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, 2009
 
 
£ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE EXCHANGE ACT
 
For the transition period from ____________ to____________
 
Commission File No. 000-33999
 
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 T  No £

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

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 8, 2009, there were 34,120,103 shares of our common stock, par value $0.001, outstanding.

 
 

 

NORTHERN OIL AND GAS, INC.
FORM 10-Q

March 31, 2009

C O N T E N T S

 
Page
PART I
 
   
Item 1.                    Financial Statements
1
Condensed Balance Sheets
1
Condensed Statements of Operations
3
Condensed Statements of Cash Flows
4
Notes to Unaudited Condensed Financial Statements
6
   
Item 2.                      Management’s Discussion and Analysis or Plan of Operation
17
   
Item 3.                      Quantitative and Qualitative Disclosures about Market Risk
23
   
Item 4.                      Controls and Procedures
24
   
   
PART II
 
   
Item 1.                      Legal Proceedings
24
   
Item 6.                      Exhibits
25
   
Signatures
26



 
 

 

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.
 
 
 NORTHERN OIL AND GAS, INC.
           
 CONDENSED BALANCE SHEETS
           
MARCH 31, 2009 AND DECEMBER 31, 2008
           
             
 ASSETS
           
   
March 31,
   
         December 31,
 
   
2009
   
2008
 
   
(UNAUDITED)
       
 CURRENT ASSETS
           
 Cash and Cash Equivalents
  $ 640,104     $ 780,716  
 Trade Receivables
    1,752,399       2,028,941  
 Other Receivables
    935,884       874,453  
 Prepaid Drilling Costs
    245,283       4,549  
 Prepaid Expenses
    122,273       71,554  
 Deferred Tax Asset
    1,975,000       1,433,000  
 Total Current Assets
    5,670,943       5,193,213  
                 
 PROPERTY AND EQUIPMENT, AT COST
               
 Oil and Natural Gas Properties, Full Cost Method (including unevaluated costs of
               
 $39,482,967 at 3/31/09 and $42,621,297 at 12/31/2008)
    58,041,025       55,680,567  
 Other Property and Equipment
    412,927       408,400  
 Total Property and Equipment
    58,453,952       56,088,967  
 Less - Accumulated Depreciation and Depletion
    1,260,343       856,010  
 Total Property and Equipment, Net
    57,193,609       55,232,957  
                 
 LONG - TERM INVESTMENTS
    2,561,624       2,416,369  
                 
 DEBT ISSUANCE COSTS
    1,629,768       -  
                 
 DEFERRED TAX ASSET
    33,000       33,000  
                 
 Total Assets
  $ 67,088,944     $ 62,875,539  
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
 CURRENT LIABILITIES
               
 Accounts Payable
  $ 3,977,145     $ 1,934,810  
 Line of Credit
    1,642,057       1,650,720  
 Accrued Expenses
    327,768       1,270,075  
 Accrued Drilling Costs
    3,840,271       8,419,729  
 Subordinated Notes
    500,000       -  
 Derivative Liability
    292,015       -  
 Other Liabilities
    18,573       135,731  
 Total Current Liabilities
    10,597,829       13,411,065  
                 
 LONG-TERM LIABILITIES
               
 Revolving Line of Credit
    6,000,000       -  
 Derivative Liability
    706,708       -  
 Other Noncurrent Liabilities
    136,208       -  
 Total Long-Term Liabilities
    6,842,916       -  
                 
 Total Liabilities
    17,440,745       13,411,065  
 
 
1

 
 
                 
 STOCKHOLDERS' EQUITY
               
 Common Stock, Par Value $.001; 100,000,000 Authorized, 34,392,103
               
 Outstanding (2008 – 34,120,103 Shares Outstanding)
    34,393       34,121  
 Additional Paid-In Capital
    52,700,022       51,692,776  
 Accumulated Deficit
    (2,328,974 )     (2,021,649 )
 Accumulated Other Comprehensive Income (Loss)
    (757,242 )     (240,774 )
 Total Stockholders' Equity
    49,648,199       49,464,474  
                 
 Total Liabilities and Stockholders' Equity
  $ 67,088,944     $ 62,875,539  
                 
                                                                                          The accompanying notes are an integral part of these condensed financial statements.
         

 
2

 


NORTHERN OIL AND GAS, INC.
 
CONDENSED STATEMENTS OF OPERATIONS
 
FOR THE THREE MONTHS ENDED MARCH 31, 2009 AND 2008
 
(UNAUDITED)
 
             
             
             
             
             
             
             
   
Three Months Ended
 
   
March, 31
 
   
2009
   
2008
 
 REVENUES
           
 Oil and Gas Sales
  $ 640,734     $ 285,729  
 Gain on Derivatives
    17,534       1,300  
      658,268       287,029  
                 
 OPERATING EXPENSES
               
 Production Expenses
    94,389       1,398  
 Severance Taxes
    58,315       12,094  
 General and Administrative Expense
    568,635       507,883  
 Depletion of Oil and Gas Properties
    381,654       40,636  
 Depreciation and Amortization
    22,679       8,564  
 Accretion of Discount on Asset Retirement Obligations
    1,394       -  
 Total Expenses
    1,127,066       570,575  
                 
 LOSS FROM OPERATIONS
    (468,798 )     (283,546 )
                 
 OTHER INCOME (EXPENSE)
    (43,527 )     96,269  
                 
 LOSS BEFORE INCOME TAXES
    (512,325 )     (187,277 )
                 
 INCOME TAX PROVISION (BENEFIT)
    (205,000 )     -  
                 
 NET LOSS
  $ (307,325 )   $ (187,277 )
                 
 Net Loss Per Common Share – Basic and Diluted
  $ (0.01 )   $ (0.01 )
                 
 Weighted Average Shares Outstanding – Basic
    34,223,925       28,849,731  
                 
 Weighted Average Shares Outstanding - Diluted
    34,223,925       28,849,731  

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


3



NORTHERN OIL AND GAS, INC.
 
CONDENSED STATEMENTS OF CASH FLOWS
 
FOR THE THREE MONTHS ENDED MARCH 31, 2009 AND 2008
 
(UNAUDITED)
 
             
             
             
             
             
             
   
Three Months Ended
 
   
March 31,
 
   
2009
   
2008
 
 CASH FLOWS FROM OPERATING ACTIVITIES
           
 Net Loss
  $ (307,325 )   $ (187,277 )
 Adjustments to Reconcile Net Loss to Net Cash Used for Operating Activities:
               
 Depletion of Oil and Gas Properties
    381,654       40,636  
 Depreciation and Amortization
    62,910       8,564  
 Accretion of Discount on Asset Retirement Obligations
    1,394       -  
 Income Tax Benefit
    (205,000 )     -  
 Issuance of Stock for Consulting Fees
    -       49,875  
 Issuance of Stock for Compensation
    127,090       -  
 Market Value adjustment of Derivative Instruments
    -       (1,300 )
 Amortization of Deferred Rent
    (4,643 )     -  
 Share - Based Compensation Expense
    49,885       -  
 Changes in Working Capital and Other Items:
               
 Decrease (Increase) in Trade Receivables
    276,542       (220,015 )
 Increase in Other Receivables
    (61,431 )     -  
 Increase in Prepaid Expenses
    (50,719 )     (88,653 )
 Increase in Accounts Payable
    2,042,335       368,442  
 Decrease in Accrued Expenses
    (942,307 )     (95,818 )
 Net Cash Provided By (Used For) Operating Activities
    1,370,385       (125,546 )
                 
 CASH FLOWS FROM INVESTING ACTIVITIES
               
 Purchases of Office Equipment and Furniture
    (4,527 )     (202,234 )
 Decrease (Increase) in Prepaid Drilling Costs
    (240,734 )     364,290  
 Decrease on Accrued Drilling Costs
    (4,579,458 )     -  
 Increase in Short-term Investment, net
    -       (3,800,524 )
 Increase in Oil and Gas Properties
    (2,203,969 )     (6,118,134 )
 Net Cash Used For Investing Activities
    (7,028,688 )     (9,756,602 )
                 
 CASH FLOWS FROM FINANCING ACTIVITIES
               
 Increase in Checks Issued, not Cashed
    -       177,741  
 Increase in Margin Loan
    -       1,519,487  
 Payments on Line of Credit
    (8,663 )     -  
 Advances on Revolving Credit Facility
    6,000,000       -  
 Cash Paid for Listing Fee
    -       (65,000 )
 Increase in Subordinated Notes, net
    500,000       -  
 Debt Issuance Costs Paid
    (973,646 )     -  
 Proceeds from Exercise of Stock Options
    -       105,000  
 Net Cash Provided by Financing Activities
    5,517,691       1,737,228  
 
 
4

 
                 
 NET DECREASE IN CASH AND CASH EQUIVALENTS
    (140,612 )     (8,144,920 )
                 
 CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD
    780,716       10,112,660  
                 
 CASH AND CASH EQUIVALENTS – END OF PERIOD
  $ 640,104     $ 1,967,740  
                 
                 
 Supplemental Disclosure of Cash Flow Information
               
 Cash Paid During the Period for Interest
  $ 14,048.00     $ -  
 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
  $ -     $ 1,047,048  
 Payment of Consulting Fees through Issuance of Common Stock
  $ -     $ 49,875  
 Payment of Compensation through Issuance of Common Stock
  $ 261,280     $ -  
 Capitalized Asset Retirement Obligations
  $ 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     $ -  


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

 
5

 

NORTHERN OIL AND GAS, INC.
NOTES TO FINANCIAL STATEMENTS
March 31, 2009


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.  Prior to March 20, 2007, our name was “Kentex Petroleum, Inc.”  The Company took its present form on March 20, 2007, when Kentex completed a so-called short-form merger with its wholly-owned subsidiary, Northern Oil and Gas, Inc. (“NOG”), a Nevada corporation engaged in the Company’s current business, in which NOG merged into Kentex and Kentex was the surviving entity.  The Company’s common stock trades on the American Stock Exchange under the symbol “NOG”.

The Company will continue to focus on 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.  We participate on a heads up basis in the drilling of wells on our leasehold.  We own working interest in wells, and do 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 will likely drill in 2009 and beyond.  We believe the advantage gained by participating as a non-operating partner in the 53 gross oil wells completed in 2008 and the first quarter 2009 has given us valuable data on completions and will help to control well costs and enhance results as we begin to develop our high working interest sections in mid-2009.

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 minority interests ranging from 1% to 42%, we expect to participate in the drilling of incrementally higher working interest drilling units, eventually operating our substantial inventory of high working interest drilling units with a range of 40% to 100% ownership.  We control approximately 70,000 net acres in the growing North Dakota Bakken Play.  This exposes us to 110 net wells based on 640 acre spacing units.  To be more specific, if we drill a well and participate with a 25% working interest, this counts towards this total as a quarter of one well.  Down spacing in the field will potentially expose us to significantly more wells as development continues on “held by production” acreage. Further, the productivity of the Three Forks/Sanish and secondary recovery expose us to substantially more potential reserves.

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 PRACTICES

The financial information included herein is unaudited, except the balance sheet as of December 31, 2008, which has been derived from our audited financial statements as of December 31, 2008.  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.

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, 2008, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

 
6

 

Cash, Cash Equivalents, and Long-Term Investments

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 SIPC protection on a vast majority of our financial assets.

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 $22,679 for the three months ended March 31, 2009.

Debt Issuance Costs

In February 2009, the Company entered into a revolving credit facility with CIT Capital USA, Inc. (CIT) (see Note 8).  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-Sholes 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 will be amortized for three years over the term of the facility using the effective interest method.  The amortization for the three months ended March 31, 2009 was $40,231.

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, 2009 and December 31, 2008, 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 Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment.”  This statement requires us to record an expense associated with the fair value of stock-based compensation.  We currently 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 Statement No. 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.  SFAS 109 requires 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.

 
7

 


Stock Issuance

The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in EITF No. 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

Net Income (Loss) per common share is based on the Net Income (Loss) divided by weighted average number of common shares outstanding.

Diluted earnings per share are computed using weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method.  As the Company has a loss for the three months ended March 31, 2009 the potentially dilutive shares are anti-dilutive and are thus not added into the earnings per share calculation.

As of March 31, 2009 there were 400,000 potentially dilutive shares from stock options that became exercisable in 2007.

In addition, as of March 31, 2009, 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 $278,352 of internal costs for the three months ended March 31, 2009.

As of March 31, 2009 we controlled approximately 22,000 net acres of leaseholds in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. We controlled approximately 70,000 net acres in North Dakota, primarily in Mountrail County, targeting the Bakken Shale and approximately 10,000 net acres 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 the year ended December 31, 2008 the Company sold acreage for $468,609.  The proceeds for these sales were applied to reduce the capitalized costs of oil and gas properties. There were no property sales for the three months ended March 31, 2009.

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 Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (SFAS 143) 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.


 
8

 

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 period-end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.  Such present value of proved reserves’ future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the Balance Sheet (following SEC Staff Accounting Bulletin No. 106).  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, even in the current lower price environment. 

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, and deferred income taxes.  Actual results may differ from those estimates.

Derivative Instruments and Price Risk Management

The Company uses derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of 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 would be based on expected production from existing wells.  The Company has, and continues to use exchange traded futures contracts and option contracts to hedge the delivery price of oil at a future date.

Derivatives 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 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 are 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 is recognized in current period earnings as income or loss from derivative.  Gains and losses on derivative instruments that do not qualify for hedge accounting are included in income or loss from derivative in the period in which they occur.  The resulting cash flows from derivatives are reported as cash flows from operating activities.

At the inception of a derivative contract or upon identification of hedged production to which a derivative contract applies, the Company may designate the derivative as a cash flow hedge.  For all derivatives designated as cash flow hedges, the Company formally documents 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 measures hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is 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 13 for a description of the derivative contracts which the Company executed during 2009.

Impairment

SFAS 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.

New Accounting Pronouncements

 
9

 


In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities."  SFAS 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity's financial position, financial performance, and cash flows.  SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  Pursuant to the transition provisions of the Statement, the Company adopted SFAS No. 161 on January 1, 2009.  The required disclosures are presented in Note 13 on a prospective basis. This Statement does not impact the financial results as it is disclosure-only in nature.

In April 2009, the FASB issued FSP FAS 107-1 and Accounting Principles Board (APB) 28-1 “Interim Disclosures about Fair Value of Financial Instruments”. The FSP amends SFAS No. 107 “Disclosures about Fair Value of Financial Instruments” to require an entity to provide disclosures about fair value of financial instruments in interim financial information. This FSP is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The Company will include the required disclosures in its quarter ending June 30, 2009.

In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157.” FSP FAS 157-2 delayed the effective date of SFAS No. 157 “Fair Value Measurements” from 2008 to 2009 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of the provisions of SFAS No. 157 related to nonfinancial assets and nonfinancial liabilities on January 1, 2009 did not have a material impact on the Financial Statements. See Note 11 for SFAS No. 157 disclosures.

In March 2009, the FASB released Proposed Staff Position SFAS 157-e, "Determining Whether a Market Is Not Active and a Transaction Is Not Distressed".  This proposal provides additional guidance in determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurement purposes as defined in SFAS 157, "Fair Value Measurements."  SFAS 157-e is effective for interim periods ending after June 15, 2009, but early adoption is permitted for interim periods ending after March 15, 2009.  The Company plans to adopt the provisions of SFAS 157-e during second quarter 2009, but does not believe this guidance will have a significant impact on the Company's financial position, cash flows, or disclosures.

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments”. The guidance applies to investments in debt securities for which other-than-temporary impairments may be recorded. If an entity’s management asserts that it does not have the intent to sell a debt security and it is more likely than not that it will not have to sell the security before recovery of its cost basis, then an entity may separate other-than-temporary impairments into two components: 1) the amount related to credit losses (recorded in earnings), and 2) all other amounts (recorded in other comprehensive income). This FSP is to be applied prospectively and is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The Company will adopt this FSP for its quarter ending June 30, 2009. There is no expected impact on the Financial Statements.

NOTE 3                 LONG-TERM INVESTMENTS

All marketable debt and equity securities that are included in long-term investments are considered available-for-sale and are carried at fair value.  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 is a summary of our long-term investments as of March 31, 2009:
   
Cost at
March 31, 2009
   
Unrealized
(Loss)
   
Fair Market
Value at
March 31,
2009
 
Auction Rate Municipal Bonds
 
$
2,550,000
   
$
(247,786
)
 
$
2,302,214
 
Auction Rate Preferred Stock
   
275,143
     
(15,733
)
   
259,410
 
      Total Long-Term Investments
 
$
2,825,143
   
$
(263,519
)
 
$
2,561,624
 

For the three months ended March 31, 2009 there were no realized gains or losses recognized on the sale of investments.  In November 2008 we received, in a settlement from UBS AG (“UBS”), rights which allow us to put back the auction rate securities at par value to UBS.  We expect to liquidate these investments at par no later than June 2010, in the meantime they continue to pay interest at various rates.  We also have the ability to borrow up to 75% of the loan-to-market value of eligible

 
10

 

auction rate securities on a no-net cost basis.  As of March 31, 2009, we have borrowed $1,642,057 under the agreement, with an additional $476,693 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 SFAS No. 115, and FSP No. FAS 115-1 and FAS 124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” and to determine the classification of the impairment as temporary or other-than-temporary.   In determining if the difference between cost and estimated fair value of the auction rate securities was deemed either temporary or other-than-temporary impairment, the Company evaluated each type of long-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 investments in the auction rate securities were temporary as of March 31, 2009, primarily based on estimated cash flows of the investments, the settlement agreement entered into with UBS, and the Company’s ability and intent to hold such investments until settlement.


NOTE 4                 PROPERTY AND EQUIPMENT

Property and equipment at March 31, 2009, consisted of the following:
   
March 31, 2009
 
Oil and Gas Properties, Full Cost Method
     
  Unevaluated Costs, Not Subject to Amortization or Ceiling Test
 
$
39,482,967
 
  Evaluated Costs
   
18,558,058
 
     
58,041,025
 
Office Equipment, Furniture, Leasehold Improvements and Software
   
412,927
 
     
58,453,952
 
Less:  Accumulated Depreciation, Depletion, and Amortization
       
  Property and Equipment
   
1,260,343
 
      Total
 
$
57,193,609
 




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

 
Three Month Period Ended
March 31,
 
 
2009
 
2008
 
Depletion of Costs for Evaluated Oil and Gas Properties
 
$
381,654
     
40,636
 
Depreciation of Office Equipment, Furniture, and Software
   
22,679
     
8,564
 
      Total Depreciation, Depletion, and Amortization Expense
 
$
404,333
   
$
49,200
 


NOTE 5                 PREFERRED AND COMMON STOCK

The Company has neither authorized nor issued any shares of preferred stock.

No stock of the Company was issued in the three months ended March 31, 2009.

Restricted Stock Awards

In March 2008, the Company issued 20,000 shares of restricted common stock to employee James Sankovitz pursuant to a written employment agreement.  The issuance of restricted stock is intended to retain and motivate the employee.  The fair value of the award was $140,500 or $7.03 per share, the average market value of a share of Common Stock on the date the stock was issued. The fair value was expensed over the one-year term of the award.  The Company expensed $35,125 related to this award in the three months ended March 31, 2009.  The shares are fully vested at March 31, 2009.  Vesting of the shares was contingent on the employee maintaining employment with the Company and other restrictions included in the employment agreement.

 
11

 


In February 2009, the Company granted 60,000 shares of restricted common stock to employees James Sankovitz and Chad Winter pursuant to written agreements.  The grants of restricted stock are intended to retain and motivate the employees.  The fair value of the awards was $170,400 or $2.84 per share, the market value of a share of common stock on the date the stock was granted.  30,000 of the shares become fully vested on January 1, 2010 and 30,000 of the shares become fully vested on January 1, 2011.  The fair value will be expensed evenly over the term of the award.  The Company expensed $14,760 related to those awards in the three months ended March 31, 2009.  Vesting of the awards is contingent on the employees maintaining employment with the Company and other restrictions in the agreement.

Obligations to Issue Stock

In February 2009, the Company agreed to issue 92,000 shares of Common Stock to three employees of the company.  The employees are fully vested in the shares on the date of the grant.  The fair value of the stock to be issued was $261,280 or $2.84 per share, the market value of a 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, 2009.  The shares will be issued as soon as possible following receipt of approval by the Company's shareholders and approval of the shares for listing on the American Stock Exchange.

On February 27, 2009, the Company closed on a revolving credit facility with CIT Capital USA, Inc. (CIT).  As part of this credit facility agreement the Company entered into an engagement with Cynergy Advisors, LLC (Cynergy).  As part of the compensation for the work performed on obtaining the financing, Cynergy is due 180,000 shares of restricted Common Stock of the Company.  The fair value of the restricted stock to be issued is $475,200 or $2.64 per share, the market value of a share of Common Stock on the date the financing closed.  The fair value of this stock was capitalized as Debt Issuance Costs and will be amortized for three years over the term of the financing.  The shares will be issued as soon as possible.

NOTE 6                 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 shareholder in the Company.

The Company has also purchased leasehold interests 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 from Gallatin Resources, LLC.  Carter Stewart, one of NOG’s directors, owns a 25% interest in Gallatin Resources, LLC.
 
All transactions involving related parties were approved by the Company’s Board of Directors or Audit Committee and the Company obtained independent verification of the fairness of consideration paid in each transaction.

NOTE 7                 STOCK OPTIONS/STOCK BASED COMPENSATION

On November 1, 2007 the Board of Directors granted 560,000 of options under the 2006 Stock Option Plan.  The Company granted 500,000 options, in aggregate, to members of the board and 60,000 options to one employee pursuant to an employment agreement.  These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date.  160,000 options granted in 2007 have been exercised as of March 31, 2009.

The Company accounts for stock-based compensation under the provisions of SFAS No. 123(R), “Share Based Payment.”  This statement requires us to record an expense associated with the fair value of stock-based compensation.  We currently 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.  The total fair value of the options will be recognized as compensation over the vesting period.  The Company received no cash consideration for these option grants.  There have been no stock options granted in 2008 or 2009 under the 2006 Stock Option Plan, and all exercises of options during 2008 related to prior period grants.

Currently Outstanding Options

No options were exercised in the three months ended March 31, 2009.
No options were forfeited or granted during the three months ended March 31, 2009.
400,000 options are exercisable and outstanding as of March 31, 2009.
There is no further compensation expense that will be recognized in future years, relating to all options that have been granted as of March 31, 2009, since the entire fair value compensation has been recognized.
 
 
12

NOTE 8  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 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 its interests in proved reserves estimated to be produced from its oil and gas properties.  $11 million of financing is initially available under the Facility.  An additional $14 million of financing could become available upon subsequent borrowing base redeterminations based on the deployment of funds from the Facility.  The Facility terminates on February 27, 2012, with all outstanding borrowings due at that time.   The Company had borrowed $6 million under the facility at March 31, 2009.

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. At March 31, 2009 the weighted average interest rate on the outstanding borrowings was approximately 6.2%.

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, 2009, 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.  The hedged production is estimated to be equal to approximately 20% of 2009 total production and less than 10% of production volumes in 2010-12.  See Note 13 for additional disclosure concerning these swap agreements.

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 9                 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 SFAS 143, 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 SFAS 143 during the three months ended March 31, 2009.

 
$
61,437
 
Liabilities Incurred for New Wells Placed in Production
   
22,299
 
Accretion of Discount on Asset Retirement Obligations
   
1,394
 
Ending Asset Retirement Obligation
 
$
85,131
 
 
 
13

 
NOTE 10                      INCOME TAXES

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with SFAS No. 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 expense (benefit) for the three months ended March 31, 2009 and 2008 consists of the following:
       
   
Three Months Ended
March 31,
 
 
2009
 
2008
 
Current Income Taxes
 
$
-
   
$
-
 
Deferred Income Taxes
               
  Federal
   
(175,000
)
   
-
 
  State
   
(30,000
)
   
-
 
      Total Benefit
 
$
(205,000
)
 
$
-
 

In June 2006, the FASB issued Interpretation No. 48 “Accounting for Uncertainty in Income Taxes, and Interpretation of FASB Statement No. 109” (FIN 48).  We adopted FIN 48 on January 1, 2007.  Under FIN 48, 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 FIN 48, 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 FIN 48 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, 2009, 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, 2009 relating to unrecognized benefits.

The tax years 2008, 2007 and 2006 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

NOTE 11                      FAIR VALUE

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, 2009.  
 
   
Quoted Prices
In Active
Markets for
Identical Assets
(Level 1)
   
Significant
Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
 
Current Derivative Liabilities
 
 $
        -
   
        (292,015)
   
               -
 
Non-Current Derivative Liabilities
   
        -
     
(706,708)
     
               -
 
Long-Term Investments (See Note 3)
   
        -
     
        -
     
   2,561,624
 
   Total
 
 $
        -
   
(998,723)
   
   2,561,624
 


 
14

 

Level 2 liabilities consist of derivative liabilities (see Note 13).  Under SFAS 157, the fair value of the Company's derivative financial instruments is determined based on the counterparties' valuation models that utilize market corroborated inputs.  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 ($2,825,143) 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.   Based on this, along with the underlying maturities of the securities, a portion of which is greater than 30 years, the Company has classified auction rate securities as long-term assets on our 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, 2009, the Company’s investment advisors provided a valuation based on Level 3 inputs for the ARS investments.  The investment advisors 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, 2009, 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 $2,561,624, which represents a decline in value of $263,519 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 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, 2009
  
$
2,416,369
 
Unrealized Gain Included in Other Comprehensive Income (Loss)
  
 
145,255
 
Balance at March 31, 2009
  
 
2,561,624
 


 
15

 



NOTE 12                      FINANCIAL INSTRUMENTS

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and the line of credit. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and the 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, 2009 and December 31, 2008 do not represent significant credit risks as they are dispersed across many counterparties.

NOTE 13                      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.

Crude Oil Derivative Contracts Cash-flow Hedges

The Company's cash-flow hedges consisted of crude oil futures contracts.  As of March 31, 2009 the Company hedged 112,500 barrels of production thru February 2012 at approximately $51.25 per barrel of oil.  The contracts were used to establish floor prices on anticipated future oil production. There were no net premiums received or paid when the Company entered into these contracts.  At settlement any realized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the statement of operations.

NOTE 14                      COMPREHENSIVE INCOME

The Company follows the provisions of SFAS No. 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 Month Period Ended March 31,
 
   
2009
   
2008
 
Net Income (Loss)
 
$
(307,325
 
$
(187,277
)
Unrealized Gains on Marketable Securities
 (net of tax of $63,000)
   
82,255
     
 -
 
 Unrealized Loss on Derivative Liabilities (net of tax of $400,000)
   
(598,723
)
   
 -
 
Comprehensive Income (Loss) Net
 
$
(823,793
 
$
(187,277
)

 
 
16

 

Item 2. Management’s Discussion and Analysis or Plan of Operation.

The following updates information as to our financial condition and plan of operation provided in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.  The following also analyzes our results of operations for three month periods ended March 31, 2009 and March 31, 2008.

Except as discussed below, a discussion of our past financial results is not pertinent to the business plan of the Company on a going forward basis, due to the change in our business which occurred upon consummation of the merger on March 20, 2007.

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:  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 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 these 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 in these statements.  Forward-looking statements speak only as of the date they are made.  You should consider carefully the statements in this “Item 1A. Risk Factors” and other sections of this report, 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.

Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report.  We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation.  Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the Securities and Exchange Commission which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows.  If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

Overview and Outlook

We are an oil and gas exploration and production company.  Our properties are located in Montana, North Dakota and New York.  Our corporate strategy is to build shareholder value through the development and

 
17

 

acquisition of oil and gas assets that exhibit economically producible hydrocarbons.  We currently control the rights to mineral leases on approximately 215,000 gross acres of land, 102,000 net acres of land.

During the quarter ended March 31, 2009, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  We drilled and completed17 gross wells (approximately 0.98 net wells) during the quarter with total capital expenditures of approximately $5,096,000.

Production History
 
The following table presents information about our produced oil and gas volumes during the three months ended March 31, 2008 compared to the three months ended March 31, 2009.  As of March 31, 2009, we were selling oil and natural gas from a total of 53 gross wells (approximately 3.15 net wells), compared to 4 gross wells (approximately 0.27 net wells) at March 31, 2008.  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.
 
   
Three Months Ended March 31,
   
2009
 
2008
Net Production:
       
Oil (Bbl)
 
27,560
 
3,143
Natural Gas (Mcf)
 
2,043
 
4
Barrel of Oil Equivalent (Boe)
 
27,901
 
3,144
         
Average Sales Prices:
       
Oil (per Bbl)
 
$  37.52
 
$ 90.89
Effect of oil hedges on average price (per Bbl)
 
$    0.64
 
$ 0.41
Oil net of hedging (per Bbl)
 
$  38.16
 
$ 91.30
Natural Gas (per Mcf)
 
$    5.94
 
$   9.25
Effect of natural gas hedges on average price (per Mcf)
 
                          --
 
--
Natural gas net of hedging (per Mcf)
 
$    5.94
 
$   9.25
         
Average Production Costs:
       
Oil (per Bbl)
 
$  3.42
 
$  0.44
Natural Gas (per Mcf)
 
$  0.31
 
$  0.50
Barrel of Oil Equivalent (Boe)
 
$  3.41
 
$  0.44

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, 2008 compared to the three months ended March 31, 2009.

 
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Three Months Ended March 31,
 
   
2009
   
2008
 
             
             
Depletion of oil and natural gas properties
  $ 381,654     $ 40,636  


Productive Oil Wells
 
The following table summarizes gross and net productive oil wells by state at March 31, 2008 and March 31, 2009.  A net well represents our percentage ownership of a gross well. No wells have been permitted or drilled on any of our Yates County, New York acreage.  The following table 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 flowback subsequent to fracture stimulation.

 
March 31,
 
2009
 
2008
 
Gross
 
Net
 
Gross
 
Net
North Dakota
            50
 
        2.42
 
              3
 
           .17
Montana
              3
 
          .73
 
              1
 
           .10
Total:
            53
 
        3.15
 
              4
 
           .27

Results of Operations for the periods ended March 31, 2008 and March 31, 2009.

Our first well commenced drilling in the fourth quarter of 2007, and we did not realize revenue from that well until the first quarter of 2008.  During 2008 we significantly increased our drilling activities, generated income and achieved net earnings in the third and fourth quarters of 2008 and for the 2008 fiscal year as a whole.  To-date, we have developed less than four percent (4.0%) of our total drillable acreage inventory and we expect to continue to add substantial volumes of production on a quarter-over-quarter basis going forward into the foreseeable future.
 
As of March 31, 2009, we had established production from 53 total wells in which we hold working interests, only four of which had established production as of March 31, 2008.  Our production at March 31, 2009 approximated 792 barrels of oil per day, however several wells operated by others were producing on tight chokes due to commodity prices.  This compares to approximately 50 barrels of oil per day as of March 31, 2008.

During the first quarter we experienced lower than expected production due to several high rate wells being placed on tight chokes.  As of May 8, 2009 we have seen some of these wells return to normal production levels and expect to see additional increases in production due to rising commodity prices and differentials returning to historical levels.

We drilled with a 100% success rate in the quarter ended March 31, 2009.  We have 50 Bakken or Three Forks wells completed and 3 successful Red River discoveries at March 31, 2009.  As of March 31, 2009, we expect to participate in the drilling of approximately 60-70 gross oil wells (six to seven net) in 2009.

Total expenses for the three-month period ended March 31, 2008, were $570,575 and for the three-month period ended March 31, 2009, were $1,127,066.  We had a net loss of $187,277 for the three-month period ended March 31, 2008, and a net loss of $307,325 (representing approximately $0.01 per share) for the three-month period ended March 31, 2009.

 
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Operation Plan

During the quarter ended March 31, 2009, we continued the development of our oil and gas properties primarily in the Williston Basin Bakken play.  We recognized $640,734 in revenues from sales of oil and natural gas for the three months ended March 31, 2009, compared to $285,729 for the three months ended March 31, 2008.  Our future financial results will depend primarily on: (i) the ability to continue to source and screen potential projects; (ii) the ability to discover commercial quantities of oil and gas; (iii) the market price for oil and gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources.  There can be no assurance that we will be successful in any of these respects, that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding to increase our currently limited capital resources.

2009 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 17 gross wells (approximately 0.98 net wells) during the quarter with total capital expenditures of $5,096,000.  In 2009, we intend to continue drilling efforts on our existing acreage covering an aggregate of approximately 92,000 net mineral acres in North Dakota and Montana, and to commence drilling or participate in at least 60 new gross wells including first quarter completions.

The following table sets forth our drilling activity for the last three years.  The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value.  Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

As of March 31, 2009, we have a total of 77 wells that are either drilling, completing or producing, including 53 producing wells and 24 drilling or completing wells.  The following table sets forth wells that have been completed and are producing oil as of March 31, 2009:

Well Name
 
County
 
Operator
 
Northern Oil Working Interest
Bergstrom Trust 26-1H
 
Mountrail, ND
 
Brigham Exploration
 
6.2500%(1)
Friedrick Trust 31-1
 
Sheridan, MT
 
Brigham Exploration
 
23.31750%
Hallingstad 27-1H
 
Mountrail, ND
 
Brigham Exploration
 
8.4375%(2)
Richardson 25-1
 
Sheridan, MT
 
Brigham Exploration
 
37.0000%
Richardson 30-1
 
Sheridan, MT
 
Brigham Exploration
 
12.5000%(3)
Johnson 33-1H
 
Mountrail, ND
 
Brigham Exploration
 
12.5000%(4)
Bonney 34-3H
 
Dunn, ND
 
Burlington Resources
 
2.7344%
Shonna  1-15H
 
Divide, ND
 
Continental Resources
 
14.8438%
Skachenko 1-31H
 
Dunn, ND
 
Continental Resources
 
6.2500%
Elveida  1-33H
 
Divide, ND
 
Continental Resources
 
9.8631%
Arvid 1-34H
 
Divide, ND
 
Continental Resources
 
4.8622%
Landblom 1-35 H
 
Divide, ND
 
Continental Resources
 
0.3125%
Oilers 1H-10
 
Richland, MT
 
Crusader Energy
 
6.5972%
Wayzetta   1-13H
 
Mountrail, ND
 
EOG Resources
 
6.2500%
Austin 19-30H
 
Mountrail, ND
 
EOG Resources
 
3.0925%(5)
Clearwater 1-2H
 
Mountrail, ND
 
EOG Resources
 
3.6431%
Fladeland 11-30H
 
Mountrail, ND
 
Fidelity Exploration
 
1.1405%
En-Neset-0706H-1
 
Mountrail, ND
 
Hess Corporation
 
2.8000%
En-Person-1102H-1
 
Mountrail, ND
 
Hess Corporation
 
12.1809%
 
 
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Rs-Agribank-1102H-1
 
Mountrail, ND
 
Hess Corporation
 
4.7880%(6)
En-Hynek-0112H-1
 
Mountrail, ND
 
Hess Corporation
 
0.7811%
Bl-Blanchard-155-96-1522H-1
 
Williams, ND
 
Hess Corporation
 
2.5000%
RS-Armour
 
Mountrail, ND
 
Hess Corporation
 
2.34375%
En-Enget
 
Mountrail, ND
 
Hess Corporation
 
2.50001%
RS-Thompson
 
Mountrail, ND
 
Hess Corporation
 
2.345069%
Bangen 41-27H
 
Mountrail, ND
 
Marathon Oil Company
 
5.7813%
Shobe 24-20H
 
Mountrail, ND
 
Marathon Oil Company
 
0.7440%
Reiss  34-20H
 
Dunn, ND
 
Marathon Oil Company
 
2.4509%
Kent Carlson  24-36H
 
Dunn, ND
 
Marathon Oil Company
 
6.2500%
Voigt 11-15H
 
Dunn, ND
 
Marathon Oil Company
 
0.7919%
Clive Pelton 34-23H
 
Dunn, ND
 
Marathon Oil Company
 
1.1719%
Kovaloff 21-17H
 
Dunn, ND
 
Marathon Oil Company
 
0.6250%
Strommen 14-8H
 
Dunn, ND
 
Marathon Oil Company
 
2.5008%
Eckelberg 41-26H
 
Dunn, ND
 
Marathon Oil Company
 
0.3900%
Mark Sandstrom 14-32H
 
Mountrail, ND
 
Marathon Oil Company
 
3.8691%
Jay Sandstrom 34-31H
 
Mountrail, ND
 
Marathon Oil Company
 
0.4771%
Jodi Carlson 24-12H
 
Dunn, ND
 
Marathon Oil Company
 
1.2500%
Norton 24-12H
 
Dunn, ND
 
Marathon Oil Company
 
1.2500%
Rick Clair  25-36H
 
Mountrail, ND
 
Murex Petroleum
 
6.2500%
Gladys 1-9H
 
McKenzie, ND
 
Newfield Exploration
 
2.6042%
Wisness 1-4H
 
   McKenzie, ND
 
Newfield Exploration
 
5.0000%
Nelson 1-26H
 
Mountrail, ND
 
Sinclair Oil
 
2.6042%
Pathfinder  1-9H
 
Mountrail, ND
 
Slawson Exploration
 
2.6000%
Voyager 1-28H
 
Mountrail, ND
 
Slawson Exploration
 
4.9609%
Prowler  1-16H
 
Mountrail, ND
 
Slawson Exploration
 
3.4375%
Payara  1-21H
 
Mountrail, ND
 
Slawson Exploration
 
2.3125%
Peacemaker 1-8H
 
Mountrail, ND
 
Slawson Exploration
 
14.4220%
Jericho 1-5H
 
Mountrail, ND
 
Slawson Exploration
 
42.0000%
Pet-Inc Federal 20-44
 
McKenzie, ND
 
St. Mary Land and Exploration
 
7.2006%
Moi 22-15H
 
Billings, ND
 
Whiting Oil & Gas
 
2.3438%
Braaflat 11-11H
 
Mountrail, ND
 
Whiting Oil and Gas
 
0.0100%
Federal 11-9H
 
Mountrail, ND
 
Whiting Oil and Gas
 
0.390625%
Sig 21X-6
 
Divide, ND
 
XTO Energy
 
1.4372%
 
­­­­­­­­­­___________________________

(1)  
Upon achieving payout, our working interest will increase to 24.5%.
(2)  
Upon achieving payout, our working interest will increase to 20.5%.
(3)  
Upon achieving payout, our working interest will increase to 21.25%.  Additionally, we have a 1.0% overriding royalty interest on all production from this well.
(4)  
Upon achieving payout, our working interest will decrease to 8.125%.
(5)  
Upon achieving payout, our working interest will increase to 4.02%.
(6)  
Upon achieving payout, our working interest will decrease to 3.1122%.

 
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(7) 
Including the wells set forth in the foregoing table, we estimate that over 250 sections in which we have acreage interests have been included in permits to drill wells within North Dakota and Montana.  We do not know if or when applicable operators will chose to commence drilling activities for any contemplated well that is not yet drilling.

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, however, if we do not generate sufficient sales revenues we will continue to finance our operations through equity and/or debt financings.

The following table summarizes total current assets, total current liabilities and working capital at March 31, 2009.  We note, however, that approximately $2.5 million of Auction Rate Securities are not classified as current assets and we have subsequently entered into a credit facility with CIT Capital USA, Inc. during the quarter that we believe will address both our short-term and long-term liquidity needs.  As of March 31, 2009 we had $5,000,000 in available funds under our CIT facility and up to $14,000,000 in additional liquidity based on updated strip pricing and recent reserve additions.

Current Assets                  $      5,670,943
 
Current Liabilities             $    10,597,829
 
Working Capital                $   (4,926,886)


CIT Capital USA, Inc. Credit Facility

On February 27, 2009, we 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 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 its interests in proved reserves estimated to be produced from its oil and gas properties.  $11 million of financing is initially available under the Facility.  An additional $14 million of financing could become available upon subsequent borrowing base redeterminations based on the deployment of funds from the Facility.  The Facility terminates on February 27, 2012.

We have 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.  We have 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. At March 31, 2009 the weighted average interest rate on the outstanding borrowings was approximately 6.2%.

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 our company, default under any other material indebtedness we might have, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Facility.

 
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All of our 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.

Satisfaction of Our Cash Obligations for the Next 12 Months
 
With the addition of the CIT Facility, we believe we will be funded to meet our drilling commitments and expected general and administrative expenses for the next twelve months.  Nonetheless, any strategic acquisition of assets may require us to access the capital markets at some point in 2009.  We believe there may be distressed situations that will arise in 2009 that may make the acquisition of assets a viable strategy, and we will evaluate any potential opportunities 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 distressed 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 CIT Facility and anticipated funds from operations may not be sufficient to sustain continued acreage acquisition.  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, 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 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
 
As of March 31, 2009, we did not have any material long-term debt obligations other than the credit facility, capital lease obligations, operating lease obligations or purchase obligations requiring future payments except our office lease that expires on January 31, 2013, and contains a base rent of approximately $142,459 in 2009 and escalating up to approximately $160,236 during the final lease year.


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, 2008 and have not materially changed since that report was filed.

Hedging Activities
 
Our Facility with CIT requires that we enter into a swap agreement with Macquarie Bank Limited (“Macquarie”) to hedge a total of 118,000 barrels of production in total over the 36-month term of the Facility.  In general, we do not expect to use hedges beyond the extent required by our lenders.  As of March 31, 2009, our current hedging consisted exclusively of WTI-NYMEX crude oil swap agreements settled monthly, all of which were entered into on February 27, 2009 with a constant price of $51.25 per barrel:
 
 
23

 
Period
 
Notional Monthly Volume
(Barrels)
April 2009 through December 2009
 
5,500
January 2010 through December 2010
 
3,000
January 2011 through December 2011
 
2,000
January 2012 through February 2012
 
1,500

For the 2009 contracts listed above, a hypothetical $0.10 change in the WTI-NYMEX reference price above or below the fixed reference price applied to the notional amounts would cause a change in our gain (loss) on hedging activities in 2009 of $550.

 Interest Rate Risk
 
Our Facility entered into with CIT on February 27, 2009, subjects us to interest rate risk on borrowings under that facility.  Our Facility with CIT allows us to fix the interest rate of borrowings under our Facility 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 United States Securities and Exchange Commission (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, 2009, 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, 2009.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2009, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.


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.  No material developments have occurred in any pending litigation matters subsequent

 
24

 

to the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.  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 6.  Exhibits.
 
The exhibits listed in the accompanying exhibit index are filed as part of this Quarterly Report on Form 10-Q.
 


 
25

 

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 11, 2009
 
By:
/s/Michael Reger
       
Michael Reger, Chief Executive Officer and Director
         
Date:
May 11, 2009
 
By:
/s/Ryan Gilbertson
       
Ryan Gilbertson, Chief Financial Officer and Director


 
26

 

EXHIBIT INDEX


Exhibit Number
 
 
Exhibit Description
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
 


 
27