UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

T QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

£ 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 I.D. No.)

315 Manitoba Avenue – Suite 200

Wayzata, Minnesota 55391

 (Address of Principal Executive Offices)

(952) 476-9800

(Issuer’s Telephone Number)

N/A

(Former name, former address and former fiscal year,

if changed since last report)

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small 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  £

Non-Accelerated Filer  £                                                                  Smaller Reporting Company T

             (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No T

As of November 05, 2008, there were 34,092,164 shares of our common stock, par value $0.001, outstanding.

NORTHERN OIL AND GAS, INC.

FORM 10-Q

September 30, 2008

C O N T E N T S

	Page
PART I
Item 1.                    Financial Statements	1
Balance Sheets	1
Statements of Operations	2
Statements of Cash Flows	3
Notes to Unaudited Financial Statements	5
Item 2.                     Management’s Discussion and Analysis or Plan of Operation	15
Item 4T.                  Controls and Procedures	29
PART II
Item 1.                      Legal Proceedings	30
Item 2.                      Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 6.                      Exhibits	31
Signatures	32

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
SEPTEMBER 30, 2008 AND DECEMBER 31, 2007
ASSETS
	September 30,
	2008			December 31, 2007
	(Unaudited)
CURRENT ASSETS
Cash and Cash Equivalents	$	6,772,167		$	10,112,660
Trade Receivables		1,541,207			-
Derivative Asset		81,800			-
Prepaid Drilling Costs		24,376			364,290
Prepaid Expenses		121,897			25,680
Total Current Assets		8,541,447			10,502,630
PROPERTY AND EQUIPMENT, AT COST
Oil and Natural Gas Properties, Full Cost Method (including unevaluated costs of $32,294,808 at 9/30/08 and $7,587,511 at 12/31/2007)		39,529,287			7,587,511
Other Property and Equipment		269,084			44,769
Total Property and Equipment		39,798,371			7,632,280
Less - Accumulated Depreciation and Depletion		375,238			3,446
Total Property and Equipment, Net		39,423,133			7,628,834
AVAILABLE FOR SALE SECURITIES		3,320,975			-
Total Assets	$	51,285,555		$	18,131,464
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable	$	770,771		$	113,254
Accrued Expenses		3,296			110,993
Accrued Drilling Costs		2,614,855			-
Margin Loan		988,439			-
Total Current Liabilities		4,377,361			224,247
LONG-TERM LIABILITIES		-			-
Total Liabilities		4,377,361			224,247
STOCKHOLDERS' EQUITY
Common Stock, Par Value $.001; 100,000,000 Authorized, 34,024,644
Outstanding (2007 – Par Value $.001; 28,695,922 Shares Outstanding)		34,025			28,696
Additional Paid-In Capital		50,435,311			22,259,921
Retained Deficit		(3,413,393	)		(4,381,400	)
Accumulated Other Comprehensive Income (Loss)		(147,749	)		-
Total Stockholders' Equity		46,908,194			17,907,217
Total Liabilities and Stockholders' Equity	$	51,285,555		$	18,131,464

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

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NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007
(UNAUDITED)
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008		2007
REVENUES
Oil and Gas Sales	$	1,362,655	$	-		$	2,412,912	$	-
Gain on Derivatives		-		-			1,300		-
		1,362,655		-			2,414,212		-
OPERATING EXPENSES
Production Expenses		18,078		-			27,496		-
Severance Taxes		69,673		-			120,009		-
General and Administrative Expense		355,103		309,227			1,273,722		1,501,146
Depletion and Depreciation		203,103		260			371,792		780
Total Expenses		645,957		309,487			1,793,019		1,501,926
INCOME (LOSS) FROM OPERATIONS		716,698		(309,487	)		621,193		(1,501,926	)
OTHER INCOME		155,121		42,189			346,814		65,982
INCOME (LOSS) BEFORE INCOME TAXES		871,819		(267,298	)		968,007		(1,435,944	)
INCOME TAX PROVISION (BENEFIT)		-		-			-		-
NET INCOME (LOSS)	$	871,819	$	(267,298	)	$	968,007	$	(1,435,944	)
Net Income (Loss) Per Common Share – Basic and Diluted	$	0.03	$	(0.01	)	$	0.03	$	(0.06	)
Weighted Average Shares Outstanding – Basic		33,834,283		22,967,845			31,192,461		22,269,979
Weighted Average Shares Outstanding - Diluted		34,414,987		22,967,845			34,374,298		22,269,979

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

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NORTHERN OIL AND GAS, INC.
STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007
(UNAUDITED)
	Nine Months Ended
	September 30,
		2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	968,007		$	(1,435,944	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by (Used for) Operating Activities:
Depletion and Depreciation			371,792			780
Issuance of Stock for Consulting Fees			49,875			475,000
Market Value adjustment of Derivative Instruments			(95,148	)		-
Share – Based Compensation Expense			70,250			655,781
Increase in Trade Receivables			(1,541,207	)		-
Increase in Prepaid Expenses			(96,217	)		(20,088	)
Increase in Accounts Payable			657,517			-
Decrease in Accrued Expenses			(107,697	)		-
Net Cash Provided by (Used For) Operating Activities			277,172			(324,471	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Office Equipment and Furniture			(224,315	)		(14,082	)
Prepaid Drilling Costs			339,914			(210,000	)
Prepaid Lease Payments			-			(150,000	)
Increase in Accrued Drilling Costs			2,614,855			-
Purchase of Available for Sale Securities			(3,550,524	)		-
Oil and Gas Properties			(30,654,840	)		(3,561,087	)
Net Cash Used For Investing Activities			(31,474,910	)		(3,935,169	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Margin Loan			988,439			-
Repayments of Convertible Notes Payable (Related Party)			-			(165,000	)
Cash Paid for Listing Fee			(65,000	)		-
Proceeds from Derivatives			95,148			-
Proceeds from the Issuance of Common Stock – Net of Issuance Costs			25,904,858			15,015,053
Proceeds from Exercise of Stock Options			933,800			-
Net Cash Provided by Financing Activities			27,857,245			14,850,053
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(3,340,493	)		10,590,413
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD			10,112,660			849,935
CASH AND CASH EQUIVALENTS – END OF PERIOD		$	6,772,167		$	11,440,348
Supplemental Disclosure of Cash Flow Information

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Cash Paid During the Period for Interest	$	18,079	$	-
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	$	1,286,936	$	2,662,812
Payment of Consulting Fees through Issuance of Common Stock	$	49,875	$	475,000

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2008

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 60-70 gross oil wells we will drill in 2008 and early 2009 will give us valuable data on completions and help to control well costs 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 only minority interests ranging from 1% to 37%, 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 65,000 net acres in the growing North Dakota Bakken Play.  This exposes us to 101 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.

 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.  As of September 30, 2008 the substantial decline in oil prices has not affected the Company’s financial position in a material amount.

NOTE 2         BASIS OF PRESENTATION

The financial information included herein is unaudited, except the balance sheet as of December 31, 2007, which has been derived from our audited financial statements as of December 31, 2007.  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

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this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission.  These financial statements should be read in conjunction with the audited financial statements and notes for the year ended December 31, 2007, which are included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

New Accounting Pronouncements

In December 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 141(R), “Business Combinations.”  SFAS No. 141(R) changes the accounting for and reporting of business combination transactions in the following way:  Recognition with certain exceptions, of 100% of the fair values of assets acquired, liabilities assumed, and non controlling interests of acquired businesses; measurement of all acquirer shares issued in consideration for a business combination at fair value on the acquisition date; recognition of contingent consideration arrangements at their acquisition date fair values, with subsequent changes in fair value generally reflected in earnings; recognition of pre-acquisition gain and loss contingencies at their acquisition date fair value; capitalization of in-process research and development (IPR&D) assets acquired at acquisition date fair value; recognition of acquisition-related transaction costs as expense when incurred; recognition of acquisition-related restructuring cost accruals in acquisition accounting only if the criteria in Statement No. 146 are met as of the acquisition date; and recognition of changes in the acquirer’s income tax valuation allowance resulting from the business combination separately from the business combination as adjustments to income tax expense.  SFAS No. 141(R) is effective for the first annual reporting period beginning on or after December 15, 2008 with earlier adoption prohibited.  The adoption of SFAS No. 141(R) will affect valuation of business acquisitions made in 2009 and forward.    

In December 2007, the FASB issued SFAS No. 160 “Noncontrolling Interest in Consolidated Financial Statements – an Amendment of ARB 51” (SFAS 160).  SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest.  SAFS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  Earlier adoption is prohibited.  We do not anticipate a material impact upon adoption.

In March 2008, the FSAB issued FASS 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.  We do not anticipate a material impact upon adoption.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair value Measurements.”  SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.  SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements.  The provisions of SFAS 157 were originally to be effective beginning January 1, 2008.  Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in consolidated financial statements on a non-recurring basis.  We are currently evaluating the impact of adopting the provisions of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed on a non-recurring basis.

NOTE 3         SIGNIFICANT ACCOUNTING PRACTICES

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 evaluation expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities.  As of September 30, 2008, we controlled approximately 21,354 net acres of leaseholds in Sheridan County, Montana with primary targets including the Red River and Mission Canyon formations, approximately 65,000 net acres, primarily in Mountrail County, North Dakota, targeting the Bakken Shale and 10,000 net acres in Yates County, New York that is prospective for Marcellus Shale and Trenton-Black River natural gas production. See Note 6 for an explanation of activities on these properties.

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Proceeds from property sales generally will 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.

Costs capitalized will be 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 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.   The unamortized cost of the Company’s oil and gas properties did not exceed the ceiling limit as of September 30, 2008.  Therefore, the Company was not required to writedown the net capitalized costs of its oil and gas properties at September 30, 2008.

Other Property and Equipment

Property and equipment that are not oil and gas property 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 $33,713 for the nine months ended September 30, 2008.

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.

Cash, Cash Equivalents and Long Term Investments

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, specifically $6,717,245 of cash and cash equivalents and all of our long-term investments.

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 may continue 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

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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 10 for a description of the derivative contracts which the Company executes.

Stock-Based Compensation

The Company has accounted 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 average risk-free interest rate is determined using the U. S. Treasury rate in effect as of the date of grant, based on the expected term of the stock option.

Options Granted November 1, 2007

On November 1, 2007, the Board of Directors granted 560,000 options to board members and one employee.  The total fair value of the options was recognized as compensation in 2007 as the optionees were immediately vested.  In computing the expected volatility, we used the combined historical volatility of the Company’s common stock for a one month period and the blended historical volatility for two of our peer Companies over a period of four years and eleven months.  In computing the exercise price we used the average closing/last trade price of the Company’s common stock for the five highest volume trading days during the 30-day trading period ending on the last trading day preceding the date of the grants.

The following assumptions were used for the Black-Scholes model:

	November 1,
	2007
Risk free rates	4.36%
Dividend yield	0%
Expected volatility	56%
Weighted average expected stock option life	5 Years

The “fair market value” at the date of grant for stock options granted using the formula relied upon for calculating the exercise price is as follows:

Weighted average fair value per share	$	2.72
Total options granted		560,000
Total weighted average fair value of options granted	$	1,524,992

Income Taxes

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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.  FASB Statement No. 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.  As of September 30, 2008, the Company maintains a full valuation allowance for all deferred tax assets.

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.  Actual results could differ from those estimates.

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 September 30, 2008 and December 31, 2007, 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.

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 is computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. 

NOTE 4         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 September 30, 2008:

	Cost at September 30, 2008		Unrealized (Loss)			Fair Market Value at September 30, 2008
Auction Rate Municipal Bonds	$	2,550,000	$	(197,625	)	$	2,352,375
Auction Rate Preferred Stock		1,000,524		(31,924	)		968,600
Total Long-Term Investments	$	3,550,524	$	(229,549	)	$	3,320,975

For the three and nine months ended September 30, 2008 there were no realized gains or losses recognized on the sale of investments.  As of September 30, 2008, an unrealized loss on available-for-sale securities, net of tax, of $229,549 was included in accumulated other comprehensive income (loss) in the accompanying unaudited Balance Sheet.  At September 30, 2008 the Company evaluated its net unrealized losses and determined them to be temporary.  Factors considered in determining whether a loss is temporary included the length of time and extent to which the investments fair value has been less than the cost basis, the financial condition and near-term prospects of the investee, and the Company's intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in fair value.  Subsequent to September 30, 2008 we have 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

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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 auction rate securities on a no-net cost basis.  

NOTE 5         PROPERTY AND EQUIPMENT

Property and equipment at September 30, 2008, consisted of the following:

	September 30, 2008
Oil and Gas Properties, Full Cost Method
Unevaluated Costs, Not Subject to Amortization or Ceiling  Test	$	32,294,808
Evaluated Costs		7,234,479
		39,529,287
Office Equipment, Furniture, and Software		269,084
		39,798,371
Less: Accumulated Depreciation, Depletion, and Amortization		375,238
Property and Equipment	$	39,423,133

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

	Nine-Month Period Ended September 30,
	2008			2007
Depletion of Costs for Evaluated Oil and Gas Properties		$	338,079		$	-
Depreciation of Office Equipment, Furniture, and Software			33,713			260
Total Depreciation, Depletion, and Amortization Expense		$	371,792		$	260

NOTE 6         OIL AND GAS PROPERTIES

Recent Acquisitions – Related Party Transactions

In September 2007, we commenced a continuous lease program with South Fork Exploration, LLC. (“SFE”) to acquire acreage in and around Burke and Divide Counties of North Dakota.  As of September 30, 2008, the Company has paid SFE $615,600 for all acreage secured under the program. SFE’s president is J.R. Reger, brother of Michael Reger, the Company’s Chief Executive Officer.  J.R. Reger is also a shareholder in the Company.

On January 18, 2008, Montana Oil Properties, Inc. (“MOP”) assigned to the Company leases covering approximately 1,600 net acres in Mountrail County, North Dakota.  The total purchase price for this assignment is $800,000 in cash and 30,000 shares of restricted common stock.  As of June 30, 2008, MOP delivered an additional 885 acres.  The total purchase price for this assignment was $442,291 in cash and 16,587 shares of restricted stock.  The principals of MOP are Mr. Steven Reger and Mr. Tom Ryan, both are relatives of our Chief Executive Officer, Michael Reger.

Recent Acquisitions – Non-Related Party

On February 15, 2008, the Company entered into an agreement to acquire from Antares Exploration Fund, L.P. (“Antares”), leasehold interests covering up to 5,700 net acres in Mountrail County, North Dakota for an aggregate purchase price of $5,700,000.  On April 14, 2008, we entered into an Agreement setting forth a land bank arrangement with Deephaven MCF Acquisition, LLC (“Deephaven”), an affiliate of Deephaven Capital Management, LLC.  On April 14, 2008, pursuant to the land bank arrangement, Deephaven closed on the acquisition from Antares of leases covering 5,132 net acres for the Company's benefit, which leases can then be acquired by the Company at any time during the initial year that Deephaven owns such leases.  On April 14, 2008 and June 26, 2008, the Company closed on the purchase directly from Antares of an additional 277 net acres and 223 net acres in Mountrail County, North Dakota, respectively.  The foregoing transactions have resulted in the Company controlling an aggregate of 5,632.99 net acres purchased from Antares pursuant to the February 15, 2008 agreement. On September 26, 2008, the Company negotiated an amendment of certain terms of the February 15, 2008 land bank agreement altering the structure of the agreement in the Company’s favor.

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On May 21, 2008, the Company entered into an agreement to acquire from Ritter, Laber & Associates, Inc. leasehold interest on approximately 3,209 net acres in Mountrail and Burke Counties, North Dakota.  On July 1, 2008, the Company closed on this acquisition. The total purchase price for this assignment was $3,049,367 in cash.

On June 13, 2008, the Company entered into an agreement to acquire from Woodstone Resources, LLC leasehold interests on approximately 23,210 net acres in Dunn County, North Dakota.  On July 10, 2008, the Company closed on this acquisition.  The total purchase price for this assignment was $9,284,000 in cash.

The Company has also completed other miscellaneous acquisitions in North Dakota and Montana.

NOTE 7          PREFERRED AND COMMON STOCK

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

In March 2008, an optionee exercised 100,000 stock options granted to them in 2006.  The shares related to this exercise were not issued until April 2008.

In April 2008, an employee exercised 60,000 stock options granted in 2007.

In May 2008, a board member exercised 100,000 stock options granted in 2007.

In April, June, and July 2008 4,818,186 shares were issued related to the exercise of warrants issued in 2007.

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 will be expensed over the one-year term of the award.  The Company expensed $35,125 related to this award in the quarter ended September 30, 2008.  Vesting of the shares is contingent on the employee maintaining employment with the Company and other restrictions included in the employment agreement.

NOTE 8         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 Michael Reger, CEO of NOG.  J.R. Reger is also a shareholder in NOG.  See Note 6.

The Company also has 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.  See Note 6.

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

NOTE 9         STOCK OPTIONS/STOCK BASED COMPENSATION

On November 1, 2007 the Board of Directors granted an additional 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.  In April 2008, an employee exercised 60,000 options under this plan.  In May 2008, a member of the Board of Directors exercised 100,000 options under this plan.

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

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materially affect the fair value estimate.  The total fair value of the options will be recognized as compensation over the service period (see Note 2 for calculation of fair value).  The Company received no cash consideration for these option grants.  There have be no stock options granted in 2008 under the 2006 Stock Option Plan, and all exercises of options during 2008 related to prior period grants.

Currently Outstanding Options:

·   260,000 options were exercised in the nine months ended September 30, 2008.

·   No options were forfeited or granted during the nine months ended September 30, 2008.

·   400,000 options are exercisable and outstanding as of September 30, 2008.

·   The Company recorded compensation expense related to these options of $2,366,417 for the year ended December 31, 2007.  There is no further compensation expense that will be recognized in future years relating to options   that had been granted as of September 30, 2008, because the entire fair value compensation has been recognized.

NOTE 10       DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes commodity swap and option 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.  The Company has hedged 20,000 barrels of production thru the end of 2008 at approximately $105 per barrel of oil however no production has been hedged into 2009 or beyond.

Crude Oil Derivative Contracts Cash-flow hedges

The Company's cash-flow hedges consisted of crude oil futures contracts.  The contracts are 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.

The Company held derivative positions in the form of written call options that were not designated as hedges.  These positions were entered into as investment vehicles.  Also, futures contracts that cannot be matched with production for cash flow hedges were included as investment vehicles.

The following table provides a summary of the impact on earnings from future contracts settled, expiration of written call options and the changes in the fair values of these nondesignated derivative contracts as recorded as an increase or decrease in other income, for the three and nine months ended September 30, 2007 and September 30, 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
Increase in earnings due to changes in fair value or settlement of derivatives entered into as investment vehicles	$	105,200	$	-	$	123,536	$	-

The following table reflects open commodity derivative contracts at September 30, 2008, the associated volumes and the corresponding weighted average NYMEX reference price.

			Notional
	Derivative		Amount -	NYMEX
Settlement Period	Instrument	Hedge Strategy	Oil (Barrels)	Reference Price
Futures Contracts
12/01/08 - 12/31/08	Sold Future	Cash flow	20,000	$                                          104.35

NOTE 11       FAIR VALUE

SFAS 157 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 SFAS 157 as the exchange

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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 SFAS 157 must maximize the use of observable inputs and minimize the use of unobservable inputs.  The standard describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:

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

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

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

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of September 30, 2008.  The current asset amounts represent the fair values expected to be included in the results of operations in December 2008.

	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Current Derivative Assets (See Note 10)	$	-	$	81,800	$	-
Long-Term Investments (See Note 4)		-		-		3,320,975
Total	$	-	$	81,800	$	3,320,975

Level 3 assets consist of municipal bonds and floating rate preferred stock (see Note 4) 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 ($3,550,524) at anytime during a two-year period beginning June 30, 2010. The Offer is non-transferable and expires on November 14, 2008. On October 28, 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, we have 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 September 30, 2008, 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 September 30, 2008, 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 $3,320,975, which represents a decline in value of $229,549 from par.

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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 cash balance of $6,772,167, 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, 2008	$	-
Purchases		3,800,524
Unrealized loss included in other comprehensive income (loss)		(141,074	)
Balance at March 31, 2008		3,659,450
Sales/Maturities		(250,000	)
Unrealized loss included in other comprehensive income (loss)		(20,100	)
Balance at June 30, 2008		3,389,350
Unrealized loss included in other comprehensive income (loss)		(68,375	)
Balance at September 30, 2008	$	3,320,975

NOTE 12       COMPREHENSIVE INCOME

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income (loss)	$	871,819		$	(267,298	)	$	968,007		$	(1,435,944	)
Unrealized losses on marketable securities		(68,375	)		-			(229,549	)		-
Net unrealized gain on hedges		823,800			-			81,800			-
Other Comprehensive Income (loss) net	$	1,627,244		$	(267,298	)	$	820,258		$	(1,435,944	)

NOTE 13   SUBSEQUENT EVENTS

In October 2008, the Company received an Offer from UBS, one of its investment providers, to sell at par value auction-rate securities originally purchased from UBS ($3,550,524) at anytime during a two-year period beginning June 30, 2010. The Offer is non-transferable and expires on November 14, 2008. On October 28, the Company elected to participate in the Offer.

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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, 2007.  The following also analyzes our results of operations for nine month periods ended September 30, 2008 and September 30, 2007.

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 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, 2007, 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

We are a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties, and have focused our activities primarily on projects based in the Rocky Mountain Region of the United States, specifically the Williston Basin.  We have targeted specific prospects and began drilling for oil in the Williston Basin region in the fourth fiscal quarter of 2007.  As of November 4, 2008, we have completed 28 successful discoveries, consisting of 26 targeting the Bakken formation and 2 targeting a Red River Structure.  As of November 6, 2008, we are participating in the drilling of 15 Bakken and Three Fork/Sanish wells.  As of November 6, 2008, approximately 170 sections containing Northern’s acreage has been included in permitted or docketed-for-permit drilling locations.

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The Company participates on a heads up basis proportionate to its working interest in a declared drilling unit. More specifically, we pay for the drilling costs based on our working interest percentage and receive revenue from the oil and gas production based on the working interest percentage, minus landowner royalties, which typically range from 12% to 20%.  Although to this point we have participated with only minority interests ranging from 1% to 37%, 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 65,000 net acres in the growing North Dakota Bakken Play.  This exposes us to 101 net drilling locations 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 the total as a quarter of one well.  We control approximately 68 spacing units where we own in excess of 40% of the acreage, this gives us a substantial inventory of potential drilling locations that we could drill and operate on our own timing.  To drill our complete inventory of 101 net drilling locations we expect to participate in approximately 450 gross wells. As of November 6, 2008, we have developed approximately 2% of our North Dakota Bakken position.

We expect to participate in approximately 60 gross oil wells in 2008 and very early 2009 with an average working interest of 8% yielding approximately four net wells.  Based on the current pace of development, we expect to fully hold our Bakken acreage by production by 2011. Subsequent to this, we expect down spacing to yield significantly more net oil wells.  We expect our position to have the potential to yield approximately 50 million gross barrels of oil.  This is based on assumptions of 101 net wells and 500,000 barrels of recoverable oil per well. Operators have stated a range of approximately 250,000 to 900,000 barrels of recoverable oil.  Our assumption of 500,000 barrels of recoverable oil per well was derived from reported results from our operating partners and reservoir engineering data from our producing wells.  The pace of development and our assumptions are subject to change and it is possible that results may not be as favorable as we expect.  However we may also experience substantially higher reserves due to secondary recovery and enhanced completion techniques.  Based on currently planned wells, we expect to exit 2008 at a run rate of approximately 1,100 gross barrels of daily oil production.  After paying landowner royalties ranging from 12% to 20% this equates to approximately 900 barrels of daily production net to us.

At $65 dollar oil prices, our target exit rate of 900 barrels per day will produce a run rate of approximately $21 million in annualized cash flows entering 2009 if we were to stop drilling.  We expect this number to grow substantially through 2009 as we continue to add production.  Any fluctuation in the per barrel price of oil, the actual daily production from our wells or the number of wells in production entering 2009 would correspondingly increase or decrease our actual annualized cash flow at any point in time.  For instance, in the event that the price of oil decreases by ten percent from $65 per barrel, our annualized cash flows entering 2009 would equal approximately $19.2 million.  Conversely, in the event that the price of oil increases by ten percent from $65 per barrel, our annualized cash flows entering 2009 would equal approximately $23.4 million.

As an exploration company, our business strategy is to identify and exploit resources in and adjacent to existing or indicated producing areas that can be quickly developed and put in production at low cost based on the activity of larger drillers in the area.  We also intend to take advantage of our expertise in aggressive land acquisition to develop exploratory projects with attractive growth potential in focus areas and to participate with other companies in those areas to explore for oil and natural gas using state-of-the-art three-dimensional (3-D) seismic technology.  We believe our competitive advantage lies in our ability to acquire property in the most exciting new plays in a nimble and efficient fashion.  We are focused on low overhead, our expected cash expense burn rate is approximately $2 million for fiscal year 2008.  We believe we are in a position to most efficiently exploit and identify high production oil and gas properties.  We intend to continue to actively pursue the acquisition of properties that fit our profile.

We currently control the rights to mineral leases on approximately 96,354 net acres of land.  Our principal assets are located in the WillistonBasin region of the northern United States and Yates County, New York, and include the following primary positions as of September 30, 2008:

▪   Approximately 21,354 net acres located in Sheridan County, Montana, representing a stacked pay prospect;

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▪   Approximately 25,000 net acres located in Mountrail County North Dakota, within and surrounding to the north, south and west the Parshall Field currently being developed by EOG Resources and others to target the Bakken Shale;

▪   Approximately 10,000 net acres located in Burke and Divide Counties of North Dakota, in which we are targeting the Winnepegosis and Bakken Shales on acreage in close proximity to recent discoveries by Continental Resources and others in the formation;

▪   Approximately 25,000 net acres in and around Marathon Oil production in Dunn County, North Dakota; and

▪   Approximately 10,000 net acres located in the “Finger Lakes” region of Yates County, New York, in which we are targeting natural gas production from the Trenton/Black River, Marcellus and Queenstown-Medina formations.

We have also completed other miscellaneous, non material, acreage acquisitions in North Dakota and Montana.

Results of Operations for the fiscal year ended December 31, 2007 and the nine months ended September 30, 2008.

The Company is in the early stage of developing its properties in Montana, North Dakota and New York.  During the fiscal year ended December 31, 2007, our operations were limited primarily to technical evaluation of the properties and the design of development plans to exploit the oil and gas resources on those properties, as well as seeking opportunities to acquire additional oil and gas properties.  Accordingly, we had minimal production due to our wells commencing production near the end of the fourth quarter of 2007.  We completed drilling of our first wells and began selling limited quantities of oil and gas in the fourth quarter of 2007.   In the first three quarters of 2008, we increased production and expect to continue to grow production consistently throughout the remainder of 2008.

As of September 30, 2008, we recognized production revenues from 23 wells, of which twelve wells are located in Mountrail County, North Dakota, nine wells are located in Dunn County, North Dakota and two wells are located in Sheridan County, Montana.  Subsequent to quarter end, we added production from an additional five wells in the Bakken formation. Our third quarter revenue has increased approximately 80 % over the second quarter of 2008.

We did not recognize any oil and gas revenues for the twelve months ended December 31, 2007.  We realized our first meaningful revenues from production late in the quarter ended March 31, 2008, as we were able to establish commercial production in connection with new drilling activities commenced in 2007.    Revenues from oil and gas sales in the quarter ended September 30, 2008 were $1,362,655, compared to $764,528 in the quarter ended June 30, 2008.  Our average realized sales price for oil produced during the quarter ended September 30, 2008 was approximately $103.50 per barrel, compared to approximately $120.12 per barrel in the quarter ended June 30, 2008.  We expect that our revenues will continue to increase quarter-over-quarter for the fourth quarter of 2008 as we continue to drill new wells and establish commercial production from our existing and new wells.   Each fiscal quarter we continue to realize increased oil and natural gas volumes from wells put into production in prior fiscal quarters as well as additional wells drilled or completed in the current quarter.

Total operating expenses, including severance taxes, production expenses, general and administrative, and non-cash expenses of depletion and depreciation for the fiscal year ended December 31, 2007 were $4,513,189, for the quarter ended March 31, 2008 were $570,575, for the three months ended June 30, 2008 were $576,487 and for the three months ended September 30, 2008 were $645,957.  Our operating expenses for the three months ended September 30, 2008 consisted principally of general and administrative costs.  General and administrative costs for the three months ended September 30, 2008 were $355,103 compared to $410,736 for the three months ended June 30, 2008 and $507,883 for the three months ended March 31, 2008.  The decrease in third quarter general and administrative costs was approximately 40% under our previously announced budget of $500,000 per quarter.  We

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expect operating costs to continue to increase as we proceed with our development plans.  In the future we expect to incur increased geologic, geophysical, engineering and other personnel related costs.

We realized net income of $871,819 for the quarter ended September 30, 2008 and net income of $968,007 for the nine months ended September 30, 2008, compared to a net loss of $4,305,293 for the fiscal year ended December 31, 2007, a net loss of $187,277 for the quarter ended March 31, 2008, net income of $283,465 for the quarter ended June 30, 2008 and net income of $96,188 for the six months ended June 30, 2008.  Approximately $500,000 of the loss experienced during the fiscal year ended December 31, 2007 consisted of a cash expense, and the balance was related to share issuance costs which are expected to decrease substantially in 2008.  Approximately $125,546 of the loss experienced during the quarter ended March 31, 2008 consisted of cash expenses, and the balance was related to share issuance costs.  We expect the cash general and administrative expenses to run approximately $500,000 per quarter going forward, excluding any one-time charges.

Overview of Third Quarter 2008 Operational Results

In the quarter ended March 31, 2008, we began selling meaningful amounts of oil from wells that became operational in the fourth quarter of 2007.  In the quarter ended June 30, 2008, we continued to realize additional sales of oil from wells that were productive during the prior fiscal quarter and began selling meaningful amounts of oil from additional wells that became operational during the second fiscal quarter.  We continued that trend during the quarter ended September 30, 2008, as evidenced by a quarter-over-quarter increase in our net income.  We expect our revenue to continue to increase along with our oil production as we continue to participate in additional wells during the fourth quarter of 2008.

 North Dakota

We realized production revenues totaling $1,029,892 from 21 wells in North Dakota during the quarter ended September 30, 2008, of which 13 wells came into production during the third fiscal quarter of 2008.  As of September 30, 2008, we capitalized approximately $6,438,437 in acreage, drilling and future drilling costs for these wells.

 Montana

We realized production revenues totaling $332,763 from 2 wells in Montana during the quarter ended September 30, 2008.  Both of these wells were productive throughout the third quarter of 2008.  As of September 30, 2008, we capitalized approximately $707,743 in acreage, drilling and future drilling costs for these wells.

Third Quarter 2008 Operational Results

The following table illustrates selected operational data for the quarter ended September 30, 2008 compared to the quarter ended June 30, 2008.

Selected Operation Data:	Three Months Ended June 30, 2008		Three Months Ended September 30, 2008
Net Production:
Oil (Bbl)		6,350		13,111
Natural Gas (Mcf)		133		412

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Net Sales:		Three Months Ended June 30, 2008		Three Months Ended September 30, 2008
Oil	$	762,763	$	1,356,902
Natural Gas	$	1,765	$	5,753
Total Oil and Natural Gas sales	$	764,528	$	1,362,655
Average Sales Prices:
Oil (per Bbl)	$	120.12	$	103.50
Effect of oil hedges on average price (per Bbl)	$	-	$	-
Oil net of hedging (per Bbl)	$	120.12	$	103.50
Natural Gas (per Mcf)	$	13.31	$	13.97
Effect of natural gas hedges on average price (per Bbl)	$	-	$	-
Natural gas net of hedging (per Bbl)	$	13.31	$	13.97

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 at the end of the first three fiscal quarters of 2008.

	Three Months Ended June 30, 2008		Three Months Ended September 30, 2008
Depletion of oil and natural gas properties	$	106,942	$	190,501

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Operation Plan

During the fourth quarter of the fiscal year ended December 31, 2007, we commenced in earnest the development of our oil and gas properties in conjunction with our drilling partners.  These activities continued to build in the first three quarters of fiscal year 2008, and are anticipated to continue to grow throughout the fourth quarter of 2008 and beyond.  The Company has several projects that are in various stages of discussions and is continually evaluating oil and gas opportunities in the Continental United States.  We will continue to participate on a heads-up basis in the continuing development of our substantial Bakken acreage holdings.  We do not typically lease land to operators or dilute working interest.  We own our proportionate share of wells and we will continue to develop higher working interest sections going forward.  We will continue to acquire acreage in the play as it may become available as well as continually evaluate additional opportunities both in the Bakken and beyond.

Our future financial results will depend primarily on the following factors, among others:

Our ability to continue to source and screen potential projects;

Our ability to discover commercial quantities of oil and gas;

The market price for oil and gas; and

Our 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.

Drilling Projects

As of September 30, 2008, we had completed 23 successful discoveries, compared to ten successful discoveries completed as of June 30, 2008 and six successful discoveries completed as of March 31, 2008.  As of November 6, 2008, we have completed an additional five wells, for a total of 28 successful discoveries. As of November 6, 2008, we are participating in the drilling of 15 additional wells, all of which are expected to commence production in the fourth calendar quarter of 2008.  Approximately 170 sections containing NOG acreage  have been permitted or docketed for permit as of November 6, 2008.  We expect most, if not all, of these wells and potentially more will be drilled throughout 2009, although we have no control over the timing of such wells in our position as a non-operator in these particular wells.  In addition to the proposed drilling locations, we are making preparations to drill wells on some of our high working interest locations, potentially ranging up to 100% working interest.

Upon full development of our North Dakota acreage position, we anticipate that we will be able to drill up to 101 net wells based on 640-acre spacing.  In the event the Bakken field continues to be down spaced to 320-acre units, we could control as many as 203 net Bakken wells.  EOG Resources previously announced calculations of 9 million barrels of oil in place per 640-acre section in the Parshall Field, of which they believe they will recover 900,000 barrels with a single lateral well.  Based on a number of 500,000 barrels of recoverable oil per well, conservative relative to the EOG estimates, we may be exposed to approximately 50 million gross barrels of oil based on 640 acre spacing, excluding the Brigham joint venture acreage.  On continued down spacing to 320 acre drilling units, we could be exposed up to a potential 100 million barrels of oil.  In addition we believe significant amounts of oil may be recoverable from a second producing reservoir in the Three Forks/Sanish formation, this formation has the potential to increase reserves and productivity significantly.  We are currently participating in four wells operated by Continental Resources and have several planned that will be targeting this formation.  With the addition of the Three Forks/Sanish formation, our potential reserves may increase substantially.

Through the use of 3-D seismic data we have identified 8 high-grade conventional locations on our Sheridan County Position. Our full Montana acreage position is subject to the Brigham joint venture as long as

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Brigham continues to drill on it.  Should Brigham let 120 days pass without the spud of a new well the joint venture shall terminate.

The following table summarizes our producing wells as of November 6, 2008:

State/County	Operator	Well Name	Northern Oil and Gas Working Interest
NORTH DAKOTA – MOUNTRAIL	BRIGHAM EXPLORATION	BERGSTROM TRUST 26-1H	6.25%/24% BIAPO
NORTH DAKOTA – MOUNTRAIL	BRIGHAM EXPLORATION	HALLINGSTAD 27-1H	8.5%/20% BIAPO
NORTH DAKOTA – MOUNTRAIL	BRIGHAM EXPLORATION	RICHARDSON 25-1	37.00%
NORTH DAKOTA – MOUNTRAIL	BRIGHAM EXPLORATION	RICHARDSON 30-1	12.5%/21.25%BIAPO  (+ 1.00% ORRI)
NORTH DAKOTA – MOUNTRAIL	BRIGHAM EXPLORATION	JOHNSON 33-1H	12.75%
NORTH DAKOTA – MOUNTRAIL	MUREX PETROLEUM	RICK CLAIR  25-36H	6.25%
NORTH DAKOTA – MOUNTRAIL	WHITING OIL & GAS	BRAAFLAT  11-11H	1.00%
NORTH DAKOTA – MOUNTRAIL	WHITING OIL & GAS	FEDERAL 11-9H	.005%
NORTH DAKOTA – MOUNTRAIL	SINCLAIR OIL	NELSON 1-26H	3.00%
NORTH DAKOTA – MOUNTRAIL	SLAWSON EXPLORATION	PATHFINDER  1-9H	3.00%
NORTH DAKOTA – MOUNTRAIL	SLAWSON EXPLORATION	PROWLER  1-16H	5.00%
NORTH DAKOTA – MOUNTRAIL	SLAWSON EXPLORATION	PAYARA  1-21H	3.00%
NORTH DAKOTA – MOUNTRAIL	SLAWSON EXPLORATION	VOYAGER 1-18H	5.00%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	REISS  34-20H	1.00%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	KENT CARLSON  24-36H	6.25%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	VOIGT 11-15H	1.00%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	CLIVE PELTON 34-23H	3.00%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	ECKELBERG 41-26H	3.00%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	STROMMEN 14-8H	3.00%
NORTH DAKOTA – DUNN	MARATHON OIL COMPANY	WILLARD KOVALOFF 21-1H	1.00%
NORTH DAKOTA – DUNN	BURLINGTON RESOURCES	BONNEY 34-3H	3.00%
NORTH DAKOTA – MOUNTRAIL	HESS CORPORATION	EN-PERSON-1102H-1	12.50%
NORTH DAKOTA – MOUNTRAIL	HESS CORPORATION	RS-AGRIBANK-1102H-1	7.50%
NORTH DAKOTA – MOUNTRAIL	HESS CORPORATION	EN-NESET-0706H-1	3.00%
NORTH DAKOTA – MOUNTRAIL	HESS CORPORATION	BL-BLANCHARD 155-96	2.50%

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State/County	Operator	Well Name	Northern Oil and Gas Working Interest
NORTH DAKOTA – MOUNTRAIL	EOG RESOURCES	WAYZETTA 1-13H	6.25%
NORTH DAKOTA – DIVIDE	CONTINENTAL RESOURCES	SHONNA 1-15H	15.00%
NORTH DAKOTA – DIVIDE	CONTINENTAL RESOURCES	ARVID 1-35	5.00%

Brigham Exploration

On April 23, 2007 we entered into a joint venture agreement with Brigham Exploration. Under the terms of the agreement, we contributed 3,000 net acres of our approximate 65,000 net acres located in North Dakota and approximately 21,350 net acres of our Sheridan County, Montana acreage.

Drilling under the Brigham joint venture commenced in the early fourth quarter of 2007.  On the Mountrail County, North Dakota acreage, we successfully completed the Bergstrom Family Trust 26, a Bakken well that produced at an early rate of approximately 200 gross barrels of oil per day.  We participated for a 6.25% working interest that converts to 24% working interest at payout.  We also completed the Hallingstad 27, a Bakken well that produced at an early rate of approximately 500 gross barrels of oil per day.  We participated for an 8.4% working interest that converts to 20.5% working interest at payout.

On the Sheridan County, Montana acreage, we successfully completed the Richardson #25, a Red River test well that went on production at a consistent rate of approximately 300 barrels of oil per day.  The Company participated for a 10% working interest that converts to 37% working interest at payout, which occurred in the third fiscal quarter of 2008. We did not recognize any revenue from these wells in 2007.  We also completed the Richardson #30 in late June 2008, an offset to the productive Richardson #25 Red River Well.  The Richardson #30 began production at a rate of approximately 175 barrels of oil per day.  The Company participated for a 12.5% working interest that converts to 21.25% working interest at payout as well as retaining a 1% over-riding royalty interest.

Commencing in 2008, Brigham is subject to a 120 day continuous drilling provision requiring Brigham to drill every 120 days to retain future drilling opportunity.  Under the joint venture acreage in Mountrail County North Dakota, Brigham expects to operate a third Bakken well that will spud in late December 2008.  On the Sheridan county acreage, Brigham expects to drill a third conventional well expected to spud in early 2009.

Murex Petroleum

In the second quarter of 2008, our acreage was included in the Rick Clair 25-36H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 1400 gross barrels of oil per day.

Whiting Oil & Gas

In the second quarter of 2008, we participated with Whiting Oil & Gas in the Braaflat 11-11H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 1600 gross barrels of oil per day.

In the third quarter of 2008, we participated with Whiting Oil & Gas in the Federal 11-9H, a horizontal Bakken well in Mountrail County North Dakota.

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Sinclair Oil

In the second quarter of 2008, we participated with Sinclair Oil in the Nelson 1-26H a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 750 gross barrels of oil per day.

Slawson Exploration

In the second quarter of 2008, we participated with Slawson Exploration in the Pathfinder 1-9H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 1,500 gross barrels of oil per day.

In the third quarter of 2008, we participated with Slawson Exploration in the Prowler  1-16H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 950 gross barrels of oil per day.  We participated in the Payara 1-21H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 622 gross barrels of oil per day.  We participated in the Voyager 1-18H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 929 gross barrels of oil per day.  

On October 30, 2008, we executed a drilling agreement with Slawson Exploration covering certain of our acreage in Mountrail County, North Dakota for a one-well drilling arrangement.  Under that agreement, we agreed to sell 120 net acres in Section 5, Township 151 North, Range 92 West for $3,000 per net acre.  Once the transaction is complete, we will control a 42% working interest in the section.  The Jericho 1-5H well, expected to be drilled pursuant to the agreement, will be a horizontal Bakken well drilled in the 640 acre section.  The agreement is conditioned on Slawson commencing drilling by March 1, 2009.

Marathon Oil Corporation

In the fourth quarter of 2007, we participated with Marathon Oil for a 3% working interest in the Reiss 34 20H, a horizontal Bakken well in Dunn County North Dakota that produced at an early rate of 700 gross barrels of oil per day.

In the second quarter of 2008, we participated with Marathon Oil in the Kent Carlson 24-36H , a horizontal Bakken well located in Dunn County North Dakota that produced at an early rate of 450 gross barrels of oil per day.   We participated in the Clive Pelton 34-23H, a horizontal Bakken well located in Dunn County North Dakota that produced at an early rate of 650 gross barrels of oil per day.  We participated in the Eckelberg 41-26H, a horizontal Bakken well located in Dunn County North Dakota that produced at an early rate of 650 gross barrels of oil per day.

In the third quarter of 2008, we participated with Marathon Oil in the Strommen 14-8H , a horizontal Bakken well located in Dunn County North Dakota that produced at an early rate of 632 gross barrels of oil per day.  We participated in the Voigt 11-15H, a horizontal Bakken well located in Dunn County North Dakota that produced at an early rate of 550 gross barrels of oil per day. We participated with Marathon Oil in the Willard Kovaloff 21-1H, a horizontal Bakken well located in Dunn County North Dakota that produced at an early rate of 695 gross barrels of oil per day.

The Marathon Oil program is an excellent example of how we attempt to participate in wells with a small working interest in order to accumulate data as the completion techniques continue to evolve.

Burlington Resources

In the second quarter of 2008, we participated with Burlington Resources in the Bonney 34-3H, a horizontal Bakken well in Dunn County North Dakota that produced at an early rate of 400 gross barrels of oil per day.

Hess Corporation

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In the third quarter of 2008, we participated with Hess in the EN-Person 1102H-1, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 950 gross barrels of oil per day.  We participated with Hess in the RS-Agribank 1102-H1, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 950 gross barrels of oil per day.  We participated with Hess in the EN-Neset 0706H-1, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 550 gross barrels of oil per day.We participated with Hess in the BL-Blanchard 155-96, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 650 gross barrels of oil per day.

EOG Resources

In the third quarter of 2008, we participated with EOG Resources in the Wayzetta 1-13H, a horizontal Bakken well in Mountrail County North Dakota that produced at an early rate of 1,355 gross barrels of oil per day.

Continental Resources

In the third quarter of 2008, we participated with Continental Resources in the Shonna 1-15H, a horizontal Bakken well in Divide County North Dakota that produced at an early rate of 403 gross barrels of oil per day. We participated with Continental Resources in the Arvid 1-35H, a horizontal Bakken well in Divide County North Dakota.

The following table summarizes wells that are currently drilling or completing as of November 6, 2008, all of which wells are located in North Dakota:

State/County	Operator	Well Name	Northern Oil and Gas Working Interest
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	SIDONIA 1-06H	11.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	AUSTIN 19-30H	5.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	PARSHALL  11-28H	2.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	PARSHALL  12-27H	2.00%
NORTH DAKOTA - DIVIDE	CONTINENTAL RESOURCES	ELVEIDA  1-33H	10.00%
NORTH DAKOTA - DUNN	CONTINENTAL RESOURCES	SKACHENKO 1-31H	6.25%
NORTH DAKOTA - BILLINGS	CONTINENTAL RESOURCES	ARMSTRONG 1-24H	2.0%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	BANDIT  1-29H	27.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	PEACEMAKER 1-8H	15.00%
NORTH DAKOTA - MOUNTRAIL	HESS CORPORATION	EN-HYNEK-0112H-1	2.00%
NORTH DAKOTA - DUNN	MARATHON OIL COMPANY	MARK SANDSTROM 14-32H	5.00%
NORTH DAKOTA - MOUNTRAIL	MARATHON OIL COMPANY	SHOBE 24-20H	3.00%
NORTH DAKOTA - DUNN	MARATHON OIL COMPANY	JODI CARLSON 24-12H	2.00%
NORTH DAKOTA - MOUNTRAIL	MARATHON OIL COMPANY	NORTON 24-12H	2.00%
NORTH DAKOTA - RICHLAND	CRUSADER ENERGY	OILERS 1H-10	7.50%

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The following table summarizes wells that are currently permitted on our acreage as of November 6, 2008:

State/County	Operator	Well Name	Northern Oil and Gas Working Interest
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	BURESS 1-17H	5.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	MODEL   1-05H	3.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	MODEL   2-08H	3.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	MODEL  4-19H	3.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	RUUD  1-18H	3.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	AUSTIN 23-32H	3.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	SHELL 1-08H	3.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	AUSTIN 3-4H	1.00%
NORTH DAKOTA - MOUNTRAIL	EOG RESOURCES	MODEL 1-09H	3.00%
NORTH DAKOTA - MOUNTRAIL	WHITING OIL & GAS	LACEY 11-12H	2.00%
NORTH DAKOTA - MOUNTRAIL	HESS CORPORATION	RS-F. ARMOUR ###-##-####H	12.50%
NORTH DAKOTA - MOUNTRAIL	HESS CORPORATION	RS-FELDMAN 156-92-1423-1H	12.50%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	JERICHO 1-5H	42.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	HEDGEHOG   1-6H	5.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	TOMCAT  1-2H	5.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	SENTRY  10-1H	5.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	NIGHTCRAWLER  1-17H	5.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	POLARIS 1-21H	5.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	MAMBA #1-20H	5.00%
NORTH DAKOTA - MOUNTRAIL	SLAWSON EXPLORATION	PANTHER 1-29H	7.50%
NORTH DAKOTA - MOUNTRAIL	BRIGHAM EXPLORATION	AFSETH 34-1H	6.25%
NORTH DAKOTA - MOUNTRAIL	BRIGHAM EXPLORATION	HALLINGSTAD 35-1H	15.00%
NORTH DAKOTA - MOUNTRAIL	WINDSOR ENERGY	WOLF 1-4H	16.00%
NORTH DAKOTA - DUNN	TRACKER RESOURCES	KNUTSON  #4-1H	8.00%
NORTH DAKOTA - DUNN	TRACKER RESOURCES	LEE 28-1H	6.25%
NORTH DAKOTA - DUNN	PENN VIRGINIA	WATKINS 24-1H	10.00%
NORTH DAKOTA - DUNN	ANSCHUTZ	TWIST 31-4H	10.00%
NORTH DAKOTA - MCKENZIE	PETRO-HUNT	WOLLAN 27B-2-2H	3.00%

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State/County	Operator	Well Name	Northern Oil and Gas Working Interest
NORTH DAKOTA - MOUNTRAIL	XTO	SMOUSE 41-28	30.00%
NORTH DAKOTA - DIVIDE	XTO	SIG 21X-6	2.00%
NORTH DAKOTA - MCKENZIE	NEWFIELD EXLPORTATION	WISNESS 1-4H	5.00%
NORTH DAKOTA - MCKENZIE	ENCORE OPERATING	ROLFSON 14-33H	5.00%
NORTH DAKOTA - BURKE	SAMSON OIL	GUSTAFSON 29-161-92H	25.00%
NORTH DAKOTA - MOUNTRAIL	MUREX PETROLEUM	CHAD ALLEN 25-36H	6.25%
NORTH DAKOTA - DUNN	MARATHON OIL COMPANY	KENT CARLSON  14-36H	6.25%
NORTH DAKOTA - MOUNTRAIL	MARATHON OIL COMPANY	BANGEN 41-27H	7.50%
NORTH DAKOTA - DIVIDE	CONTINENTAL RESOURCES	ELLS 1-6H	12.50%
NORTH DAKOTA - DIVIDE	CONTINENTAL RESOURCES	VIOLA 1-7H	7.50%
NORTH DAKOTA - DIVIDE	CONTINENTAL RESOURCES	ROSSOW 1-10H	10.00%
NORTH DAKOTA - MOUNTRAIL	ST. MARY	S.M. CLARK 4-6H	2.00%
MONTANA - SHERIDAN	KODIAK OIL & GAS	MEAGHER 16-30	8.50%
MONTANA - SHERIDAN	KODIAK OIL & GAS	BONEYARD 13-20	8.50%
MONTANA - SHERIDAN	BRIGHAM EXPLORATION	FRIEDRICK TRUST 31-1	25%

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements.  We have historically met our capital requirements through the issuance of common stock and by short term 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.

The following table summarizes total current assets, total current liabilities and working capital at March 31, 2008, June 30, 2008 and September 30, 2008. In addition to our September 30, 2008 working capital amount of $4,164,086, we have the ability to borrow, on a no-net cost basis, up to 75% of the market value of our auction rate securities.

	March 31, 2008 (Unaudited)		June 30, 2008 (Unaudited)		September 30, 2008 (Unaudited)
Current Assets	$	5,962,838	$	17,605,086	$	8,541,447
Current Liabilities	$	2,194,099	$	3,325,757	$	4,377,361
Working Capital	$	3,768,739	$	14,279,329	$	4,164,086

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We continued to participate in the drilling of our acreage at an accelerated pace in the quarter ended September 30, 2008, and expect that trend to continue into 2009.  If drilling activities accelerate at a rate that exceeds our receipt of revenues from producing wells, we will require additional capital to finance future drilling activities through equity and/or debt financings.  We are presently pursuing potential debt financing arrangements to address this potential need, but cannot be certain that such arrangements will be available on terms acceptable to the Company.  The recent financial and banking crisis in the United States has limited access to capital for many companies, but we cannot be certain the extent to which those conditions will impact our future financing activities.  In the event that we are not able to obtain debt or equity financing on terms acceptable to us, we may utilize “farm-out” and other arrangements that will allow us to generate additional capital through sales or leases of select portions of our acreage.  In any event, however, we would at a minimum retain an overriding royalty interest that would ensure the Company realizes revenues from any properties sold or leased using such arrangements.  We do expect to have access to the necessary capital to continue to drill our locations in the manner we have to this point.

Satisfaction of our cash obligations for the next 12 months.

We currently are funded to meet our minimum drilling commitments and expected general and administrative expenses for the next 12 months.  However, we anticipate accelerating the drilling of higher working interest units which will require additional capital.

Since inception, we have financed cash flow requirements through short term debt financing, our recent land bank arrangement and the issuance of common stock for cash and services as well as proceeds from the exercise of warrants to purchase common equity.  In the future, if we deem it necessary to raise capital for continued acreage acquisition or an accelerated drilling program, we may access the debt or equity markets.  There can be no assurance this capital will be available and if it is not, we may be forced to substantially curtail or cease acreage acquisition and/or drilling expenditures.  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.

We may incur operating losses over the next twelve months.  Our lack of operating history makes predictions of future operating results difficult.  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.

Significant financing arrangements.

On April 14, 2008, we entered into an Agreement setting forth a land bank arrangement with Deephaven MCF Acquisition, LLC (“Deephaven”), an affiliate of Deephaven Capital Management LLC, pursuant to which the Company could acquire leases having an aggregate value of up to $8.1 million.  Under the arrangement, Deephaven acquired certain qualifying leases in the Bakken Shale formation in Mountrail County, North Dakota, which leases could be acquired by the Company at any time during the initial year that Deephaven owns such leases.

We utilized approximately $5.1 million of the potential $8.1 million facility available under the Agreement upon initiation of the facility and will not utilize the remaining $3.0 million of the facility.  On September 26, 2008, the Company agreed to a Second Amendment to the Agreement whereby the Company agreed to purchase from Deephaven all leases remaining in the land bank arrangement no later than November 25, 2008, for $912.50 per net acre ($4,364,456.90 in the aggregate) plus 67,500 fully-paid and non-assessable restricted shares of the Company’s common stock.  Such cash payment and issuance of shares constitute the sole consideration to be received by Deephaven for any and all leases remaining in the land bank arrangement and terminates any and all obligations of the Company to issue to Deephaven any other shares of capital stock, pay to Deephaven any further cash or provide any other consideration that Deephaven otherwise would be entitled to receive under the Agreement.  No additional

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cash, capital stock or other consideration of any form will be due from the Company to Deephaven following Deephaven’s receipt of the agreed-upon cash payment and shares of common stock. The Second Amendment also terminated the Registration Rights Agreement By and Among Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008 and a prior Amendment extending the initial option period under the Agreement.  The Second Amendment provides, however, that the Company is required to file a registration statement on Form S-3 registering the shares of common stock issued to Deephaven no later than December 25, 2008.

As of September 30, 2008, we received gross proceeds of approximately $25,982,072.75 from the exercise of outstanding warrants previously issued in connection with the Company’s September 2007 institutional private placement.  The warrants resulted in the issuance of an aggregate of 4,818,187 shares of the Company’s common stock, par value $0.001.

Auction Rate Securities

In or around September 2007, we began purchasing municipal bonds and floating rate preferred stock 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 for $3,550,524 at anytime during a two-year period beginning June 30, 2010.  The Offer is non-transferable and expires on November 14, 2008.  On October 28, the Company elected to participate in the Offer.  Based on that decision, along with the underlying maturities of the securities, a portion of which is greater than 30 years, we have classified auction rate securities as long-term assets on our balance sheet. In addition to the Offer, UBS is providing no net cost loans of up to 75% of the loan-to-market value of eligible auction rate securities until June 30, 2010. UBS has agreed to allow the Company to borrow, on a no net cost basis up to 75% of the loan-to-market value, as determined by UBS.

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 September 30, 2008, the Company’s investment advisors provided a valuation based on certain 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 September 30, 2008, 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 valuation, the Company valued the ARS investments at $3,320,975, which represents a decline in value of $229,549 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

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terms, the underlying securities have matured or the Company accepts the investment manager’s offer to redeem the securities.

Based on the cash balance of $6,772,167, 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.

Expected purchase or sale of any significant equipment.

We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time or anticipated to be needed in the next twelve months.

Significant changes in the number of employees.

As of September 30, 2008, we had four executive-level full-time employees and one administrative employee.  As drilling production activities commence, we may hire additional technical, operational and administrative personnel as appropriate.  We do not expect a significant change in the number of full time executive employees over the next 12 months.  We are using, and will continue to use, extensively the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment.  We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.

Summary of product research and development that we will perform for the term of our plan.

We do not anticipate performing any significant product research and development under our plan of operation until such time as we can raise adequate working capital to sustain our operations.

Expected purchase or sale of any significant equipment.

We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time or anticipated to be needed in the next twelve months.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Item 4T. 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 the 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 September 30, 2008, 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

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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 September 30, 2008.

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 September 30, 2008, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.  Legal Proceedings

From time to time we may be engaged in certain legal proceedings and claims arising in the ordinary course of our business.  The ultimate liabilities, if any, which may result from these or other pending or threatened legal actions against us cannot be determined at this time.  However, in the opinion of management, the facts known at the present time do not indicate that such litigation will have a material effect on our consolidated financial position or results of operations.

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

On June 30, 2008, we provided notice to all holders of the remaining outstanding warrants to purchase shares of our common stock exercisable for $6.00 per share indicating that the Company determined to call such warrants for cancellation pursuant to the terms of such warrants.  Between July 1, 2008 and July 21, 2008, the Company received additional gross proceeds of $10,400,004 from the exercise of such warrants, which had been issued in connection with the Company’s September 2007 institutional private placement.  The warrants resulted in the issuance of an aggregate of 1,733,334 shares of the Company’s common stock. The Company believes the issuance of the shares upon exercise of the warrants was exempt from the registration and prospectus delivery requirements of the Securities Act by virtue of Section 4(2) and Rule 506 of Regulation D promulgated by the United States Securities and Exchange Commission (the “SEC”).  As of September 30, 2008, all outstanding warrants to purchase shares of the Company’s common stock had been exercised by the holders thereof, and no outstanding warrants remained available for exercise.

On September 26, 2008, we issued 2,558 shares of restricted common stock to MOP as partial consideration for our acquisition of leases covering acreage in Mountrail County, North Dakota pursuant to an agreement dated January 17, 2008.  The shares were issued pursuant to the exemption from registration provided in Section 4(2) of the Securities Act.  The principals of MOP are Mr. Steven Reger and Mr. Tom Ryan, both are uncles of our Chief Executive Officer, Michael Reger.  The issuance of the foregoing shares of common stock was approved by our Audit Committee, which consists of independent directors having no relation to the principals of MOP.  We did not receive any proceed from the issuance of the foregoing securities.

On September 26, 2008, we issued 7,675 shares of restricted common stock to Missouri River Royalty Corporationas consideration for our acquisition of well interests in certain wells proposed for drilling in McKenzie County and Mountrail County of North Dakota pursuant to an agreement dated June 19, 2008.  The shares were issued pursuant to the exemption from registration provided in Section 4(2) of the Securities Act.  We did not receive any proceed from the issuance of the foregoing securities.

On October 6, 2008, we issued 67,500 shares of restricted common stock to Deephaven as partial consideration for the purchase of leases from Deephaven pursuant to a land bank arrangement entered into on April 14, 2008 and amended on September 26, 2008.  The shares were issued pursuant to the exemption from registration

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provided in Section 4(2) of the Securities Act. We did not receive any proceed from the issuance of the foregoing securities.

Item 6.  Exhibits.

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

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SIGNATURES

In accordance with the requirements of the Exchange Act, the Registrant has caused this Quarterly Report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHERN OIL AND GAS, INC.

Date:	November 13, 2008	By:	/s/Michael Reger
			Michael Reger, Chief Executive Officer and Director
Date:	November 13, 2008	By:	/s/Ryan Gilbertson
			Ryan Gilbertson, Chief Financial Officer and Director

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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

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