of the following occurs: a successful auction occurs, the issuer redeems the issue, a buyer is found outside of the auction process or the underlying securities mature.  In October 2008, the Company received an offer (the “Offer”) from UBS AG (“UBS”), one of its investment providers, to sell at par value auction-rate securities originally purchased from UBS ($1,225,143) at anytime during a two-year period beginning June 30, 2010.  The Offer was non-transferable and expired on November 14, 2008. On October 28, 2008 the Company elected to participate in the Offer.   The Company has classified auction rate securities as short-term assets on our

 
18

 

balance sheet.  In addition to the Offer, UBS is providing no net cost loans up to 75% of the loan-to-market value of eligible auction rate securities until June 30, 2010.

Typically, the fair value of ARS investments approximates par value due to the frequent resets through the auction process.  While the Company continues to earn interest on its ARS investments at the contractual rate, these investments are not currently trading and therefore do not have a readily determinable market value.  Accordingly, the estimated fair value of the ARS no longer approximates par value.  At March 31, 2010, the Company valued the ARS investments based on Level 3 inputs.  The Company utilized a discounted cash flow approach to arrive at this valuation. The assumptions used in preparing the discounted cash flow model include estimates of, based on data available as of March 31, 2010, interest rates, timing and amount of cash flows, credit and liquidity premiums, and expected holding periods of the ARS.  These assumptions are volatile and subject to change as the underlying sources of these assumptions and market conditions change.  Based on this Level 3 valuation, the Company valued the ARS investments at $1,080,301, which represents a decline in value of $144,842 from par.

Although there is uncertainty with regard to the short-term liquidity of these securities, the Company continues to believe that the carrying value represents the fair value of these marketable securities because of the overall quality of the underlying investments and the anticipated future market for such investments.  In addition, the Company has the intent and ability to hold these securities until the earlier of: the market for auction rate securities stabilizes, the issuer refinances the underlying security, a buyer is found outside of the auction process at acceptable terms, the underlying securities have matured or the Company accepts the investment manager’s offer to redeem the securities.

Based on the CIT financing, the fact that the Company has approximately $17.5 million in cash and other short-term investments, the expected positive operating cash flows, and the Company’s ability to obtain no net cost loans up to 75% of the loan-to-market value, as determined by UBS, on eligible auction rate securities, the Company does not anticipate the current inability to liquidate the auction rate securities to adversely affect the Company’s ability to conduct its business.

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
   
(800,000
)
Unrealized Gain Included in Other Comprehensive Income (Loss)
   
61,945
 
Balance at March 31, 2010
 
$
1,080,301
 
 
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
March 31, 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
 
$
-
   
$
-
   
$
(225,008
)
      Total
 
$
-
   
$
-
   
$
(225,008
)

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 March 31, 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 $2,187,540 as of March 31, 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 loss of $176,983 and maintained a mark-to-market value of an unrealized loss of $990,816 on derivative instruments for the three months ended March 31, 2010.
 
 
 
 
20

 
 
 
The following table reflects the weighted average price of open commodity derivative contracts as of March 31, 2010, by year with associated volumes.


Weighted Average Price
Of Open Commodity Contracts
 
 
Year
 
Volumes (Bbl)
   
Weighted Average Price
 
2010
    237,600     $ 77.52  
2011
    162, 996     $ 75.78  
2012
    3,000     $ 51.25  


In addition to the hedges listed above, on April 21, 2010 the Company entered into a swap agreement covering delivery of 194,000 barrels of oil for delivery in various quantities beginning May 1, 2010 until December 31, 2011 at a fixed price of $88.00 per barrel.  As of May 1, 2010, the Company has a total hedged volume of 571,196 barrels at a weighted average price of $80.45.

At March 31, 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
 
Estimated
Fair Value
 
Derivatives Designated as Hedging Instruments
       
Derivative Liabilities:
       
Oil Contracts
Other Current Liabilities
 
$
2,170,153
 
Oil Contracts
Other Non-Current Liabilities
   
1,371,616
 
Total Derivative Liabilities:
   
$
3,541,769
 


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
March 31,
 
   
2010
   
2009
Adjusted
 
Net Income (Loss)
  $ 1,559,630     $ (258,873 )
Unrealized gains on Short-term Investments  (net of tax of $128,000 and $63,000 at March 31, 2010 and 2009)
    196,465       82,255  
Net unrealized gain (losses) on derivatives (Net of tax of $89,000 and $400,000  at March  31, 2010 and 2010)
    140,100       (598,723 )
Other Comprehensive income (loss) net
  $ 1,896,195     $ (775,341 )

 
 
21

 
 
 
NOTE 17     SUBSEQUENT EVENTS

In April 2010, the Company entered into a commodity swap contract.  The oil swap contract is for 194,000 barrels of oil.  The contracts settle at various quantities from May 2010 to February 2012.  The price on the contract is fixed at $88.00 per barrel.

In April 2010, the Company completed a sale of 5,750,000 shares of common stock.  The net proceeds from this sale of common stock were approximately $82.6 million after deducting underwriters discounts and estimated offering expenses.


 
22

 
 
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 and 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 quarter of 2010 and continue to monitor various larger acquisitions.
 

 
23

 

We control approximately 114,068 net acres in the Williston Basin targeting the North Dakota Bakken and Three Forks formations, which provides the potential to drill approximately 321 net wells using 640 acre spacing units.  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 March 31, 2010, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  We drilled, completed or acquired working interests in an additional 22 gross wells (approximately 1.34 net wells) during the quarter.  As of March 31, 2010, we owned working interests in 164 successful discoveries, consisting of 161 targeting the Bakken/Three Forks formation and three targeting the Red River structure.

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 it expects to continue to leverage our leasing expertise as the Bakken and Three Forks plays continue to increase in size and scope.

Completion Activity

During the first quarter, we experienced significant delays in fracture stimulation appointments for wells across all operators with whom we participate.  We believe this trend has been driven primarily by seasonal issues and increased costs of completing during the coldest winter months.  Additionally, we believe there has been some constraint in moving fracture stimulation supplies, such as frac sand, into the field due to seasonal conditions.  We expect that for the next quarter, delay between fracture stimulation and completion may average as much as six weeks.  This will not 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 or acquired interests in an additional 22 gross wells (approximately 1.34 net wells) during the quarter.  We intend to continue drilling efforts on our existing acreage in North Dakota and Montana.  We expect to spud approximately 18 net wells in 2010 through participations in approximately 125 gross wells in which we expect to own an average 15% working interest.

As of March 31, 2010, we had interest in a total of 210 gross wells that were either drilling, completing or producing, including 164 producing wells and 46 drilling or completing wells.  Permits continue to be issued for drilling units in which we have acreage interests within North Dakota and Montana.

We have commenced the development of the acreage position we acquired from Windsor Bakken LLC in 2009 with our operating partner, Slawson Exploration.  The development program consists of 54 gross wells with our average working interest in such wells expected to approximate 20%.  As of March 31, 2010, 22 of the 54 wells in the program had been drilled, completed, and turned over to production, with five rigs drilling ahead.

Production History
 
The following table presents information about our produced oil and gas volumes during the three months ended March 31, 2010, compared to the three months ended March 30, 2009.  As of March 31, 2010, we were selling oil and natural gas from a total of 164 gross wells (approximately 10.48 net wells), compared to 53 gross wells (approximately 3.15 net wells) at March 31, 2009.  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.



 
24

 


   
Three Months Ended
March 31,
 
   
2010
   
% Change
   
2009
 
Net Production:
                 
Oil (Bbl)
    119,614       334 %     27,560  
Natural Gas (Mcf)
    32,603       1,496 %     2,043  
Barrel of Oil Equivalent (Boe)
    125,048       348 %     27,901  
                         
Average Sales Prices:
                       
Oil (per Bbl)
  $ 70.18       87 %   $ 37.52  
Effect of settled oil hedges on average price (per Bbl)
  $ (1.48 )     (331 %)   $ 0.64  
Oil net of settled hedging (per Bbl)
  $ 68.70       80 %   $ 38.16  
Natural Gas (per Mcf)
  $ 3.97       (33 %)   $ 5.94  
Effect of natural gas hedges on average price (per Mcf)
    --       --       --  
Natural gas net of hedging (per Mcf)
  $ 3.97       (33 %)   $ 5.94  
                         
Average Production Costs:
                       
Oil (per Bbl)
  $ 3.25       (5 %)   $ 3.42  
Natural Gas (per Mcf)
  $ 0.18       (42 %)   $ 0.31  
Barrel of Oil Equivalent (Boe)
  $ 3.15       (8 %)   $ 3.41  


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 months ended March 31, 2010 compared to the three months ended March 31, 2009.

   
Three Months Ended
March 31,
 
   
2010
   
2009
 
Depletion of oil and natural gas properties
  $ 1,883,605     $ 302,202  

Productive Oil Wells
 
The following table summarizes gross and net productive oil wells by state at March 31, 2009 and March 31, 2010.  A net well represents our percentage ownership of a gross well.  No wells have been permitted or drilled on any of our Yates County, New York acreage.  The following table does not include wells in which our interest is limited to royalty and overriding royalty interests.  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.

   
March 31,
 
   
2010
   
2009
 
   
Gross
   
Net
   
Gross
   
Net
 
North Dakota
    158       9.47       50       2.42  
Montana
    6       1.01       3       0.73  
Total:
    164       10.48       53       3.15  




 
25

 

Results of Operations for the periods ended March 31, 2009 and March 31, 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 three months ended March 31, 2010, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  As of March 31, 2010, we had established production from 164 total gross wells in which we hold working interests, only 53 of which had established production as of March 31, 2009.  During the first quarter of 2010 we produced an average of approximately 1,329 barrels of oil per day, compared to an average of approximately 306 barrels of oil per day during the first quarter of 2009.  Our production at March 31, 2010 approximated 1,500 barrels of oil per day, compared to approximately 792 barrels of oil per day at March 31, 2009.

We drilled with a 100% success rate in the three months ended March 31, 2010.  We have 161 Bakken or Three Forks wells completed and three successful Red River discoveries at March 31, 2010.  As of March 31, 2010, we expect to participate in the drilling of approximately 125 gross (approximately 18 net) oil wells in 2010.

We recognized $8,368,847 in revenues from sales of oil and natural gas for the three months ended March 31, 2010, compared to $640,734 for the three months ended March 31, 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 $1,559,630 (representing approximately $0.04 per share) for the three-month period ended March 31, 2010, compared to net loss of $258,873 for the three-month period ended March 31, 2009.  Total operating expenses were $4,596,936 for the three-month period ended March 31, 2010, compared to operating expenses of $1,047,614 for the three-month period ended March 31, 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.

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.
 
The following table summarizes total current assets, total current liabilities and working capital at March 31, 2010.
 
             Current Assets                        $     34,204,202
             Current Liabilities                    $     16,392,207
             Working Capital                      $     17,811,995                             
 
CIT Capital USA, Inc. Credit Facility

We have a revolving credit facility with CIT that provides up to a maximum principal amount of $25 million of working capital for exploration and production operations (the “Credit Facility”).  The borrowing base of funds available under the Credit Facility will be redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from our interests in proved reserves estimated to be produced from our oil and gas properties.  On March 22, 2010, we entered into a second amendment to the Credit Facility to decrease our commitment fee rate per annum from 0.625% on any day prior to March 1, 2010 to 0.50% on any day on or after March 1, 2010.

$16 million of financing is the borrowing base available under the Credit Facility.  An additional $9 million of financing could become available upon subsequent borrowing base redeterminations based on the deployment of

 
26

 

funds from the Credit Facility.  The Credit Facility terminates on February 27, 2012.  As of March 31, 2010, we had $2.3 million in borrowings outstanding under the Credit Facility.

All of our obligations under the 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 a Guaranty and Collateral Agreement and perfected by a 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 $82.6 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.

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, 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.

 
27

 
 

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 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 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).

The following table reflects the weighted average price of open commodity derivative contracts as of March 31, 2010, by year with associated volumes


Weighted Average Price
Of Open Commodity Contracts
 
 
Year
 
Volumes (Bbl)
   
Weighted Average Price
 
2010
    237,600     $ 77.52  
2011
    162, 996     $ 75.78  
2012
    3,000     $ 51.25  


In addition to the hedges listed above, on April 21, 2010 the Company entered into a swap agreement covering delivery of 194,000 barrels of oil for delivery in various quantities beginning May 1, 2010 until December 31, 2011 at a fixed price of $88.00 per barrel.  As of May 1, 2010, the Company has a total hedged volume of 571,196 barrels at a weighted average price of $80.45.

 
28

 

 
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 March 31, 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 March 31, 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 March 31, 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.



 
29

 

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, which we intend to oppose.  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 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.

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


 
30

 

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:
May 6, 2010
 
By:
/s/ Michael L. Reger
       
Michael L. Reger, Chief Executive Officer and Director
         
Date:
May 6, 2010
 
By:
/s/ Chad D. Winter
       
Chad D. Winter, Chief Financial Officer


 
31

 

EXHIBIT INDEX


Exhibit Number
 
 
Exhibit Description
3.1
 
Composite Articles of Incorporation of Northern Oil and Gas, Inc. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K/A (Amendment No. 3) filed with the SEC on June 24, 2009.)
 
3.2
 
Bylaws of Northern Oil and Gas, Inc., as amended. (Incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the SEC on December 6, 2007.)
 
10.1*
 
Employment Agreement by and between Northern Oil and Gas, Inc. and Chad D. Winter, dated March 25, 2010 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2010 (file No. 001-33999))
     
10.2*
 
Employment Agreement by and between Northern Oil and Gas, Inc. and James R. Sankovitz, dated March 25, 2010 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2010 (file No. 001-33999))
     
10.3*
 
Amendment No. 1 to Second Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Ryan R. Gilbertson, dated March 25, 2010 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on March 25, 2010 (file No. 001-33999))
     
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
 
* Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report.

 
32