Northern Oil and Gas (NOG) 10-K 2009 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHTINGTON, DC  20549

FORM 10-K

 (Mark One)

T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

or

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to __________________

Commission File No.  - 000-33999

__________________

NORTHERN OIL AND GAS, INC.

(Exact Name of Registrant as Specified in Its Charter)

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

315 Manitoba Avenue – Suite 200, Wayzata, Minnesota 55391

(Address of Principal Executive Offices)  (Zip Code)

952-476-9800

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange On Which Registered
Common Stock, $0.001 par value	American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes £No T

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.Yes £No T

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes T                      No £

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. T

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  T

Non-Accelerated Filer  £                                                                           Smaller Reporting Company £

             (Do not check if a smaller reporting company)

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sale price as reported by the American Stock Exchange) was approximately $261,247,772.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

As of March 13, 2008, the registrant had 34,120,103 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2009 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

NORTHERN OIL AND GAS, INC.

TABLE OF CONTENTS

		Page
	Part I
Item 1.	Business	2
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	18
Item 3.	Legal Proceedings	24
Item 4.	Submission of Matters to a Vote of Security Holders	24
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	29
Item 7.	Management’s Discussion and Analysis or Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 8.	Financial Statements and Supplementary Data	36
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	36
Item 9A.	Controls and Procedures	36
Item 9B.	Other Information	39
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance
Item 11.	Executive Compensation	39
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	39
Item 13.	Certain Relationships and Related Transactions, and Director Independence	39
Item 14.	Principal Accountant Fees and Services	39
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	39
Signatures		40
Index to Financial Statements		F-1

NORTHERN OIL AND GAS, INC.

2008 ANNUAL REPORT ON FORM 10-K

PART I

Item 1.  Business

Overview

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.,” a Nevada corporation incorporated on October 5, 2006.  The Company took its present form on March 20, 2007, when Northern Oil and Gas, Inc.  (“Northern”), a Nevada corporation engaged in the Company’s current business, merged with and into our subsidiary, with Northern remaining as the surviving corporation (as more fully discussed below).  Northern then merged into us, and we were the surviving corporation.  We then changed our name to Northern Oil and Gas, Inc.  References made herein to “Kentex” refer to the Company’s status and operations prior to March 20, 2007.

The Company was originally organized under the laws of the State of Nevada on February 10, 1983, principally for the purpose of engaging in any lawful activity.  On or about January 18, 2006, Kentex received notification that the NASD had approved the Form 211 application for addition to the OTC Bulletin Board under the ticker symbol “KNTX”, effective January 19, 2006.

On March 20, 2007, Kentex acquired Northern, pursuant to a merger by and among us, Kentex Acquisition Corp., a Nevada corporation and our wholly owned subsidiary (the “Merger Sub”), and Northern.  Kentex Acquisition Corp. merged with and into Northern, with Northern as the surviving corporation (the “Merger”).  We issued 21,173,013 shares of our common stock in exchange for 100% of the outstanding shares of Northern.  Upon closing of the Merger, the former stockholders of Northern thereafter controlled approximately 94% of our outstanding shares of common stock.  Immediately following the Merger, the Company completed a so-called short-form Merger with Northern, in which Northern merged into the Company, and the Company was the surviving entity.  As a part of this short-form Merger, the Company changed its name to “Northern Oil and Gas, Inc”.  As a result of the Merger, Northern was deemed to be the acquiring company for financial reporting purposes and the transaction has been accounted for as a reverse merger.  The financial statements presented in the Company’s December 31, 2006, Form 10-KSB report were the historical financial statements of Kentex Petroleum, Inc, the predecessor company.  Additional material terms of the Merger are detailed in the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission (the “SEC”) on December 19, 2006.

On March 17, 2008 the Company received an approval letter to begin trading on the American Stock Exchange (the “AMEX”).  Our common stock commenced trading on the AMEX on March 26, 2008 under the symbol “NOG.”

Following the Merger, our main business focus has been directed to oil and gas exploration and development.  Unless specifically stated otherwise, our primary operations are now those formerly operated by Northern as well as other business activities since March, 2007.

Business

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 believe that we are able to create value via strategic acreage acquisitions and convert that value or portion thereof into production by utilizing experienced industry partners specializing in the specific areas of interest.  We have targeted specific prospects and began drilling for oil in the Williston Basin region in the fourth fiscal quarter of 2007.  As of March

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16, 2009, we had completed 46 successful discoveries, consisting of 43 targeting the Bakken/Three Forks formation and three targeting a Red River Structure.

As an exploration company, our business strategy is to identify and exploit resources that can be quickly developed and put in production at low cost and are both repeatable and scalable.  We also intend to take advantage of our expertise in aggressive land acquisition to develop exploratory projects with extremely 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.  We believe we are in a position to most efficiently exploit and identify high production oil and gas properties.  We intend to continue to carefully pursue the acquisition of properties that fit our profile.

Because we did not commence drilling activities until the fourth fiscal quarter of 2007, we did not perform any reservoir engineering calculations in the 2007 fiscal year.  Although we began oil production in the fourth fiscal quarter of 2007, we did not receive payment or recognize revenue from sales in the 2007 fiscal year.  As such, we first began to recognize revenue from our oil and gas operations in 2008.  As such, many metrics of comparison from 2007 to 2008 are not applicable.

Reserves

We completed our initial reservoir engineering calculations in the first fiscal quarter of 2008 and completed our most recent reservoir engineering calculation in February 2009.  Our year end calculations take into consideration the development of approximately 1.5% of our total drillable acreage inventory. The table below summarizes our estimated proved reserves by core area as of December 31, 2008, and our December 2008 average daily production.  The value of our reserves is calculated by determining the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expenses, production taxes and future development costs.  In accordance with SEC regulations, our reserve report values our production based upon the $38.60 price of oil on December 31, 2008.  Oil prices have increased and we have added significant production since December 31, 2008.  The table below uses price and costs without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or Federal income taxes, and discounted using an annual discount rate of 10%.  The values below are generally referred to in our industry as the “Pre-tax PV10%” values of our reserves and may be considered a non-GAAP financial measure as defined by the SEC.

Proved Reserves(1)

Core Area	Oil(2)		Natural Gas		Total		Pre-Tax PV10% Value(3)		December 2008 Average Daily Production
	(barrels)		(cubic feet)		(barrels of oil equivalent)				(barrels per day)
North Dakota		664,923		205,492		699,172	$	10,785,589		420
Montana		62,742		10,959		64,569		1,000,467		40
Total		727,665		216,451		763,741	$	11,768,056		460

_____________________

(1)	Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices as of December 31, 2008, including the effect of dirrerentials, pursuant to current SEC and FASB guidelines.
(2)	Oil includes natural gas liquids.

(3) Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.  Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes.  We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties.  We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid.  Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions.  However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows.  Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The daily production data provided in the foregoing table does not reflect substantial improved production from well completions and increased flow rates on existing wells since December 31, 2008.  We believe that production from existing wells in December 2008 was intentionally choked back by several operators in response to commodity price decreases and winter season selling differentials.  Our average daily production as of March 13, 2009, was approximately 850 net barrels of oil per day, reflecting additional well completions and increased flow rates from pre-existing wells despite restricted flow rates from certain of our wells.

Our reserve report does not account for any value in potential reserves relating to any acreage not subject to drilling activities, such as our New York acreage and any undeveloped acreage in North Dakota or Montana.  Further, our reserve report did not indicate any significant quantities of natural gas present in any wells drilling or completed as of December 31, 2008.  We have elected not to complete an assessment of proven undeveloped locations (“PUD’s”) at this time due to the rapid increase in drilling adjacent to and in our acreage units.  We intend to complete a reserve report including PUD’s by the end of the second quarter of 2009, at which time we believe we will be able to obtain a more accurate PUD’s estimation.  Estimates of ultimate recovery from our Bakken wells have ranged from 350,000 to over 1,000,000 barrels of oil.  Our current acreage position will allow us to drill up to 110 net wells based on 640-acre spacing units.

Recent Developments

During the 2008 fiscal year, we continued to focus our operations on acquiring leaseholds and drilling exploratory and developmental wells primarily in the Rocky Mountain Region of the United States.  We acquired approximately 50,000 additional net acres during 2008, primarily in Mountrail and Dunn Counties of North Dakota but also in Burke, Divide and other counties of North Dakota.  As of December 31, 2008, 36 gross wells had been completed in which we had an interest.  Our principal assets continue to be located in the Williston Basin region of the northern United States and Yates County, New York, and included the following primary positions as of December 31, 2008:

▪   Approximately 30,000 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 25,000 net acres located in Dunn County, North Dakota, in which we are targeting the Bakken Shale and Three Forks/Sanish formations;

▪   Approximately 22,000 net acres located in Sheridan County, Montana, representing a stacked pay prospect over which we have significant proprietary 3-D seismic data;

▪   Approximately 10,000 net acres located in Burke and Divide Counties of North Dakota, targeting the Bakken Shale and Three Forks/Sanish formations near significant drilling activities by Marathon Oil Corporation;

▪   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; and

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Approximately 5,000 net acres located in McKenzie, Williams and Mercer Counties North Dakota, in which we are targeting the Bakken Shale.

In addition to purchasing interests in oil, gas and mineral leases with the intention of increasing our acreage positions in desired prospects, during fiscal year 2008 we also utilized “farm-in” arrangements whereby we purchase oil, gas and mineral leases under specific wells that are drilling or expected to drill in short order, while allowing the assignee of such rights to retain an overriding royalty interest or a working interest that converts at pay-out in the related production.  Recent declines in crude oil process have made farm-in arrangements more cost-effective to our company as an acquirer.

A complete discussion of our significant acquisitions during the past two years is included under the heading “Properties – Acreage Acquisitions” in Item 2 of this report

Production Methods

We primarily engage in oil and gas exploration and production through participating on a “heads-up” basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage.  We typically depend on drilling partners to propose, permit and initiate the drilling of wells.  Prior to commencing drilling, our partners are required to provide all owners of oil, gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit.  In the 2008 fiscal year, we participated in the drilling of all wells that included any of our acreage.  We will assess each drilling opportunity on a case-by-case basis going forward and participate in wells that we expect to be economically feasible based upon our estimates of ultimate recoverable oil and gas from each project, as well as other factors.

The Company may utilize experienced drilling and operating partners through formal “farm-out” agreements in which we contribute our leasehold interests in exchange for working interests in wells drilled on the Company’s acreage, while a drilling partner funds the drilling and operation of the actual well.  Pursuant to those arrangements, our partners will provide the expertise, equipment and a significant portion of the capital required to drill wells on our acreage.  However we generally intend to participate in the drilling of wells including our acreage on a “heads-up” basis commensurate with our working interest.

We also have utilized “farm-in” arrangements whereby we would purchase oil, gas and mineral leases under specific wells that were drilling or expected to drill in short order, while allowing the assignee of such rights to retain an overriding royalty interest in the related production.  In some cases these farm-in arrangements have become more cost-effective to acquire as crude oil prices have declined and the owners of oil, gas and mineral rights desire to participate in drilling wells less aggressively.  Farm-in arrangements allow us to ensure an accelerated return on capital by deploying our acquisition budget to acreage that is expected to provide production in the very near future.

We do not manage our commodities marketing activities internally, but our operating partners generally market and sell oil and natural gas produced from wells in which we have an interest.  Our operating partners coordinate the transportation of our oil production from our wells to appropriate pipelines pursuant to arrangements that such partners negotiate and maintain with various parties purchasing the production.  We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts.  The price at which production is sold generally is tied to the spot market for crude oil.  Williston Basin Light Sweet Crude from the Bakken source rock is generally 41-42 API oil and is readily accepted into the pipeline infrastructure at a price proximal to West Texas Immediate spot price.

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Proved Reserves

Our estimated proved reserves as of December 31, 2008, are summarized in the table below based upon a reserve report prepared in February 2009 by Ryder Scott Company, LP.  Our February 2009 reserve report did not include an analysis of our Proved Undeveloped Properties.

	Oil (barrels)		Natural Gas (cubic feet)		Total (barrels of oil equivalent)		% of Total Proved			Future Capital Expenditures
North Dakota
PDP(1)		418,673		104,866		436,151		57	%	$  3,272,580
PDNP(2)		246,250		100,626		263,021		34	%	3,326,230
Total Proved		664,923		205, 492		699,172		91	%		$  6,598,810
Montana:
PDP		62,742		10,959		64,569		9	%		814,541
PDNP		–		–		–		–			–
Total Proved		727,665		216,451		763,741		100	%		$  7,413,352

____________________

(1)	”PDP” consists of our proved developed producing reserves.
(2)	”PDNP” consists of our proved developed nonproducing reserves.

Competition

The oil and natural gas industry is intensely competitive, and we compete with numerous other oil and gas exploration and production companies.  Many of these companies have substantially greater resources than we have.  Not only do they explore for and produce oil and natural gas, but many also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis.  The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties.  They may also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to be better able to absorb the burden of existing, and any changes to federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position.  Our ability to discover reserves and acquire additional properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.  In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects, because we have fewer financial and human resources than other companies in our industry.  Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Marketing and Customers

The market for oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation.  The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

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Our oil production is expected to be sold at prices tied to the spot oil markets.  Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production.

Principal Agreements Affecting Our Ordinary Business

The Company does not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms and provisions of lease agreements that provide the Company the right to drill and maintain wells in specific geographic areas.  All of our lease arrangements that comprise our acreage positions are established using industry-standard terms that have been established and engrained in the oil and gas industry for many years, and many of our leases were acquired from other parties that obtained the original leasehold interest prior to our acquisition.

In general, our lease agreements stipulate five year terms with minimum net revenue interests. Bonuses and royalty payments are made on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the well is considered “held by production,” meaning the lease continues as long as oil is being produced.  Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production.  The vast majority of our North Dakota leases have over four years remaining on the terms.  We have very few leases with less than three years remaining in North Dakota.  In Montana and New York we generally have 30 months to three years remaining on our leases, with very few exceptions.  We believe that given the pace of drilling in the recent period there should be very few, if any, instances in which we are unable to accomplish the goals of our drilling program due to time constraints on the leases

Some of our acreage is subject to joint venture and drilling agreements, and we expect that we will continue to evaluate potential partners and arrangements to develop our positions.  The provisions of each relationship are and will be subject to separately negotiated arrangements.  We do not rely on any material patents, trademarks, licenses, franchises, labor contracts or other similar arrangements during our ordinary course of business.

Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies.  For example, some states in which we may operate require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas.  Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells.  Failure to comply with any such rules and regulations can result in substantial penalties.  The regulatory burden on the oil and gas industry will most likely increase our cost of doing business and may affect our profitability.  Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.  Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health.  The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.  These laws and regulations may:

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▪   require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

▪   limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

▪   impose substantial liabilities for pollution resulting from its operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities.  Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both.  In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on the Company, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance.  Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products.  In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species.  Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat.  ESA provides for criminal penalties for willful violations of the Act.  Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.  Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject the Company to significant expenses to modify our operations or could force the Company to discontinue certain operations altogether.

Employees

The Company currently has five full time employees.  Our Chief Executive Officer—Michael Reger—and our Chief Financial Officer—Ryan Gilbertson—are responsible for all material policy-making decisions, and are assisted in the implementation of the Company’s business by our Vice President of Operations and our General Counsel.  All employees have entered into written employment agreements with the Company.  As drilling production activities continue to increase, we may hire additional technical, operational or administrative personnel as appropriate.  We do not expect a significant change in the number of full time employees over the next 12 months, assuming our currently-projected drilling plan.  We are using and will continue to use 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.

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Office Locations

Our executive offices are located at 315 Manitoba Avenue, Suite 200, Wayzata, Minnesota 55391.  Our office space consists of 3,044 square feet leased pursuant to a five-year office lease agreement that commenced in February, 2008.  We believe our current office space is sufficient to meet our needs for the foreseeable future.

Financial Information about Segments and Geographic Areas

Due to our limited operating history and our limited oil and gas production, we have not estimated, accrued or classified revenue based on segments or geographic areas.  Production commenced at our first well in December 2007.

Available Information – Reports to Security Holders

Our Website address is www.northernoil.com.  We make available on this Website under “Investor Relations,” free of charge, our annual reports on Form 10-K (formerly Form 10-KSB), quarterly reports on Form 10-Q (formerly Form 10-QSB), current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities Exchange Commission (“SEC”).  These filings are also available to the public at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  Electronic filings with the SEC are also available on the SEC internet website at http://www.sec.gov.

We have also posted to our website our Audit Committee Charter, Compensation Committee Charter, Nominating Committee Charter and our Code of Business Conduct and Ethics, in addition to all pertinent Company contact information.

Item 1A.  Risk Factors

Cautionary Statement Concerning Forward-Looking Statements

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our Company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our Company.  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

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subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.  Accordingly, results actually achieved may differ materially from expected results in these statements.  Forward-looking statements speak only as of the date they are made.  You should consider carefully the statements in this “Item 1A. Risk Factors” and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.  Our Company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

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

Risks Related to our Business

Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operation and cash flow.

The global financial crisis may significantly impact our business and financial condition for the foreseeable future.

The continued credit crisis and related turmoil in the global financial system may adversely impact our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve.  Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions.  The economic situation could have an impact on operators upon whom we are dependent for drilling our wells, our lenders or customers, causing them to fail to meet their obligations to us.  Additionally, market conditions could have an impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection.  We believe, however, that we are funded to meet our 2009 drilling program and additional capital would be required in the event we accelerate our drilling or commodity prices decline substantially resulting in revenues significantly less than we currently expect.

We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.

We expect that our current capital and our other existing resources will be sufficient only to provide a limited amount of working capital, and the revenues generated from our properties in Montana and North Dakota alone may not be sufficient to fund both our continuing operations and our planned growth.  We may require additional capital to continue to operate our business beyond the initial phase of our current properties, and to further expand our exploration and development programs to additional properties.  We may be unable to obtain additional capital required.

Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) may require a substantial amount of additional capital and cash flow.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means.  We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means.  If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned expansion of operations going forward.

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Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders.  This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity.  The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

Our ability to obtain needed financing may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our status as a new enterprise without a significant demonstrated operating history, the location of our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and/or the loss of key management.  Further, if oil and/or natural gas prices on the commodities markets decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital.  If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs.  We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes, which may adversely impact our financial condition.

We have minimal operating history, which may raise substantial doubt as to our ability to successfully develop profitable business operations.

We have a limited operating history.  Our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the oil and natural gas industries.  We first generated revenues from operations in the fiscal year ended December 31, 2008, and have been primarily focused on exploratory drilling and fund raising activities.  There is nothing at this time on which to base an assumption that our business operations will prove to be successful in the long-term.  Our future operating results will depend on many factors, including:

▪   our ability to raise adequate working capital;

▪   success of our development and exploration;

▪   demand for natural gas and oil;

▪   the level of our competition;

▪   our ability to attract and maintain key management and employees; and

▪   our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

To achieve profitable operations in the future, we must, alone or with others, successfully execute on the factors stated above, along with continually developing ways to enhance our production efforts, when commenced.  Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals.  There is a possibility that some, or all, of our wells may never produce natural gas or oil.

We are highly dependent on Michael Reger, our Chief Executive Officer and Chairman and Ryan Gilbertson, Chief Financial Officer.  The loss of either of them, upon whose knowledge, leadership and technical expertise we rely, would harm our ability to execute our business plan.

Our success depends heavily upon the continued contributions of Michael Reger and Ryan Gilbertson, whose knowledge, leadership and technical expertise would be difficult to replace, and on our ability to retain and attract experienced engineers, geoscientists and other technical and professional staff.  If we were to lose their services, our ability to execute our business plan would be harmed and we may be forced to cease operations until such time as we could hire a suitable replacement for them.  Mr. Reger and Mr. Gilbertson recently entered into

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employment agreements with the Company, however, they may terminate their employment with the Company at any time.

Our management team does not have extensive experience in public company matters, which could impair our ability to comply with legal and regulatory requirements.

Our management team has had limited public company management experience or responsibilities, which could impair our ability to comply with legal and regulatory requirements such as the Sarbanes-Oxley Act of 2002 and applicable federal securities laws, including filing required reports and other information required on a timely basis.  It may be expensive to implement and effect programs and policies in an effective and timely manner that adequately respond to increased legal, regulatory compliance and reporting requirements imposed by such laws and regulations, and we may not have the resources to do so.  Our failure to comply with such laws and regulations could lead to the imposition of fines and penalties and further result in the deterioration of our business.

Our lack of diversification will increase the risk of an investment in the Company, and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business focus is on the oil and gas industry in a limited number of properties, initially in Montana and North Dakota.  Larger companies have the ability to manage their risk by diversification.  However, we will lack diversification, in terms of both the nature and geographic scope of our business.  As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile.  If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.  These realities are subject to change and may impair our ability to grow.

To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business.  We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them.  In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships.  If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.

The oil and gas industry is highly competitive.  Other oil and gas companies may seek to acquire oil and gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate.  This competition is increasingly intense as prices of oil and natural gas on the commodities markets have risen in recent years.  Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors.  Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage.  In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests.  If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

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We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions expanding our business.  If we fail to effectively manage our growth, our financial results could be adversely affected.  Growth may place a strain on our management systems and resources.  We must continue to refine and expand our business capabilities, our systems and processes and our access to financing sources.  As we grow, we must continue to hire, train, supervise and manage new employees.  We cannot assure that we will be able to:

▪   meet our capital needs;

▪   expand our systems effectively or efficiently or in a timely manner;

▪   allocate our human resources optimally;

▪   identify and hire qualified employees or retain valued employees; or

▪   incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect your investment in our common stock.

Our current credit facility with CIT Capital USA, Inc. imposes specific hedging requirements for our future production.  At the current time, we have hedged approximately 20% of our expected 2009 production and less than 5% of our 2010 and 2011 production.  While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.  In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

▪   our production is less than expected;

▪   there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

▪   the counterparties to our hedging agreements fail to perform under the contracts.

Risks Related To Our Industry

Oil and natural gas prices are very volatile.  A protracted period of oil and natural gas prices similar to or below the prices in effect at December 31, 2008 may adversely affect our business, financial condition, results of operations or cash flows.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices.  The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  The prices we receive for our production and the levels of our production depend on numerous factors beyond our control.  These factors include, but are not limited to, the following:

▪   changes in global supply and demand for oil and gas;

▪   the actions of the Organization of Petroleum Exporting Countries;

▪   the price and quantity of imports of foreign oil and gas;

▪   political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;

▪   the level of global oil and gas exploration and production activity;

▪   the level of global oil and gas inventories;

▪   weather conditions;

▪   technological advances affecting energy consumption;

▪   domestic and foreign governmental regulations;

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▪   proximity and capacity of oil and gas pipelines and other transportation facilities;

▪   the price and availability of competitors’ supplies of oil and gas in captive market areas; and

▪   the price and availability of alternative fuels.

Furthermore, the recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide.  The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has lead to a worldwide economic recession.  The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. 

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings.  A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.  To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending or borrow any such shortfall.  Lower oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations, as well as special redeterminations described in the credit agreement.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our development, exploitation, production and exploration activities.  Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production.  Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.  Our cost of drilling, completing and operating wells is often uncertain before drilling commences.  Overruns in budgeted expenditures are common risks that can make a particular project uneconomical.  Further, many factors may curtail, delay or cancel drilling, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and CO2;

• equipment failures or accidents; and

• adverse weather conditions, such as freezing temperatures, hurricanes and storms.

Our exploration for oil and gas is risky and may not be commercially successful, and the advanced technologies we use cannot eliminate exploration risk, which could impair our ability to generate revenues from our operations.

Our future success will depend on the success of our exploratory drilling program.  Oil and gas exploration involves a high degree of risk.  These risks are more acute in the early stages of exploration.  Our ability to produce revenue and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage.  Especially in recent years, the prices at which oil and natural gas trade in the open market have experienced significant volatility, and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:

▪   domestic and foreign demand for oil and natural gas by both refineries and end users;

▪   the introduction of alternative forms of fuel to replace or compete with oil and natural gas;

▪   domestic and foreign reserves and supply of oil and natural gas;

▪   competitive measures implemented by our competitors and domestic and foreign governmental bodies;

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▪   political climates in nations that traditionally produce and export significant quantities of oil and natural gas (including military and other conflicts in the Middle East and surrounding geographic region) and regulations and tariffs imposed by exporting and importing nations;

▪   weather conditions; and

▪   domestic and foreign economic volatility and stability.

Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities.  It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators.  They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible.  In addition, the use of three-dimensional (3-D) seismic data becomes less reliable when used at increasing depths.  We could incur losses as a result of expenditures on unsuccessful wells.  If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

We may not be able to develop oil and gas reserves on an economically viable basis, and our reserves and production may decline as a result.

If we succeed in discovering oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable.  On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves.  Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced.  Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.  Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.  In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells.  These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions.  While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case.  Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

Estimates of oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.

We will make estimates of oil and natural gas reserves, upon which we will base our financial projections.  We will make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions.  Economic factors beyond our control, such as interest rates, will also impact the value of our reserves.  The process of estimating oil and natural gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property.  As a result, our reserve estimates will be inherently imprecise.  Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary

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substantially from those we estimate.  If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others.  The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results.  We may become subject to liability for pollution, blow-outs or other hazards.  We intend to obtain insurance with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities.  The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets.  Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable.  Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial.  Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves.  Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.”  We have not yet determined whether we will establish a cash reserve account for these potential costs in respect of any of our properties or facilities, or if we will satisfy such costs of decommissioning from the proceeds of production in accordance with the practice generally employed in oilfield operations.  If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs.  The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

We may have difficulty distributing our production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce, we may have to make arrangements for storage and distribution to the market.  We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate.  This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities.  These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Environmental risks may adversely affect our business.

All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations.  Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.  The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge.

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The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

Our business will suffer if we cannot obtain or maintain necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities.  Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors.  Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations.

Challenges to our properties may impact our financial condition.

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense.  While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist.  In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all.  If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate.  If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired. To mitigate tile problems it is common industry practice to obtain a Title Opinion from a qualified oil and gas attorney prior to the drilling operations of a well.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities.  We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence.  The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development.  If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired.  Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

Risks Related to our Common Stock

The market price of our common stock is, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to continue to be highly volatile and could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including:

▪   dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

▪   announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;

▪   our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives;

▪   fluctuations in revenue from our oil and gas business as new reserves come to market;

▪   changes in the market for oil and natural gas commodities and/or in the capital markets generally;

▪   changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels;

▪   quarterly variations in our revenues and operating expenses;

▪   changes in the valuation of similarly situated companies, both in our industry and in other industries;

▪   changes in analysts’ estimates affecting our company, our competitors and/or our industry;

▪   changes in the accounting methods used in or otherwise affecting our industry;

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▪   additions and departures of key personnel;

▪   announcements of technological innovations or new products available to the oil and gas industry;

▪   announcements by relevant governments pertaining to incentives for alternative energy development programs;

▪   fluctuations in interest rates and the availability of capital in the capital markets; and

▪   significant sales of our common stock, including sales by selling stockholders following the registration of shares under a prospectus.

These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our results of operations and financial condition.

Our operating results may fluctuate significantly, and these fluctuations may cause the price of our common stock to decline.

Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the coming to market of oil and natural gas reserves that we are able to discover and develop, expenses that we incur, the prices of oil and natural gas in the commodities markets and other factors.  If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.

Stockholders will experience dilution upon the exercise of options.

As of December 31, 2008, we had authorized the issuance of up to 2,000,000 shares of common stock underlying options that may be granted, of which options for 1,660,000 shares of common stock had already been granted, and of those granted, 400,000 remain outstanding, pursuant to our 2006 Incentive Stock Option Plan.  On January 30, 2009, our Board of Directors also adopted the 2009 Equity Incentive Plan, pursuant to which we may issue up to 3,000,000 shares of our common stock either upon exercise of stock options granted under such plan or through restricted stock awards under such plan.  If the holders of outstanding options exercise those options or our Compensation Committee determines to grant restricted stock awards under our incentive plan, stockholders may experience dilution in the net tangible book value of our common stock.  Further, the sale or availability for sale of the underlying shares in the marketplace could depress our stock price.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business.  Therefore, investors will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all.  Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock.

Item 1B. Unresolved Staff Comments

None.

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Item 2.  Properties

Leasehold Properties

Our principal assets continue to be located in the Williston Basin region of the northern United States and Yates County, New York, and included the following primary positions as of December 31, 2008:

▪   Approximately 30,000 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 to target the Bakken Shale

▪   Approximately 25,000 net acres located in Dunn County, North Dakota, in which we are targeting the Bakken Shale and Three Forks/Sanish formations

▪   Approximately 22,000 net acres located in Sheridan County, Montana, representing a stacked pay prospect

▪   Approximately 10,000 net acres located in Burke and Divide Counties of North Dakota, targeting the Bakken Shale and Three Forks/Sanish formations near significant drilling activities by Marathon Oil Corporation

▪   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

▪   Approximately 5,000 net acres located in McKenzie, Williams and Mercer Counties North Dakota, in which we are targeting the Bakken Shale.

These properties target the same Bakken Shale resource formation.  We believe the Bakken formation represents one of the most oil rich, exciting plays in the Continental United States.  The North Dakota Geological Survey currently estimates the reserves in the Bakken formation to be 300 billion barrels, of which approximately 50% is thought to be currently recoverable, making it one of the largest resource plays in the Continental United States.  We possess three-dimensional (3-D) seismic data covering our acreage in Montana and North Dakota, which we hope to utilize to effectively target the most effective well locations on our acreage to most efficiently develop our properties. We commenced drilling on the Bakken properties in late 2007.   Based on 640-acre spacing, our current acreage position would allow us to participate in up to 110 net wells.

In addition, we control 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 possess two-dimension (2-D) seismic data veering this position.  Two wells were recently drilled by Chesapeake Energy proximal to our acreage.  We understand the results of these wells to be positive and bode well for the future potential of our acreage.  This property is outside of our core focus area and is subject to divestiture although no assurances can be given that we could complete a transaction.

Acreage Acquisitions

The discussion that follows summarizes our primary recent acquisitions.  We have made various additional acquisitions of acreage through numerous small transactions pursuant to which we purchased oil, gas and mineral leases.

Montana Acquisition

In February 2007, we acquired leasehold interests in approximately 22,000 net mineral acres in Sheridan County, Montana.  We paid a combination of cash and stock as consideration for such acquisition, including the issuance of an aggregate of 400,000 restricted shares of our common stock.

North Dakota Acquisitions

At various points in late 2007 and throughout 2008, we acquired leasehold interests in approximately 21,498 net mineral acres of land via bulk purchases in the core development area of Mountrail County, North Dakota.  We paid a combination of cash and stock as consideration for such acquisitions, including the issuance of an aggregate of 633,027 restricted shares of our common stock.  In addition to these major acquisitions we completed a series of small transactions pursuant to which we purchased leasehold interests in approximately 8,000 net mineral acres in Mountrail County.

On June 11, 2008, we entered into a purchase agreement pursuant to which we ultimately acquired leasehold interests in approximately 23,210 net mineral acres primarily in Dunn County, North Dakota.  We also completed various additional acquisitions of oil and gas leasehold interests through numerous small transactions with several parties in fiscal years 2007 and 2008.

At various points in 2007 and 2008, we purchased leasehold interests in approximately 10,000 net mineral acres in and around Burke and Divide Counties of North Dakota for cash consideration.

We have also completed other miscellaneous non-material acquisitions in North Dakota, and utilized a combination of stock and cash consideration for some of the acquisitions.

New York Acquisition

In September 2007, we acquired leasehold interests in approximately 10,000 net mineral acres in the Appalachia Basin of New York.  We paid a combination of cash and stock as consideration for such acquisition, including the issuance of an aggregate of 275,000 restricted shares of our common stock.

Certain of the foregoing acquisitions were purchased using the services of, or purchased from, parties considered to be related to our company or our Chief Executive Officer, Michael L. Reger.  All transactions involving related parties were approved by our Board of Directors or Audit Committee and we obtained independent verification of the fairness of consideration paid in each transaction.

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Undeveloped and Developed Acreage

The following table summarizes our estimated gross and net developed and undeveloped acreage by county at December 31, 2008.   Net acreage represents our percentage ownership of gross acreage.  The following table does not include acreage in which our interest is limited to royalty and overriding royalty interests.

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
North Dakota		6,011		2,339		173,989		67,661		180,000		70,000
Montana		1,644		640		23,356		21,360		25,000		22,000
New York		0		0		10,000		10,000		10,000		10,000
Total:		7,655		2,979		207,345		99,021		215,000		102,000

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Production History

The following table presents information about our produced oil and gas volumes during the year ended December 31, 2008.  Comparative information is not available for any prior years because as of December 31, 2007 we had only two wells that had just begun to produce oil and had not yet received sales or payment data from our operating partners or purchasers regarding that production.  As of December 31, 2008, we were selling oil and natural gas from a total of 36 gross wells.  All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

	Three Months Ended March 31, 2008		Three Months Ended June 30, 2008		Three Months Ended September 30, 2008		Three Months Ended December 31, 2008		Year-End December 31, 2008
Net Production:
Oil (Bbl)		3,143		6,354		13,111		28,272		50,880
Natural Gas (Mcf)		4		114		412		3,439		3,969
Barrel of Oil Equivalent (Boe)		3,144		6,373		13,180		28,845		51,542
Average Sales Prices:
Oil (per Bbl)	$	90.89	$	120.04	$	108.72	$	48.61	$	75.63
Effect of oil hedges on average price (per Bbl)	$	0.41		--		--	$	27.50	$	15.31
Oil net of hedging (per Bbl)	$	91.30	$	120.12	$	103.50	$	76.11	$	90.94
Natural Gas (per Mcf)	$	9.25	$	15.48	$	13.96	$	7.25	$	8.19
Natural Gas (per Mcf)	$	9.25	$	15.48	$	13.96	$	7.25	$	8.19
Effect of natural gas hedges on average price (per Mcf)		--		--		--		--		--
Average Production Costs:
Oil (per Bbl)	$	0 .44	$	1.25	$	1.37	$	1.50	$	1.37
Natural Gas (per Mcf)	$	0 .50	$	0.45	$	0.27	$	0.32	$	0.32
Barrel of Oil Equivalent (Boe)	$	0 .44	$	1.26	$	1.37	$	1.51	$	1.38

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Depletion of oil and natural gas properties

Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses for the year ended December 31, 2008.

	Three Months Ended March 31, 2008		Three Months Ended June 30, 2008		Three Months Ended September 30, 2008		Three Months Ended December 31, 2008		Year-Ended December 31, 2008
Depletion of oil and natural gas properties	$	40,636	$	106,942	$	190,501	$	447,425	$	785,504

Productive Oil Wells

The following table summarizes gross and net productive oil wells by state at December 31, 2008 and 2007.  A net well represents our percentage ownership of a gross well. No wells have been permitted or drilled on any of our Yates County, New York acreage.  The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation.

	December 31,
	2008				2007
	Gross		Net		Gross		Net
North Dakota		34		1.54		2	0.0875
Montana		2		0.50		0	0
Total		36		2.04		2	0.0875

Dry Holes

In the second quarter of 2007, we participated in the Teigen Trust #9-13 with a 6.25% working interest, a well identified, proposed and drilled by Kodiak Oil and Gas, Inc.   The well was intended to target the Mission Canyon formation, but produced a dry hole.  We did not have any dry holes in 2008.

Drilling Activity

We are engaged in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future.  The following table sets forth our drilling activity for the last three years.  The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value.  Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

As of March 16, 2009 we have total of 65 wells that are either drilling, completing or producing, including 46 producing wells and 19 drilling or completing wells.  The following table sets forth wells that have completed drilling and are producing oil as of March 16, 2009:

Well Name	County	Operator	Northern Oil Working Interest
Bergstrom Trust 26-1H	Mountrail, ND	Brigham Exploration	6.2500%(1)
Hallingstad 27-1H	Mountrail, ND	Brigham Exploration	8.4375%(2)
Richardson 25-1	Sheridan, MT	Brigham Exploration	37.0000%
Richardson 30-1	Sheridan, MT	Brigham Exploration	12.5000%(3)

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Well Name	County	Operator	Northern Oil Working Interest
Johnson 33-1H	Mountrail, ND	Brigham Exploration	12.5000%(4)
Friedrick Trust 31-1	Sheridan, MT	Brigham Exploration	23.3175%
Bonney 34-3H	Dunn, ND	Burlington Resources	2.7344%
Shonna  1-15H	Divide, ND	Continental Resources	14.8438%
Skachenko 1-31H	Dunn, ND	Continental Resources	6.2500%
Elveida  1-33H	Divide, ND	Continental Resources	9.8631%
Arvid 1-34H	Divide, ND	Continental Resources	4.8622%
Thorvald 1-6H	Dunn, ND	Continental Resources	6.7000%
Landblom 1-35 H	Divide, ND	Continental Resources	0.3125%
Oilers 1H-10	Richland, MT	Crusader Energy	6.5972%
Wayzetta   1-13H	Mountrail, ND	EOG Resources	6.2500%
Austin 19-30H	Mountrail, ND	EOG Resources	3.0925%(5)
Clearwater 1-2H	Mountrail, ND	EOG Resources	3.6431%
En-Neset-0706H-1	Mountrail, ND	Hess Corporation	2.8000%
En-Person-1102H-1	Mountrail, ND	Hess Corporation	12.1809%
Rs-Agribank-1102H-1	Mountrail, ND	Hess Corporation	4.7880%(6)
En-Hynek-0112H-1	Mountrail, ND	Hess Corporation	0.7811%
Bl-Blanchard-155-96-1522H-1	Williams, ND	Hess Corporation	2.5000%
Reiss  34-20H	Dunn, ND	Marathon Oil Company	2.4509%
Kent Carlson  24-36H	Dunn, ND	Marathon Oil Company	6.2500%
Voigt 11-15H	Dunn, ND	Marathon Oil Company	0.7919%
Clive Pelton 34-23H	Dunn, ND	Marathon Oil Company	1.1719%
Kovaloff 21-17H	Dunn, ND	Marathon Oil Company	0.6250%
Strommen 14-8H	Dunn, ND	Marathon Oil Company	2.5008%
Eckelberg 41-26H	Dunn, ND	Marathon Oil Company	0.3900%
Mark Sandstrom 14-32H	Mountrail, ND	Marathon Oil Company	3.8691%
Jay Sandstrom 34-31H	Mountrail, ND	Marathon Oil Company	0.4771%
Jodi Carlson 24-12H	Dunn, ND	Marathon Oil Company	1.2500%
Norton 24-12H	Dunn, ND	Marathon Oil Company	1.2500%
Rick Clair  25-36H	Mountrail, ND	Murex Petroleum	6.2500%
Gladys 1-9H	McKenzie, ND	Newfield Exploration	2.6042%
Nelson 1-26H	Mountrail, ND	Sinclair Oil	2.6042%
Pathfinder  1-9H	Mountrail, ND	Slawson Exploration	2.6000%
Voyager 1-28H	Mountrail, ND	Slawson Exploration	4.9609%
Prowler  1-16H	Mountrail, ND	Slawson Exploration	3.4375%
Payara  1-21H	Mountrail, ND	Slawson Exploration	2.3125%
Peacemaker 1-8H	Mountrail, ND	Slawson Exploration	14.4220%
Jericho 1-5H	Mountrail, ND	Slawson Exploration	42.0000%
Pet-Inc Federal 20-44	McKenzie, ND	St. Mary Land and Exploration	7.2006%
Moi 22-15H	Billings, ND	Whiting Oil & Gas	2.3438%
Braaflat 11-11H	Mountrail, ND	Whiting Oil and Gas	0.0100%
Federal 11-9H	Mountrail, ND	Whiting Oil and Gas	.390625%

­­­­­­­­­­___________________________

(1)   Upon achieving payout, our working interest will increase to 24.5%.

(2)   Upon achieving payout, our working interest will increase to 20.5%.

(3)   Upon achieving payout, our working interest will increase to 21.25%.  Additionally, we have a 1.0% overriding royalty interest on all production from this well.

(4)   Upon achieving payout, our working interest will decrease to 8.125%.

(5)   Upon achieving payout, our working interest will increase to 4.02%.

(6)   Upon achieving payout, our working interest will decrease to 3.1122%.

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The following table sets forth wells that have commenced drilling but are not producing oil as of March 16, 2009:

Well Name	County	Operator	Northern Oil Working Interest
Armstrong 1-24H	Billings, ND	Continental Resources	1.2188%
Sidonia 1-06H	Mountrail, ND	EOG Resources	9.6486%
Austin 3-4H	Mountrail, ND	EOG Resources	0.3906%
Parshall  12-27H	Mountrail, ND	EOG Resources	0.3125%
Parshall 11-28H	Mountrail, ND	EOG Resources	0.3125%
Fladeland11-30H	Mountrail, ND	Fidelity Exploration	1.1405%
Rs-F. Armour 156-92-1213H	Mountrail, ND	Hess Corporation	0.2344%
En-Enget 158-93-1009-1H	Mountrail, ND	Hess Corporation	2.5000%
Bangen 41-27H	Mountrail, ND	Marathon Oil Company	5.7813%
Shobe 24-20H	Mountrail, ND	Marathon Oil Company	0.7440%
Chad Allen	Mountrail, ND	Murex Petroleum	6.2500%
Wisness 1-4H	Mckenzie	Newfield Exlportation	5.0000%
Bandit  1-29H	Mountrail, ND	Slawson Exploration	26.2500%
Nightcrawler  1-17H	Mountrail, ND	Slawson Exploration	2.9200%
Lee 28-1H	Dunn, ND	Tracker Resources	6.2500%
Lacey 11-12H	Mountrail, ND	Whiting Oil % Gas	0.4000%
Braaflat 11-1H	Mountrail, ND	Whiting Oil & Gas	0.4000%
Wolf 1-4H	Mountrail, ND	Windsor Energy	15.8116%
Sig 21x-6	Divide, ND	XTO Energy	1.4372%

Including the wells set forth in the foregoing tables, we estimate that approximately 240 sections in which we have acreage interests have been included in permits to drill wells within North Dakota and Montana.  We do not know if or when applicable operators will chose to commence drilling activities for any contemplated well that is not yet drilling.

Brigham Exploration Joint Ventures

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 approximately 70,000 net acres located in North Dakota and approximately 22,000 net acres of our Sheridan County, Montana acreage.  Commencing in 2008, Brigham was subject to a 120 day continuous drilling provision requiring Brigham to drill every 120 days to retain future drilling opportunities on our Sheridan County Acreage.  Drilling under the Brigham joint venture commenced in the early fourth quarter of 2007.  During 2008, Brigham drilled and successfully completed two wells in North Dakota and two wells in Montana under the joint venture.  Subsequent to December 31, 2008, we have completed a third Red River producer with Brigham under this Joint Venture.

Slawson Exploration Drilling Arrangement

On October 30, 2008, we executed a drilling agreement with Slawson Exploration covering certain of our acreage in Mountrail County, North Dakota for a single 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 was completed, we controlled a 42% working interest in the section to be drilled.  Drilling commenced for the Jericho 1-5H well on January 31, 2009, as a horizontal Bakken well drilled on the 640 acre spacing unit.  The Jericho 1-5H was completed in early March 2009.  We expect to utilize this arrangement with Slawson to further develop our high working interest sections throughout 2009.  We do not, however, anticipate selling down working interest but rather drilling units where both Slawson and our company have significant leasehold interest.

Research and Development

We do not anticipate performing any significant product research and development under our plan of operation.

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Reserves

We completed our most recent reservoir engineering calculation in February 2009.  A discussion of our reserve estimations and a table summarizing the results of our most recent reserve report are included under the heading “Business – Reserves” in Item 1 of this report.

Delivery Commitments

We do not currently have any delivery commitments for product obtained from our wells.

Item 3.  Legal Proceedings

As of March 16, 2009, our company was a party to one litigation claim arising in the ordinary course of business and seeking the quieting of title for a leasehold interest acquired from a third party.  To the knowledge of management, no federal, state or local governmental agency is presently contemplating any proceeding against the Company.  No director, executive officer or affiliate of the Company or owner of record or beneficially of more than five percent of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.

On or about December 19, 2008, we instituted a FINRA dispute Resolution matter against UBS Financial Services, Inc. (“UBS”) relating to certain unauthorized trades conducted by UBS in connection with our commodities hedging account at that institution.  The matter relates to what we allege to be UBS’s improper attribution of an unauthorized long trade to our hedging account.  When our management brought the error to UBS’s attention, UBS acknowledged to two members of our management that the contracts were erroneously allocated to our account due to an error and explained that the mistake would be corrected and that an amended statement would be issued.  Ultimately UBS liquidated the contracts without any instruction from our company.  In addition to this event, UBS subsequently admitted that it had committed other errors in trading for our hedging account. We are seeking damages from UBS in excess of $870,000, plus attorneys’ fees.  We recently received UBS’s response to our Statement of Claim and the matter currently is in the discovery stage of proceedings.  We are confident that given the facts, and given UBS’s financial ability to do so, we will recover damages in this action.

Our management believes that all litigation matters in which we are involved are not likely to have a material adverse effect on our financial position, cash flows or results of operations.

Item 4.  Submission of Matters to a Vote of Security Holders 

No matters were submitted to a vote of our stockholders during the fourth fiscal quarter of 2007.

Executive Officers of the Registrant

Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this annual report.  The following are our executive officers as of March 16, 2009.

Name	Age	Positions
Michael L. Reger	32	Chairman, Chief Executive Officer and Secretary
Ryan R. Gilbertson	33	Director and Chief Financial Officer

Michael L. Reger has served as our Chief Executive Officer, Secretary and a Director since March 2007.  Mr. Reger has been primarily involved in the acquisition of oil, gas and mineral rights for his entire professional life and is a director of Reger Oil based in Billings, Montana.  Mr. Reger holds a Bachelor of Arts in Finance and an MBA in Finance/Management from the University of St. Thomas in St. Paul, Minnesota.  The Reger family has a history of acreage acquisition in the Williston Basin dating to 1952.

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Ryan R. Gilbertson has served as our Chief Financial Officer and a Director since March 2007.  Mr. Gilbertson’s last position prior to co-founding Northern was at Piper Jaffray in Minneapolis from March 2004 to August 2006.  Prior to Piper Jaffray, Ryan was a portfolio manager at Telluride Asset Management, a multi-strategy hedge fund based in Wayzata, Minnesota. Ryan holds a BA from Gustavus Adolphus College in International Business/Finance.

PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock was listed on the OTC Bulletin Board of the National Association of Securities Dealers (“NASD”) on January 19, 2006, under the symbol “KNTX”, but there was no active trading prior to approximately December 2006.  Effective April 3, 2007, after the Merger and name change, our trading symbol was changed to “NOGS.OB.”  Our common stock commenced trading on the AMEX on March 26, 2008 under the symbol “NOG.”

The high and low bid and offer prices for shares of common stock of our company for each quarter during 2007 is set forth below, although data prior to March 2007 is not applicable to the current structure of the Company.  The high and low sales prices for shares of common stock of our company for each quarter during 2008 is set forth below.  The difference in reference price used for the tables below results from transitioning the listing of our common stock from the OTC Bulletin Board to the AMEX in the first quarter of 2008.

	Sales Price
2008 fiscal year	High		Low
First Quarter	$	7.30	$	5.65
Second Quarter		16.40		6.95
Third Quarter		14.00		5.14
Fourth Quarter		8.13		2.05

	Closing Bid
2007 fiscal year	High		Low
First Quarter	$	5.00	$	1.10
Second Quarter		5.50		3.40
Third Quarter		6.50		4.40
Fourth Quarter		7.90		4.92

Prices set forth above for the 2007 fiscal year were obtained from the National Quotation Bureau, Inc. and do not necessarily reflect actual transactions, retail markups, mark downs or commissions.  Stock price data before March 20, 2007, is for the prior “shell company”—Kentex—and therefore may not be relevant to any analysis of the post-Merger Company.  Kentex common stock did not commence quotation until the third quarter of fiscal year 2006.

The closing price for our common stock on the AMEX on March 13, 2008 was $2.61 per share.

Comparison Chart

The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be

25

deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

The following graph compares on a cumulative basis changes since completion of our reverse merger on April 13, 2007 in (a) the total stockholder return on our common stock with (b) the total return on the Standard & Poor’s Composite 500 Index and (c) the total return on the Amex Oil Index.  Such changes have been measured by dividing (a) the sum of (i) the amount of dividends for the measurement period, assuming dividend reinvestment, and (ii) the difference between the price per share at the end of and the beginning of the measurement period, by (b) the price per share at the beginning of the measurement period.  The graph assumes $100 was invested on April 13, 2007 in our common stock, the Standard & Poor’s Composite 500 Index and the Amex Oil Index.  We have not included any graph for any period prior to April 13, 2007, because there was no active trading in our common stock prior to April 13, 2007 and, as such, data is not available for any period prior to such date.

	4/13/07			12/31/07		12/31/08
Northern Oil and Gas, Inc.	$	100	$	173.75	$	65.00
Standard & Poor’s Composite 500 Index		100		101.07		62.17
Amex Oil Index		100		122.70		77.07

Holders

As of March 9, 2009, we had 34,120,103 shares outstanding of our common stock, held by approximately 437 shareholders of record.  The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

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Dividends

The payment of dividends is subject to the discretion of our Board of Directors and will depend, among other things, upon our earnings, our capital requirements, our financial condition, and other relevant factors.  We have not paid or declared any dividends upon our common stock since our inception and, by reason of our present financial status and our contemplated financial requirements, and do not anticipate paying any dividends upon our common stock in the foreseeable future.  We intend to reinvest any earnings in the development and expansion of our business.  Any cash dividends in the future to common stockholders will be payable when, as and if declared by our Board of Directors or our Compensation Committee, based upon either the Board’s or the Committee’s assessment of:

▪   our financial condition and performance;

▪   earnings;

▪   need for funds;

▪   capital requirements;

▪   prior claims of preferred stock to the extent issued and outstanding; and

▪   other factors, including income tax consequences, restrictions and any applicable laws.

There can be no assurance, therefore, that any dividends on the common stock will ever be paid.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information with respect to our common shares issuable under our equity compensation plans as of December 31, 2008:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders
Incentive Stock Option Plan	400,000	$ 5.18	340,000
Equity compensation plans not approved by security holders
None	-	-	-
Total	400,000	$ 5.18	340,000

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

On December 23, 2008, we issued 15,902 shares of restricted common stock to Twin City Technical, LLC as partial consideration for our acquisition of leases covering approximately 808 net mineral acres in North Dakota.  Additionally, on December 23, 2008, we issued 7,072 shares of restricted common stock to Missouri River Royalty Corporation as partial consideration for our acquisition of leases covering approximately 130 net mineral acres in

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North Dakota.  On December 23, 2008, we issued 4,465 shares of restricted common stock to Turmoil, LLC as partial consideration for our acquisition of leases covering approximately 224 net mineral acres in North Dakota.  On December 23, 2008, we issued 500 shares of restricted common stock to David Bickerstaff as consideration for services provided to our company.  All of the foregoing transactions were approved by our board of directors.  None of the foregoing shares of our common stock were issued for cash consideration and, as such, we did not receive any proceed from the issuance of the foregoing securities.

All of the foregoing shares were issued pursuant to the exemption from registration provided in Section 4(2) of the Act.  In each instance, the recipients of the shares were afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make its investment decision, including the Company’s financial statements and reports filed pursuant to the Exchange Act.  We reasonably believe that each recipient, immediately prior to issuing the shares, had such knowledge and experience in financial and business matters that it was capable of evaluating the merits and risks of its investment.  Each recipient had the opportunity to speak with our officers and directors on several occasions prior to their investment decision.

Item 6.  Selected Financial Data

The financial statement information set forth below is derived from our balance sheets as of December 31, 2008 and 2007, and the related statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2008 and 2007 and for the period from inception [October 5, 2006] through December 31, 2006 included elsewhere in this report.  Financial statement information for the years ended December 31, 2005 and 2004 and the balance sheet information at December 31, 2006, 2005 and 2004 are derived from audited financial statements presented in our December 31, 2006 Form 10-KSB report and not included in this report, which financial statements were the historical financial statements of Kentex Petroleum, Inc, our company prior to the acquisition of Northern on March 20, 2007.

		Year Ended December 31, 2008		Year Ended December 31, 2007			From Inception on October 5, 2006 through December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004
Statements of Income Information:
Revenues
Oil and Gas Sales		$	3,542,994		--			--			--			--
Gain on Derivatives			778,885		--			--			--			--
Total Revenues	��	$	4,321,879		--			--			--			--
Operating Expenses
Production Expenses		$	70,954		--			--			--			--
Severance Taxes			203,182		--			--			--			--
General and Administrative Expense			2,091,289	$	4,509,743		$	76,374		$	12,267		$	30,084
Depletion Oil and Gas Properties			785,504		--			--			--			--
Depreciation and Amortization			67,060		3,446			--			--			--
Accretion of Discount on Asset Retirement Obligations			1,030		--			--			--			--
Total Expenses		$	3,219,019	$	4,513,189		$	76,374		$	12,267		$	30,084
Income (loss) from operations		$	1,102,860	$	(4,513,189	)	$	( 76,374	)	$	( 12,267	)	$	( 30,084	)
Other Income			383,891		207,896			267			25,000			--

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Income (loss) Before income taxes	$	1,486,751		$	(4,305,293	)	$	( 76,107	)	$	( 12,733	)	$	( 30,084	)
Income tax provision (Benefit)		(873,000	)		--			--			--			--
Net income (loss)	$	2,359,751		$	(4,305,293	)	$	( 76,107	)	$	( 12,733	)	$	( 30,084	)
Net Income (Loss) Per Common Share – Basic and Diluted		0.07			(0.18	)		(0.01	)		(0.01	)		(0.01	)
Weighted Average Shares Outstanding – Basic		31,920,747			23,667,119			18,000,000			2,357,998			2,357,997
Weighted Average Shares Outstanding - Diluted		32,653,552			23,667,119			18,000,000			2,357,998			2,357,997
Balance Sheet Information:
Total Assets	$	62,875,539		$	18,131,464		$	1,105,935			--			--
Total Liabilities	$	13,411,065		$	224,247		$	1,143,067		$	30,811		$	43,544
Stockholder's Equity (Deficit)	$	49,464,474		$	17,907,217		$	37,132		$	( 30,811	)	$	( 43,544	)
Statement of Cashflow Information:
Net cash used provided by (used for) operating activities	$	2,506,492		$	( 491,509	)	$	( 38,532	)		--			--
Net cash used provided by (used for) investing activities	$	(40,357,962	)	$	(5,078,758	)	$	( 255,000	)		--			--
Net cash used provided by (used for) financing activities	$	28,519,526		$	14,832,992		$	1,143,467			--			--

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

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.

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

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.

Overview and Outlook

We are an oil and gas exploration and production company.  Our properties are located in Montana, North Dakota and New York.  Our corporate strategy is to build shareholder value through the development and acquisition of oil and gas assets that exhibit economically producible hydrocarbons.

We currently control the rights to mineral leases on approximately 215,000 gross acres of land, 102,000 net acres of land.  Our goal is to continue to explore for and develop hydrocarbons within the mineral leases we control as well as continue to expand our acreage position should opportunities present themselves.  In order to accomplish our objectives we will need to achieve the following;

▪   Continue to develop our substantial inventory of high quality core Bakken acreage with results consistent with those to-date;

▪   Retain and attract talented personnel;

▪   Continue to be a low-cost producer of hydrocarbons; and

▪   Continue to manage our financial obligations to access the appropriate capital needed to develop our position of primarily undrilled acreage.

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The following table sets forth selected operating data for the periods indicated.  Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

	Year End December 31, 2008		Year End December 31, 2007
Net Production:
Oil (Bbl)		50,880		--
Natural Gas (Mcf)		3,969		--
Net Sales:
Oil Sales	$	3,510,596		--
Natural Gas		32,397		--
Gain on Derivatives		778,885		--
Total Revenues	$	4,321,879		--
Average Sales Prices:
Oil (per Bbl)	$	75.63		--
Effect of oil hedges on average price (per Bbl)	$	15.31		--
Oil net of hedging (per Bbl)	$	90.94		--
Natural Gas (per Mcf)	$	8.19		--
Effect of natural gas hedges on average price (per Mcf)		--		--
Natural gas net of hedging (per Mcf)	$	8.19		--
Operating Expenses:
Production Expenses	$	70,954		--
Severance Taxes	$	203,182		--
General and Administrative Expense	$	2,091,289	$	4,509,743
Depletion Oil and Gas Properties	$	785,504		--

Results of Operations for the periods ended December 31, 2007 and December 31, 2008.

Our first well commenced drilling in the fourth quarter of 2007, and we did not realize revenue from that well until the first quarter of 2008.  During 2008 we significantly increased our drilling activities, generated income and achieved net earnings in the third and fourth quarters of 2008 and for the 2008 fiscal year as a whole.  To-date, we have developed approximately 1.5% of our total drillable acreage inventory and we expect to continue to add substantial volumes of production on a quarter-over-quarter basis going forward into the foreseeable future.

As of March 16, 2009, we have established production from 46 total wells in which we hold working interests, only two of which had established production as of December 31, 2007.  Our production at December 31, 2008 approximated 460 barrels of oil per day, however several wells operated by others were producing on tight chokes and have subsequently been released increasing our approximate daily production, with the addition of other completions, to approximately 950 barrels of oil per day.  This compares to approximately 100 barrels of oil per day as of December 31, 2007.

We drilled with a 100% success rate in 2008 with 59 Bakken or Three Forks wells completed or completing and three successful Red River discoveries at December 31, 2008.  As of March 16, 2009, we expect to participate in the drilling of approximately 60 gross oil wells in 2009.

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Our expenses in the 2007 fiscal year consisted principally of general and administrative costs.  Our costs increased moderately as we proceeded with our development plans in 2008.  In the future we expect to incur increased geologic, geophysical, and engineering costs as we continue to develop our acreage.  Total expenses for the twelve-month period ended December 31, 2007, were $4,513,189 and for the twelve-month period ended December 31, 2008, were $3,219,019.  We had a net loss of $4,305,293 for the twelve-month period ended December 31, 2007, and net income of $2,359,751 (representing approximately $0.07 per share) for the twelve-month period ended December 31, 2008.

Results of Operations for the periods ended December 31, 2006 and December 31, 2007.

During 2006, we had no significant operations.  Following the Merger on March 20, 2007, our operations in 2007 were limited primarily to technical evaluation of the properties and the design of development plans to exploit the oil and gas industry resources on those properties as well as seeking opportunities to acquire additional oil and gas properties.  Our first well commenced drilling in the fourth quarter of 2007, and we did not realize revenue from that well until the first quarter of 2008.

Although we had oil production in the fourth fiscal quarter of 2007 we did not receive payment from this production in the fiscal year.  As of December 31, 2007, we had established production from two wells in which we hold small working interests, compared to no similar activities as of December 31, 2006. This production approximated to 100 barrels of oil per day.

Our expenses in fiscal years 2006 and 2007 consisted principally of general and administrative costs.  Total expenses for the period from inception (October 5, 2006) through December 31, 2006, were $76,374 and for the twelve-month period ended December 31, 2007, were $4,513,189.  We had a net loss of $76,107 for the period from inception (October 5, 2006) through December 31, 2006, and a net loss of $4,305,293 for the twelve-month period ended December 31, 2007.  Of this amount approximately $500,000 consisted of cash expense, the balance was related to share issuance costs which were eliminated in 2008.

Operation Plan

During the next twelve months we plan to continue in earnest the development of our oil and gas properties primarily in the Williston Basin Bakken play.  We expect to drill 60 gross (six to seven net wells) in 2009 with a total Bakken drilling budget of $26 million.

We recognized no revenues from the sale of oil and/or gas in 2007, but recognized $4,321,879 in revenues in 2008.  Our future financial results will depend primarily on: (i) the ability to continue to source and screen potential projects; (ii) the ability to discover commercial quantities of oil and gas; (iii) the market price for oil and gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources.  There can be no assurance that we will be successful in any of these respects, that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding to increase our currently limited capital resources.

2009 Drilling Projects

In 2009, we intend to continue drilling efforts on our existing acreage covering an aggregate of 90,000 net mineral acres in North Dakota and Montana, and to commence drilling or participate in at least 60 new gross wells. For a detailed description of our drilling activity, see “Properties – Drilling Activity” in Item 2 of Part I of this report.

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

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

The following table summarizes total current assets, total current liabilities and working capital at December 31, 2008.  We note, however, that approximately $2.3 million of Auction Rate Securities are not classified as current assets and we have subsequently entered into a credit facility with CIT Capital USA, Inc. that we believe will address both our short-term and long-term liquidity needs.

Current Assets            $   5,193,213

Current Liabilities       $ 13,411,065

Working Capital          $(8,217,852)

CIT Capital USA, Inc. Credit Facility

During the second half of the 2008 fiscal year, we contemplated and pursued a variety of means to fund our growing capital commitments from our drilling activities.  We historically have required continuous access to new capital to fund our participation in wells given the time delay between our pre-payment of drilling expenses and our receipt of revenues from completed wells.  In light of these needs and our management’s desire to minimize shareholder dilution to the extent practicable, we aggressively pursued a debt facility to provide funding for future drilling and operating needs.

On February 27, 2009, we completed the closing of a revolving credit facility with CIT Capital USA Inc. (“CIT”) that will provide up to a maximum principal amount of $25 million of working capital for exploration and production operations (the “Facility”).  The borrowing base of funds available under the Facility will be redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from its interests in proved reserves estimated to be produced from its oil and gas properties.  $11 million of financing is initially available under the Facility.  An additional $14 million of financing could become available upon subsequent borrowing base redeterminations based on the deployment of funds from the Facility.  The Facility terminates on February 27, 2012.

We have the option to designate the reference rate of interest for each specific borrowing under the Facility as amounts are advanced.  Borrowings based upon the London interbank offering rate (LIBOR) will be outstanding for a period of one, three or six months (as designated by us) and bear interest at a rate equal to 5.50% over the one-month, three-month or six-month LIBOR rate to be no less than 2.50%.  Any borrowings not designated as being based upon LIBOR will have no specified term and generally will bear interest at a rate equal to 4.50% over the greater of (a) the current three-month LIBOR rate plus 1.0% or (b) the current prime rate as published by JP Morgan Chase Bank, N.A.  We have the option to designate either pricing mechanism.  Payments are due under the Facility in arrears, in the case of a loan based on LIBOR on the last day of the specified loan period and in the case of all other loans on the last day of each March, June, September and December.  All outstanding principal is due and payable upon termination of the Facility.

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

The Facility required that we enter into a swap agreement with Macquarie Bank Limited (“Macquarie”) to hedge a total of 118,000 barrels of production in total over the next 36 months.  The swap covers 5,500 barrels of oil per month for March 2009 through December 2009, 3,000 barrels of oil per month during entire 2010 calendar year, 2,000 barrels of oil per month during the entire 2011 calendar year and 1,500 barrels of oil per month for January 2012 through February 2012.  The constant price of the swap is fixed at $51.25.  The hedged production is estimated to be equal to approximately 10% of 2009 total production and less than 5% of production volumes in 2010 through 2012.

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All of our obligations under the Facility and the swap agreements with Macquarie are secured by a first priority security interest in any and all assets of the Company pursuant to the terms of a Guaranty and Collateral Agreement and perfected by a mortgage, notice of pledge and security and similar documents.

Satisfaction of Our Cash Obligations for the Next 12 Months

With the addition of the CIT Facility, we believe we will be funded to meet our drilling commitments and expected general and administrative expenses for the next twelve months.  Nonetheless, any strategic acquisition of assets may require us to access the capital markets at some point in 2009.  We believe there may be distressed situations that will arise in 2009 that may make the acquisition of assets a viable strategy, and we will evaluate any potential opportunities as they arise.  Given our non-leveraged asset base and anticipated growing cash flows, we believe we are in a position to take advantage of any distressed sales that may occur.  However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

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

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

Effects of Inflation and Pricing

The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.  Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel.  While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Going Concern

The financial statements included in our filings have been prepared in conformity with generally accepted accounting principles that contemplate the continuance of the Company as a going concern.  Management may use borrowings and security sales to improve the Company’s cash position; however, no assurance can be given that debt or equity financing, if and when required, will be available.  The financial statements do not include any adjustments relating to the recoverability and classification of recorded assets and classification of liabilities that might be necessary should the Company be unable to continue existence.  The audited financial statements for Kentex for the fiscal year ended December 31, 2006, contained a statement by the auditors indicating their

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uncertainty that Kentex would be able to continue as a “going concern.”  The “going concern” disclosure is not presented in the report of our auditors filed herewith, and we believe that the “going concern” disclosure will not be required in our next published financials due to equity capital raised by the Company in 2007 and 2008.

Contractual Obligations and Commitments

As of December 31, 2008, we did not have any material long-term debt obligations, capital lease obligations, operating lease obligations or purchase obligations requiring future payments except our office lease that expires on January 31, 2013, and contains a base rent of approximately $142,459 in 2009 and escalating up to approximately $160,236 during the final lease year.

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 7A.  Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future.  The prices we receive for our production depend on numerous factors beyond our control.  Our revenue during 2008 generally would have increased or decreased along with any increases or decreases in oil prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.

We have previously entered into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil and natural gas price volatility.  Our derivative contracts have historically qualified for cash flow hedge accounting, whereby accounting rules allow the aggregate change in fair market value to be recorded as accumulated other comprehensive income (loss).  Recognition of derivative settlement gains and losses in the statements of income occurs in the period that hedged production volumes are sold.  We did not have any outstanding hedges as of December 31, 2008.

Our Facility with CIT, however, required that we hedge certain amounts of production through February 2012.  For a detailed description of the hedging program, see “Liquidity and Capital Resources – CIT Capital USA, Inc. Credit Facility” in Item 7 of Part II of this report.  In general, we do not expect to use hedges beyond the extent required by our lenders.

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Interest Rate Risk

We did not have outstanding any credit facilities or other obligations that would subject us to significant interest rate risk at December 31, 2008.  Our Facility entered into with CIT on February 27, 2009, will, however, subject us to interest rate risk on borrowings under that facility.

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

Item 8.  Financial Statements and Supplementary Data

Our Financial Statements required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1.

Item 9.  Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.  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 SEC’s rules and forms, 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 December 31, 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 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 December 31, 2008.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.  All internal control systems, no matter how well designed, have inherent limitations.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  Therefore, even those

36

systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting as of December 31, 2008.  In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control-Integrated Framework.”  Based on this assessment, management believes that, as of December 31, 2008, our internal control over financial reporting was effective based on those criteria. There have been no changes in internal control over financial reporting since December 31, 2008, that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by Mantyla McReynolds LLC, an independent registered public accounting firm, as stated in their report which is included herein on the following page.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Northern Oil and Gas, Inc.:

We have audited Northern Oil and Gas, Inc.’s (the Company) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting (Item 9A). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of operations, stockholders’ equity and comprehensive income, and cash flows of the Company, and our report dated March 16, 2009 expressed an unqualified opinion.

Mantyla McReynolds LLC

Salt Lake City, Utah

March 16, 2009

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Item 9B.  Other Information

None.

PART III

We are incorporating by reference information in Items 10 through 14 below from the definitive proxy statement for our 2009 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2008.

Item 10.  Directors, Executive Officers and Corporate Governance

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2009 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2008.  We provided the information required by this item with respect to our executive officers in Part I of this report pursuant to Item 401(b) of Regulation S-K.

Item 11.  Executive Compensation

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2009 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2008.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2009 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2008.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2009 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2008.

Item 14.  Principal Accountant Fees and Services

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2009 Annual Meeting of Stockholders, which we intend to file with the SEC not later than 120 days subsequent to December 31, 2008.

PART IV

Item 15.  Exhibits and Financial Statement Schedules

(a)           The following documents are filed as part of this report:

1.   Financial Statements

See Index to Financial Statements on page F-1.

2.   Financial Statement Schedules

All schedules are omitted because they are either not applicable or required information is shown in the financial statements or notes thereto.

3.   Exhibits

The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by reference as part of the annual report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHERN OIL AND GAS, INC.

Date:	March 16, 2009	By:	/s/ Michael Reger
			Michael Reger
			Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:

Signature	Title	Date
/s/ Michael L. Reger	Chief Executive Officer, Director and Secretary	March 16, 2009
Michael L. Reger
/s/ Ryan R. Gilbertson	Chief Financial Officer, Principal Financial Officer, Principal Accounting Officer, Director	March 16, 2009
Ryan R. Gilbertson
/s/ Loren J. O’Toole	Director	March 16, 2009
Loren J. O’Toole
/s/ Carter Stewart	Director	March 16, 2009
Carter Stewart
/s/ Jack King	Director	March 16, 2009
Jack King
/s/ Robert Grabb	Director	March 16, 2009
Robert Grabb
/s/ Lisa Bromiley Meier	Director	March 16, 2009
Lisa Bromiley Meier

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NORTHERN OIL AND GAS, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2008 and 2007	F-3
Statements of Operations for the Years Ended December 31, 2008, December 31, 2007 and From Inception on Oct 5, 2006 Through December 31, 2006	F-4
Statements of Stockholders’ Equity for the Years Ended December 31, 2008, December 31, 2007 and From Inception on Oct 5, 2006 Through December 31, 2006	F-5
Statements of Cash Flows for the Years Ended December 31, 2008, December 31, 2007 and From Inception on Oct 5, 2006 Through December 31, 2006	F-6
Notes to the Financial Statements	F-7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Northern Oil and Gas, Inc.:

We have audited the accompanying balance sheets of Northern Oil and Gas, Inc. (the Company) as of December 31, 2008 and 2007, and the related statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2009 expressed an unqualifed opinion.

Mantyla McReynolds LLC

Salt Lake City, Utah

March 16, 2009

F-2

NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
DECEMBER 31, 2008 AND 2007
ASSETS
	December 31,
	2008			2007
CURRENT ASSETS
Cash and Cash Equivalents	$	780,716		$	10,112,660
Trade Receivables		2,028,941			-
Other Receivable		874,453			-
Prepaid Drilling Costs		4,549			364,290
Prepaid Expenses		71,554			25,680
Deferred Tax Asset		1,433,000			-
Total Current Assets		5,193,213			10,502,630
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties, Full Cost Method (including unevaluated cost of
$42,621,297 at 12/31/2008 and $7,587,511 at 12/31/2007)		55,680,567			7,587,511
Other Property and Equipment		408,400			44,769
Total Property and Equipment		56,088,967			7,632,280
Less - Accumulated Depreciation and Depletion		856,010			3,446
Total Property and Equipment, Net		55,232,957			7,628,834
LONG-TERM INVESTMENTS		2,416,369			-
DEFERRED TAX ASSET		33,000			-
Total Assets	$	62,875,539		$	18,131,464
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable	$	1,934,810		$	113,254
Line of Credit		1,650,720			-
Accrued Expenses		1,270,075			110,993
Accrued Drilling Costs		8,419,729			-
Other Liabilities		135,731			-
Total Current Liabilities		13,411,065			224,247
LONG-TERM LIABILITIES		-			-
Total Liabilities		13,411,065			224,247
STOCKHOLDERS' EQUITY
Common Stock, Par Value $.001; 100,000,000 Authorized, 34,120,103
Outstanding (2007 – 28,695,922 Shares Outstanding)		34,121			28,696
Additional Paid-In Capital		51,692,776			22,259,921
Accumulated Deficit		(2,021,649	)		(4,381,400	)
Accumulated Other Comprehensive Income (Loss)		(240,774	)		-
Total Stockholders' Equity		49,464,474			17,907,217
Total Liabilities and Stockholders' Equity	$	62,875,539		$	18,131,464

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

F-3

NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2008, AND 2007 AND THE PERIOD
FROM INCEPTION (OCTOBER 5, 2006) THROUGH DECEMBER 31, 2006
							From
							Inception on
							October 5,
							2006
							Through
	Year Ended December 31,						December 31,
	2008			2007			2006
REVENUES
Oil and Gas Sales	$	3,542,994		$	-		$	-
Gain on Derivatives		778,885			-			-
Total Revenues		4,321,879			-			-
OPERATING EXPENSES
Production Expenses		70,954			-			-
Severance Taxes		203,182			-			-
General and Administrative Expense		2,091,289			4,509,743			76,374
Depletion of Oil and Gas Properties		785,504			-			-
Depreciation and Amortization		67,060			3,446			-
Accretion of Discount on Asset Retirement Obligations		1,030			-			-
Total Expenses		3,219,019			4,513,189			76,374
INCOME (LOSS) FROM OPERATIONS		1,102,860			(4,513,189	)		(76,374	)
OTHER INCOME		383,891			207,896			267
INCOME (LOSS) BEFORE INCOME TAXES		1,486,751			(4,305,293	)		(76,107	)
INCOME TAX PROVISION (BENEFIT)		(873,000	)		-			-
NET INCOME (LOSS)	$	2,359,751		$	(4,305,293	)	$	(76,107	)
Net Income (Loss) Per Common Share – Basic and Diluted	$	0.07		$	(0.18	)	$	(0.01	)
Weighted Average Shares Outstanding – Basic		31,920,747			23,667,119			18,000,000
Weighted Average Shares Outstanding - Diluted		32,653,552			23,667,119			18,000,000

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

F-4

NORTHERN OIL AND GAS, INC.
STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2008, AND 2007 AND THE PERIOD FROM INCEPTION (OCTOBER 5, 2006) THROUGH DECEMBER 31, 2006
													Accumulated
													Other						Total
							Additional			Stock			Comprehensive						Stockholders'
	Common Stock						Paid-In			Subscriptions			Income			Accumulated			Equity
	Shares			Amount			Capital			Receivable			(Loss)			Deficit			(Deficit)
Balance at Inception (October 5, 2006)		-		$	-		$	-		$	-		$	-		$	-		$	-
Common Stock Issued		18,000,000			1,800			-			(1,400	)		-			-			400
Compensation Related Stock Option Grants		-			-			38,575			-			-			-			38,575
Net Income (Loss)		-			-			-			-			-			(76,107	)		(76,107	)
Balance – December 31, 2006		18,000,000			1,800			38,575			(1,400	)		-			(76,107	)		(37,132	)
Payment on Stock Subscriptions Receivable		-			-			-			1,400			-			-			1,400
Sale of 2,501,573 Common Shares for $1.05 Per Share		2,501,573			250			2,626,402			-			-			-			2,626,652
Private Placement Costs		-			-			(9,933	)		-			-			-			(9,933	)
Issued 400,000 Common Shares to Montana Oil and
Gas, Inc. for Leasehold Interest		400,000			40			419,960			-			-			-			420,000
Issued 271,440 Shares to Southfork Exploration, LLC
for Leasehold Interest		271,440			27			284,985			-			-			-			285,012
Balance Immediately Prior to Reverse Acquisition
with Kentex		21,173,013			2,117			3,359,989			-			-			(76,107	)		3,285,999
Reverse Acquisition with Kentex:
Recapitalization of NOG with Kentex Common
Stock Issued in the Acquisition (Par Value
Changed to $.001 Per Share)		-			19,056			(19,056	)		-			-			-			-
Acquisition of Kentex		1,491,110			1,491			(1,491	)		-			-			-			-
Legal Fees		-			-			(25,000	)		-			-			-			(25,000	)
Introduction Fee		-			-			(12,500	)		-			-			-			(12,500	)
Payment to Kentex Stockholders		-			-			(377,500	)		-			-			-			(377,500	)
Other Professional Fees		-			-			(36,062	)		-			-			-			(36,062	)
Totals of Reverse Acquisition		1,491,110			20,547			(471,609	)		-			-			-			(451,062	)
Balance Immediately After Reverse Acquisition
with Kentex		22,664,123			22,664			2,888,380			-			-			(76,107	)		2,834,937
Shares Issued Pursuant to Consulting Agreements		73,500			74			380,656			-			-			-			380,730
Issued 100,000 Shares to Insight Capital Consultants		100,000			100			474,900			-			-			-			475,000
Compensation Related Stock Option Grants		-			-			2,366,417			-			-			-			2,366,417
Sale of 4,545,455 Common Shares for $3.30 Per Share		4,545,455			4,545			14,995,457			-			-			-			15,000,002
(unit placement)
Private Placement Costs net of Warrants Granted to Agent		-			-			(1,191,000	)		-			-			-			(1,191,000	)
Issued 115,000 Common Shares to Montana Oil and
Gas Properties, LLC for Leasehold Interest		115,000			115			577,185			-			-			-			577,300
Issued 275,000 Common Shares to Gallatin
Resources, LLC for Leasehold Interest		275,000			275			1,380,225			-			-			-			1,380,500
Issued 75,000 Shares as Compensation		75,000			75			388,425			-			-			-			388,500
Repurchase of 152,156 Common Shares		(152,156	)		(152	)		(1,049,724	)		-			-			-			(1,049,876	)
Issued Pursuant to Exercise of Options		1,000,000			1,000			1,049,000			-			-			-			1,050,000
Net Income (Loss)		-			-			-			-			-			(4,305,293	)		(4,305,293	)
Balance – December 31, 2007		28,695,922		$	28,696		$	22,259,921		$	-		$	-		$	(4,381,400	)	$	17,907,217
Issued 7,500 Shares to Roepke Communications for services		7,500			8			49,867			-			-			-			49,875
Issued 215,381 Common Shares to Montana Oil and
Gas Properties, LLC for Leasehold Interest		215,381			215			1,165,077			-			-			-			1,165,292
Issued 20,000 Common Shares of Restricted Stock for employee services		20,000			20			(20	)		-			-			-			-
Listing Fee Paid to American Stock Exchange		-			-			(65,000	)		-			-			-			(65,000	)
Issued Pursuant to Exercise of Options		260,000			260			933,540			-			-			-			933,800
Issued Pursuant to Exercise of Warrants		4,818,186			4,818			25,977,244			-			-			-			25,982,062
Warrant Exercise Costs		-			-			(77,204	)		-			-			-			(77,204	)
Stock Grant Compensation		-			-			105,375			-			-			-			105,375
Issued 7,675 Common Shares to Missouri River Royalty
Corp. for Leasehold Interest		14,747			15			146,876			-			-			-			146,891
Issued 67,500 Common Shares to Deephaven
for Leasehold Interest		67,500			68			557,145			-			-			-			557,213
Issued 15,902 Common Shares to Twin City
Technical, LLC for Leasehold Interest		15,902			16			167,315			-			-			-			167,331
Issued 4,465 Common Shares to TurmOil, Inc
for Leasehold Interest		4,465			4			46,491.00			-			-			-			46,495
Issued 500 Common Shares to David Bickerstaff
for Leasehold Interest		500			1			1,149			-			-			-			1,150
Unrealized Losses on Auction Rate Securities		-			-			-			-			(240,774	)		-			(240,774	)
Income Tax Benefit from Options Exercised								425,000												425,000
Net Income (Loss)		-			-			-			-			-			2,359,751			2,359,751
Balance – December 31, 2008		34,120,103		$	34,121		$	51,692,776		$	-		$	(240,774	)	$	(2,021,649	)	$	49,464,474

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

F-5

NORTHERN OIL AND GAS, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2008 AND 2007 AND THE PERIOD
FROM INCEPTION (OCTOBER 5, 2006) THROUGH DECEMBER 31, 2006
							From
							Inception on
							October 5,
							2006
							Through
	Year Ended December 31,						December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	2,359,751		$	(4,305,293	)	$	(76,107	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by
(Used for) Operating Activities
Depletion of Oil and Gas Properties		785,504			-			-
Depreciation and Amortization		67,060			3,446			-
Accretion of Discount on Asset Retirement Obligations		1,030			-			-
Income Tax Benefit		(873,000	)		-			-
Issuance of Stock for Consulting Fees		49,875			855,730			-
Loss on Sale of Available for Sale Securities		381			-			-
Issuance of Stock for Compensation		-			388,500			-
Market Value Adjustment of Derivative Instruments		(95,148	)		-			-
Lease Incentives Received		91,320			-			-
Amortization of Deferred Rent		(17,026	)		-			-
Share – Based Compensation Expense		105,375			2,366,417			38,575
Changes in Working Capital and Other Items:
Increase in Trade Receivables		(2,028,941	)		-			-
Increase in Other Receivables		(874,453	)		-			-
Increase in Prepaid Expenses		(45,874	)		(24,556	)		(1,000	)
Increase in Accounts Payable		1,821,556			113,254			-
Increase in Accrued Expenses		1,159,082			110,993			-
Net Cash Provided by (Used For) Operating Activities		2,506,492			(491,509	)		(38,532	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Office Equipment and Furniture		(363,631	)		(44,769	)		-
Decrease (Increase) in Prepaid Drilling Costs		359,741			(364,290	)		-
Proceeds from Sale of Oil and Gas Properties		468,609			-			-
Increase in Accrued Drilling Costs		8,419,729			-			-
Deposits		-			-			(255,000	)
Purchase of Available for Sale Securities		(3,800,524	)		-			-
Proceeds from sale of Available for Sale Securities		975,000			-			-
Increase in Oil and Gas Properties		(46,416,886	)		(4,669,699	)		-
Net Cash Used For Investing Activities		(40,357,962	)		(5,078,758	)		(255,000	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Line of Credit		1,650,720			-
Proceeds from (Repayments of) Convertible Notes Payable (Related Party)		-			(165,000	)		365,000
Cash Paid for Listing Fee		(65,000	)		-			-
Proceeds from Derivatives		95,148			-			-
Proceeds from Investor Subscriptions - Net of Issuance Costs		-			-			778,067
Proceeds from the Issuance of Common Stock – Net of Issuance Costs		25,904,858			14,997,992			400
Proceeds from Exercise of Stock Options		933,800			-			-
Net Cash Provided by Financing Activities		28,519,526			14,832,992			1,143,467
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(9,331,944	)		9,262,725			849,935
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		10,112,660			849,935			-
CASH AND CASH EQUIVALENTS – END OF PERIOD	$	780,716		$	10,112,660		$	849,935
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	27,485		$	-		$	-
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	$	2,084,372		$	2,662,812		$	-
Payment of Consulting Fees through Issuance of Common Stock	$	49,875		$	855,730		$	-
Payment of  Compensation through Issuance of Common Stock	$	-		$	388,500		$	-
Cashless Exercise of Stock Options	$	-		$	1,050,000		$	-
Capitalized Asset Retirement Obligations	$	60,407		$	-		$	-

The accompanying notes are an integral part of these financial statements

F-6

NORTHERN OIL AND GAS, INC

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 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 46 gross oil wells completed in 2008 has given us valuable data on completions and will help to control well costs and enhance results as we begin to develop our high working interest sections in mid-2009.

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

Our land acquisition and field operations, along with various other services, are primarily outsourced through the use of consultants and drilling partners.  The Company will continue to retain independent contractors to assist in operating and managing the prospects as well as to carry out the principal and necessary functions incidental to the oil and gas business.  With the additional acquisition of oil and natural gas properties, the Company intends to continue to use both in-house employees and outside consultants to develop and exploit its leasehold interests.

As an independent oil and gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent on prevailing prices of natural gas and oil.  Historically, the energy markets have been very volatile and it is likely that oil and gas prices will continue to be subject to wide fluctuations in the future.  A substantial or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital, and on the quantities of natural gas and oil reserves that can be economically produced. As of December 31, 2008 the substantial decline in oil prices has not affected the Company’s financial position in a material amount.  

F-7

NOTE 2                 SIGNIFICANT ACCOUNTING PRACTICES

These financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

Cash, Cash Equivalents, and Long-Term Investments

The Company considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents.  Cash equivalents consist primarily of interest-bearing bank accounts and money market funds.  Our cash positions represent assets held in checking and money market accounts.  These assets are generally available to us on a daily or weekly basis and are highly liquid in nature.  Due to the balances being greater than $250,000, we do not have FDIC coverage on the entire amount of bank deposits.  The company believes this risk is minimal.  In addition, we are subject to SIPC protection on a vast majority of our financial assets, specifically $657,363 of cash and cash equivalents and all of our long-term investments.

Other Property and Equipment

Property and equipment that are not oil and gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to five years.  Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  We have not recognized any impairment losses on non oil and gas long-lived assets.  Depreciation expense was $67,070 for the year ended December 31, 2008.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Revenue Recognition and Gas Balancing

We recognize oil and gas revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable.  We use the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation.  As of December 31, 2008 and 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.

F-8

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment.”  This statement requires us to record an expense associated with the fair value of stock-based compensation.  We currently use the Black-Scholes option valuation model to calculate stock based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.

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

Options Granted December 15, 2006

For the options granted in 2006 we used a basket of comparable companies to determine the volatility input.  We believe this fairly represents the volatility we may trade on were we a public company at the time of issuance.  The total fair value of the options was recognized as compensation over the one-year vesting period.  All of the options granted in 2006 have been exercised as of December 31, 2008.

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

	December 31,
	2006
Risk Free Rates	4.75%
Dividend Yield	0%
Expected Volatility	64%
Weighted Average Expected Stock Option Life	10 Years

F-9

The weighted average fair value at the date of grant for stock options granted is as follows:

Weighted Average Fair Value Per Share	$	.80
Total options granted		1,100,000
Total Weighted Average Fair Value of Options Granted	$	880,000

Income Taxes

The Company accounts for income taxes under FASB Statement No. 109, “Accounting for Income Taxes.”  Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  SFAS 109 requires the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

Stock Issuance

The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered on the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in EITF No. 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring or in Conjunction with Selling, Goods, or Services.”

Net Income (Loss) Per Common Share

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

Diluted earnings per share are computed using weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method.  As the Company has a loss for the period ended December 31, 2007 the potentially dilutive shares are anti-dilutive and are thus not added into the earnings per share calculation.

Full Cost Method

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”).  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities.  Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities.  Costs associated with production and general corporate activities are expensed in the period incurred.

As of December 31, 2008 we controlled approximately 22,000 net acres of leaseholds in Sheridan County, Montana with primary targets including the Red River and Mission Canyon. We controlled approximately 70,000 net acres in North Dakota, primarily in Mountrail County, targeting the Bakken Shale and approximately 10,000 net acres in Yates County, New York that is prospective for Marcellus Shale and Trenton-Black River natural gas production.  See Note 5 for an explanation of activities on these properties.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.  In the year ended December 31, 2008 the Company sold acreage for $468,609.  The proceeds for these sales were applied to reduce the capitalized costs of oil and gas properties.

Capitalized costs associated with impaired properties and capitalized cost related to properties having proved reserves, plus the estimated future development costs, asset retirement costs under Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (SFAS 143) are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers.  The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

F-10

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 December 31, 2008.  Therefore, the Company was not required to writedown the net capitalized costs of its oil and gas properties at December 31, 2008.  To this point the company has not realized any impairment of its properties due to our low basis in the acreage and productivity and economics of our producing wells, even in the current lower price environment. 

Use of Estimates

The preparation of financial statements under generally accepted accounting principles (“GAAP”) in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  The most significant estimates relate to proved oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, and deferred income taxes.  Actual results may differ from those estimates.

Derivative Instruments and Price Risk Management

The Company uses derivative instruments from time to time to manage market risks resulting from fluctuations in the prices of oil and natural gas.  The Company may periodically enter into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.  The notional amounts of these financial instruments would be based on expected production from existing wells.  The Company has, and 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 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.

F-11

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 14 for a description of the derivative contracts which the Company executed during 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.

New Accounting Pronouncements

In December 2007, the FASB issued Statement of Financial and Accounting Standards (“SFAS”) No. 141(R), “Business Combinations.”  SFAS 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 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 SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.”  SFAS 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity's financial position, financial performance, and cash flows.  SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  We do not anticipate a material impact upon adoption.

F-12

In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements.”  SFAS 157 defines fair value, establishes a framework for measuring fair value, and expends 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 input 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     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 December 31, 2008:

	Cost at December 31, 2008		Unrealized (Loss)			Fair Market Value at December 31, 2008
Auction Rate Municipal Bonds	$	2,550,000	$	(395,250	)	$	2,154,750
Auction Rate Preferred Stock		275,143		(13,524	)		261,618
Total Long-Term Investments	$	2,825,143	$	(408,774	)	$	2,416,369

For the year ended December 31, 2008 there were minimal gains or losses recognized on the sale of investments.  In November 2008 we received, in a settlement from UBS AG (“UBS”), rights which allow us to put back the auction rate securities at par value to UBS.  We expect to liquidate these investments at par no later than June 2010, in the meantime they continue to pay interest at various rates.  We also have the ability to borrow up to 75% of the loan-to-market value of eligible auction rate securities on a no-net cost basis.  As of December 31, 2008, we have borrowed $1,650,720 under the agreement, with an additional $468,030 of borrowings available under the agreement. 

The Company reviews these investments on a quarterly basis to determine if it is probable that the Company will realize some portion of the unrealized loss in accordance with SFAS No. 115, and FSP No. FAS 115-1 and FAS 124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” and to determine the classification of the impairment as temporary or other-than-temporary.   In determining if the difference between cost and estimated fair value of the auction rate securities was deemed either temporary or other-than-temporary impairment, the Company evaluated each type of long-term investment using a set of criteria including decline in value, duration of the decline, period until anticipated recovery, nature of investment, probability of recovery, financial condition and near-term prospects of the issuer, the Company’s intent and ability to retain the investment, attributes of the decline in value, status with rating agencies, status of principal and interest payments and any other issues related to the underlying securities. The Company determined the decline in the fair values in all of the investments in the auction rate securities were temporary as of December 31, 2008, primarily based on estimated cash flows of the investments, the settlement agreement entered into with UBS, and the Company’s ability and intent to hold such investments until settlement.

F-13

NOTE 4     PROPERTY AND EQUIPMENT

Property and equipment at December 31, 2008 and 2007, consisted of the following:

	December 31,
	2008		2007
Oil and Gas Properties, Full Cost Method
Unevaluated Costs, Not Subject to Amortization or Ceiling Test	$	42,621,297	$	7,587,511
Evaluated Costs		13,059,270		-
		55,680,567		7,587,511
Office Equipment, Furniture, Leasehold Improvements and Software		408,400		44,769
		56,088,967		7,632,280
Less:  Accumulated Depreciation, Depletion, and Amortization
Property and Equipment		856,010		3,446
Total	$	55,232,957	$	7,628,834

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

	Year Ended December 31,
	2008			2007
Depletion of Costs for Evaluated Oil and Gas Properties		$	785,504			-
Depreciation of Office Equipment, Furniture, and Software			67,060			3,446
Total Depreciation, Depletion, and Amortization Expense		$	852,564		$	3,446

NOTE 5                 OIL AND GAS PROPERTIES

Acquisitions

Montana Acquisition

In February 2007, the Company acquired leasehold interests in approximately 22,000 net mineral acres in Sheridan County, Montana.  The Company paid a combination of cash and stock as consideration for such acquisition, including the issuance of an aggregate of 400,000 restricted shares of its common stock.

North Dakota Acquisitions

At various points in late 2007 and throughout 2008, the Company acquired leasehold interests in approximately 21,498 net mineral acres of land via bulk purchases in the core development area of Mountrail County, North Dakota.  The Company paid a combination of cash and stock as consideration for such acquisitions, including the issuance of an aggregate of 633,027 restricted shares of its common stock.  In addition to these major acquisitions the Company completed a series of small transactions pursuant to which it purchased leasehold interests in approximately 8,000 net mineral acres in Mountrail County.

On June 11, 2008, the Company entered into a purchase agreement pursuant to which it ultimately acquired leasehold interests in approximately 23,210 net mineral acres primarily in Dunn County, North Dakota.  The Company also completed various additional acquisitions of oil and gas leasehold interests through numerous small transactions with several parties in fiscal years 2007 and 2008.

At various points in 2007 and 2008, the Company purchased leasehold interests in approximately 10,000 net mineral acres in and around Burke and Divide Counties of North Dakota for cash consideration.

The Company has also completed other miscellaneous non-material acquisitions in North Dakota, and utilized a combination of stock and cash consideration for some of the acquisitions.

F-14

New York Acquisition

In September 2007, the Company acquired leasehold interests in approximately 10,000 net mineral acres in the Appalachia Basin of New York.  The Company paid a combination of cash and stock as consideration for such acquisition, including the issuance of an aggregate of 275,000 restricted shares of its common stock.

Certain of the foregoing acquisitions were purchased using the services of, or purchased from, parties considered to be related to the Company or the Company’s Chief Executive Officer, Michael L. Reger.  See Note 7.  All transactions involving related parties were approved by the Company’s Board of Directors or Audit Committee and the Company obtained independent verification of the fairness of consideration paid in each transaction.

NOTE 6                 PREFERRED AND COMMON STOCK

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

In October 2006, the Company began a private placement offering of a maximum of 4,000,000 shares for sale for $1.05 (the “Offering”).  A minimum of 2,000,000 shares was needed to close on the Offering.  The Offering was a private placement made under Rule 506 promulgated under the Securities Act of 1933 (the “Act”), as amended.  The securities offered and sold (or deemed to be offered and sold, in the case of underlying shares of common stock) in the Offering have been registered for resale under the Act as of October 10, 2007.  On February 1, 2007, the Offering closed with $2,626,652 being raised and 2,501,573 common shares being issued.

On May 3, 2007, the Company issued 100,000 shares of common stock to Insight Capital Consultants Corporation pursuant to a consulting agreement with them.  The stock issued was valued at $475,000 and expensed to general and administrative expense.  The shares were valued based on the market price of the Company’s stock on the date of issuance.

F-15

In September 2007, the Company completed a private placement of 4,545,455 shares of common stock to accredited investors at a subscription price of $3.30 per share for total gross proceeds of $15,000,002.  In addition to common stock, investors purchasing shares in the private placement received a warrant to purchase common stock.  For each share of common stock purchased in this transaction, the purchaser received the right to purchase one-half share of the Company’s common stock at a price of $5.00 per share for a period of 18 months from the date of closing and the right to purchase one-half share of the Company’s common stock at a price of $6.00 for a period of 48 months from the date of closing.  FIG Partners, LLC Energy Research and Capital Partners served as the exclusive placement agent for which it received consideration in cash and warrants.  The total number of shares that are issuable upon exercise of warrants, including the placement agent's warrant is 4,818,183.  All warrants issued as part of this private placement were exercised in 2008.  In addition, four of our founders executed restriction agreements under which they agree not to sell shares of beneficial interest in the Company for a period of 18 months from the closing of this private placement, except under certain limited circumstances.  Approximately 13,289,000 shares of common stock are subject to the lock-up agreement.

In November 2007, the Company issued 73,500 shares of common stock to various consultants pursuant to consulting agreements.  The company also issued 75,000 shares of common stock to employee Chad Winter pursuant to a written employment agreement.  These 148,500 shares were valued at $769,230 at the time of issuance and expensed as general and administrative expenses.  The shares were valued at the calculated fair value of the Company’s stock on the date of the issuance.

In December 2007, Mike Reger and Ryan Gilbertson each exercised 500,000 stock options granted to them in 2006.

In 2008 optionees exercised 260,000 stock options granted in 2006 and 2007, resulting in cash proceeds to the Company of $933,800.  A tax benefit of $425,000 related to fully vested stock option awards exercised was recorded as an increase to additional paid-in capital

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 $105,375 related to this award in the year ended December 31, 2008.  Vesting of the shares is contingent on the employee maintaining employment with the Company and other restrictions included in the employment agreement.

NOTE 7                 RELATED PARTY TRANSACTIONS

The Company has purchased leasehold interests from South Fork Exploration, LLC (SFE).  SFE’s president is J.R. Reger, the brother of the Company’s CEO, Michael Reger.  J.R. Reger is also a shareholder in the Company.  See Note 5.

The Company has also purchased leasehold interests from MOP.  MOP is controlled by Mr. Tom Ryan and Mr. Steven Reger, both are relatives of the Company’s CEO, Michael Reger.  See Note 5.

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

All transactions involving related parties were approved by the Company’s Board of Directors or Audit Committee and the Company obtained independent verification of the fairness of consideration paid in each transaction.

F-16

NOTE 8     STOCK OPTIONS/STOCK-BASED COMPENSATION

The Company’s Board of Directors approved a stock option plan in October 2006 (“2006 Stock Option Plan”) to provide incentives to employees, directors, officers, and consultants and under which 2,000,000 shares of common stock have been reserved for issuance.  The options can be either incentive stock options or non-statutory stock options and are valued at the fair market value of the stock on the date of grant.  The exercise price of incentive stock options may not be less than 100% of the fair market value of the stock subject to the option on the date of the grant and, in some cases, may not be less than 110% of such fair market value.  The exercise price of non-statutory options may not be less than 100% of the fair market value of the stock on the date of grant.  On December 15, 2006, 1,100,000 options were granted at a price of $1.05 per share.  500,000 options were granted to each Michael Reger and Ryan Gilbertson, and 100,000 options were granted to Douglas Polinsky.  As stated above, these options have an exercise price of $1.05 per share.  These options became fully vested on December 15, 2007.  All options granted in 2006 have been exercised as of December 31, 2008.

On November 1, 2007 the Board of Directors granted an additional 560,000 of options under this 2006 Stock Option Plan.  The Company granted 500,000 options in aggregate, to members of the board and 60,000 options to one employee pursuant to an employment agreement.  These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date.  160,000 options granted in 2007 have been exercised as of December 31, 2008.

The Company accounts for stock-based compensation under the provisions of SFAS No. 123(R), “Share Based Payment.”  This statement requires us to record an expense associated with the fair value of stock-based compensation.  We currently use the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.  The total fair value of the options will be recognized as compensation over the vesting period (see Note 2 for calculation of fair value).  The Company received no cash consideration for these option grants.  There have been no stock options granted in 2008 under the 2006 Stock Option Plan, and all exercises of options during 2008 related to prior period grants.

The following table presents the impact on our statement of operations of stock-based compensation expense for the years ended December 31, 2008 and 2007:

	Year Ended December 31,
	2008		2007
Expenses	$	-		2,366,417
Stock-Based Compensation Expense Before Taxes		-		2,366,417
Income tax benefit		-		-
Stock-Based Compensation Expense After Taxes	$	-	$	2,366,417

Changes in stock options for the years ended December 31, 2008 and 2007 were as follows:

2007:	Number Of Shares		Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Beginning Balance		1,100,000	$	-
Granted		560,000		5.18				-
Exercised		1,000,000		1.05				-
Outstanding at December 31		660,000		4.55		9.7		1,581,200
Exercisable		660,000		4.55		9.7		1,581,200
Ending Vested		660,000		4.55				1,581,200
Weighted average fair value of  options granted during year			$	2.72

F-17

2008:
Beginning Balance	660,000	$	-		-
Granted	-		-		-
Exercised	260,000		3.59		-
Outstanding at December 31	400,000		5.18	8.8	-
Exercisable	400,000		5.18	8.8	-
Ending vested	400,000		5.18	8.8	-
Weighted average fair value of  options granted during year		$	-

Currently Outstanding Options

·   No options were forfeited during the years ended December 31, 2008 and 2007.

·   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 all options that have been granted as of December 31, 2008, since the entire fair value compensation has been recognized during 2006 and 2007.

NOTE 9                 ASSET RETIREMENT OBLIGATION

The company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities.  Under the provisions of SFAS 143, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

The company has no assets that are legally restricted for purposes of settling asset retirement obligations.  The following table summarizes the company's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the year ended December 31, 2008.

Beginning Asset Retirement Obligation	$	-
Liabilities Incurred for New Wells Placed in Production		60,407
Accretion of Discount on Asset Retirement Obligations		1,030
Ending Asset Retirement Obligation	$	61,437

NOTE 10                      INCOME TAXES

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with SFAS No. 109, “Accounting for Income Taxes”.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

F-18

The components of the benefit for income taxes are:

								For the Period from Inception (October 5, 2006) through
		Years Ended December 31,						December 31, 2006
	2008				2007
Current Income Taxes		$	-			$	-		$	-
Deferred Income Taxes
Federal			(715,000	)			-			-
State			(158,000	)			-			-
Total Benefit		$	(873,000	)		$	-		$	-

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2008 and 2007 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.

Reconciliation of reported amount of income tax expense:

	2008			2007			2006
Income (Loss) Before Taxes and NOL		1,486,751		$	(4,305,293	)	$	(76,107	)
Federal Statutory Rate		x 34	%		x 34	%		x25	%
Taxes (Benefit) Computed at Federal Statutory Rate		505,000			(1,460,000	)		(19,027	)
State Taxes (Benefit), Net of Federal Taxes		104,000			-			-
Effects of:
Permanent and Other Differences		(2,000	)		(12,341	)		11,368
Increase (Decrease) in Valuation		(1,480,000	)		1,472,341			7,659
Reported Provision (Benefit)		(873,000	)	$	-		$	-

At December 31, 2008 and 2007, the Company has a net operating loss carryforward for Federal income tax purposes of $8,726,000 and $1,950,000, respectively, which expires in varying amounts during the tax years 2027 and 2028.

The components of the Company’s deferred tax assets and liabilities are as follows:

	December 31,
	2008		2007
Deferred Tax Assets
Current:
Share Based Compensation	$	774,000	$	815,000
Unrealized Investment Losses		168,000		-
Accrued Payroll		520,000		-
Current		1,462,000		815,000
Non-Current
Net Operating Loss Carryforwards (NOLs)		3,588,000		665,000
Depletion		257,000		-
Sale of Land Lease Rights		117,000		-
Non-Current		3,962,000		665,000
Total  Deferred Tax Assets		5,424,000		1,480,000
Less: Valuation Allowance		-		(1,480,000	)
Net Deferred Tax Asset	$	5,424,000	$	-

F-19

Deferred Tax Liabilities
Current:
Other	$	(29,000	)	$	-
Current		(29,000	)		-
Non-Current
Fixed Assets		(931,000	)		-
Dry Well Write Off		(36,000	)		-
Intangible Drilling Costs		(2,962,000	)		-
Non-Current		(3,929,000	)		-
Net Deferred Tax Liability		(3,958,000	)		-
Total Deferred Tax Asset (Liability)	$	1,466,000		$	-
Deferred Tax Assets (Liability)
Current Portion	$	1,433,000		$	-
Long-Term Portion	$	33,000		$	-

A valuation allowance is provided when it is more likely than not that all or some portion of the deferred tax assets will not be realized.  At December 31, 2007, a valuation allowance was maintained on the Company’s deferred tax assets since they were not more likely than not to be realized.  This assessment was made based on historical activity and the results of operations as of December 31, 2007.  In 2008, using objective and verifiable data, which became available during the fourth quarter, the Company calculated that it will utilize the existing deferred tax assets.  As a result, the Company has determined that a valuation allowance is no longer necessary for its deferred tax assets and the valuation allowance was released as of December 31, 2008.

In June 2006, the FASB issued Interpretation No. 48 “Accounting for Uncertainty in Income Taxes, and Interpretation of FASB Statement No. 109” (FIN 48).  We adopted FIN 48 on January 1, 2007.  Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement.  Unrecognized tax benefits are tax benefits claimed in our tax returns that do not meet these recognition and measurement standards.

Upon the adoption of FIN 48, we had no liabilities for unrecognized tax benefits and, as such, the adoption had no impact on our financial statements, and we have recorded no additional interest or penalties.  The adoption of FIN 48 did not impact our effective tax rates.

Our policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense.  For the year ended December 31, 2008 and 2007, we did not recognize any interest or penalties in our Statement of Operations, nor did we have any interest or penalties accrued in our Balance Sheet at December 31, 2008 and 2007 relating to unrecognized benefits.

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

NOTE 11 OPERATING LEASES

Vehicles

The Company leases vehicles under noncancelable operating leases.  Total rent expense under the agreements was approximately $31,000 and $22,000 for the years ended December 31, 2008 and 2007, respectively.

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Minimum future lease payments under these vehicle leases are as follows:

Year Ending December 31,	Amount
2009	$	52,000
2010		41,000
2011		20,000
Total	$	113,000

Building

Effective February 2008, the Company entered into an operating lease agreement to lease 3,044 square feet of office space.  The lease requires initial gross monthly lease payments of $11,415.  The monthly payments increase by 4% on each anniversary date.  The lease expires in December 2012.  Total rent expense under the agreement was approximately $114,000 for the year ended December 31, 2008.

The Company was required to prepay $68,490, the first six months rent.  Minimum future lease payments under the building lease are as follows:

Year Ending December 31,	Amount
2009	$	142,459
2010		148,151
2011		154,087
2012		160,236
Total	$	604,933

The Company received $91,320 of landlord incentives under the lease agreement.  The Company has recorded a deferred rent liability for this amount that is being amortized over the term of the lease.

Prior to this lease the Company was paying $1,250 on a month-to-month lease.

NOTE 12   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 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.

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The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of December 31, 2008.  

	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Long-Term Investments (See Note 3)	$	-	$	-	$	2,416,369

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

In February 2008, auctions began to fail for these securities and each auction since then has failed.  Consequently, the investments are not currently liquid.  In the event the Company needed to access these funds, they are not expected to be accessible until one of the following occurs: a successful auction occurs, the issuer redeems the issue, a buyer is found outside of the auction process or the underlying securities mature.  In October 2008, the Company received an offer (the “Offer”) from UBS AG (“UBS”), one of its investment providers, to sell at par value auction-rate securities originally purchased from UBS ($2,825,143) at anytime during a two-year period beginning June 30, 2010.  The Offer was non-transferable and expired on November 14, 2008. On October 28, 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 December 31, 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 December 31, 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 $2,416,369, which represents a decline in value of $408,774 from par.

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

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Based on the cash balance of $780,716, 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
Sales/Maturities		(725,000)
Realized Loss on Sales/Maturities		(381)
Unrealized Loss Included in Other Comprehensive Income (Loss)		(179,225)
Balance at December 31, 2008	$	2,416,369

NOTE 13                      FINANCIAL INSTRUMENTS

The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and line of credit. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and line of credit approximate fair value because of their immediate or short-term maturities.

The Company’s accounts receivable relate to oil and natural gas sold to various industry companies.  Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral.  The Company’s accounts receivable at December 31, 2008 and 2007 do not represent significant credit risks as they are dispersed across many counterparties.

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NOTE 14                      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.

Crude Oil Derivative Contracts Cash-flow Hedges

The Company's cash-flow hedges consisted of crude oil futures contracts.  The Company hedged 20,000 barrels of production thru the end of 2008 at approximately $105 per barrel of oil.  The contracts were used to establish floor prices on anticipated future oil production. There were no net premiums received or paid when the Company entered into these contracts.  At settlement any realized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the statement of operations.

All cash flow hedges were settled during 2008 and the Company reported a gain on derivatives of $778,885 in revenues.  As of the end of 2008, no production has been hedged into 2009 or beyond, although it is expected that the Company will continue to enter into hedges concerning anticipated future oil production.

Crude Oil Derivative Contracts Investment Vehicles

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 these nondesignated derivative contracts.  Future contracts settled and expiration of written call options were recorded as other income, for the years ended December 31, 2007 and 2008:

		Year Ended December 31,
	2008		2007
Increase in earnings due to settlement or expiration of derivatives entered into as investment vehicles	$	123,536	-

There are no investment vehicle positions held as of December 31, 2007 and 2008.

NOTE 15                      EARNINGS PER SHARE

The following is a reconciliation of the numerator and denominator used to calculate basic earnings per share and diluted earnings per share for the years ended December 31, 2008, 2007, and 2006:

	2008			2007				2006
	Net  Income	Shares	Per Share	Net Loss	Shares	Per Share	Net Loss		Shares	Per Share
Basic EPS	$ 2,359,751	31,920,747	$      0.07	$ (4,305,293)	23,667,119	$(0.18)	$    (76,107)		18,000,000	$(0.01)
Dilutive effect of options	-	732,805		-	-		-		-
Diluted EPS	$ 2,359,751	32,653,552	$      0.07	$ (4,305,293)	23,667,119	$(0.18)	$    (76,107)		18,000,000	$(0.01)

For the year ended December 31, 2008, options to purchase 7,476 shares of common stock were not considered in calculating diluted earnings per share because the exercise prices were greater than the average market price of common shares during the year and, therefore, the effect would be anti-dilutive.

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NOTE 16   COMPREHENSIVE INCOME

The Company follows the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income.  In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to stockholders of the Company.

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

							For the Period from Inception (October 5, 2006) through
	Years Ended December 31,						December 31, 2006
	2008			2007
Net Income (Loss)	$	2,359,751		$	(4,305,293	)		$	(76,107	)
Unrealized Losses on Marketable Securities  (net of tax of $168,000)		(240,774	)		-				-
Comprehensive Income (Loss) Net	$	2,118,977		$	(4,305,293	)		$	(76,107	)

NOTE 17                      QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Quarterly data for the years ended December 31, 2008 and 2007 is as follows:

	Quarter Ended
	March 31,			June 30,			September 30,					December 31,
2008:
Revenue	$	287,029		$	764,528				$	1,362,655		$	1,907,667
Expenses		570,575			576,487					645,957			1,426,000
Income (Loss) from Operations		(283,546	)		188,041					716,698			481,667
Other Income		96,269			95,424					155,121			37,077
Income Tax Provision (Benefit)		-			-					-			(873,000	)
Net Income (Loss)		(187,277	)		283,465					871,819			1,391,744
Net Income (Loss) Per Common Share - Basic and Diluted		(0.01	)		0.01					0.03			0.04
2007:
Revenue	$	-		$	-				$	-		$	-
Expenses		297,719			894,720			*		309,487			3,011,263
Loss from Operations		(297,719	)		(894,720	)		*		(309,487	)		(3,011,263	)
Other Income		10,133			13,660					42,189			141,914
Income Tax Expense		-			-					-			-
Net Loss		(287,586	)		(881,060	)		*		(267,298	)		(2,869,349	)
Net Loss Per Common Share - Basic and Diluted		(0.01	)		(0.04	)		*		(0.01	)		(0.10	)

* The second quarter 2007 financial statements were adjusted, from what was reported, as the company rescinded stock it had previously issued to Ibis Consulting Group, LLC.

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NOTE 18                      SUBSEQUENT EVENTS

On February 27, 2009, the company entered into a revolving credit facility with CIT Capital USA, Inc. (CIT) that will provide up to a maximum principal amount of $25 million of working capital for exploration and production operations.  The borrowing base of funds available under the Facility will be redetermined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from its interests in proved reserves estimated to be produced from its oil and gas properties.  $11 million of financing is initially available under the Facility.  An additional $14 million of financing could become available upon subsequent borrowing base redeterminations based on the deployment of funds from the Facility.  The Facility is subject to certain covenants and contains a floating interest rate.  The Facility terminates on February 27, 2012.

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INDEX TO EXHIBITS

Exhibit No.	Description	Reference
2.1	Agreement and Plan of Merger dated March 20, 2007, with exhibits	Incorporated by reference to Exhibit 2 to the Current Report on Form 8-K12G3 filed with the Securities and Exchange Commission on March 22, 2007 (File No. 000-30955).
2.2	Written Action of the Board of Directors of Kentex Petroleum, Inc., constituting the plan and agreement of short-form merger with Northern Oil and Gas, Inc., dated March 20, 2007	Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form SB-2 filed with the Securities and Exchange Commission on June 11, 2007, as amended, File No. 333-143648
3.1	Articles of Incorporation of Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on July 6, 2000 (File No. 000-30955).
3.2	Certificate of Amendment of the Articles of Incorporation of Northern Oil and Gas, Inc. dated March 27, 1984	Incorporated by reference to Exhibit 3.3(i) to the Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on July 6, 2000 (File No. 000-30955).
3.3	Certificate of Amendment of the Articles of Incorporation of Northern Oil and Gas, Inc. dated October 5, 1999	Incorporated by reference to Exhibit 3.3(ii) to the Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on July 6, 2000 (File No. 000-30955).
3.4	Written Action of the Board of Directors of Kentex Petroleum, Inc. authorizing name change to Northern Oil and Gas, Inc., dated March 20, 2007	Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form SB-2 filed with the Securities and Exchange Commission on June 11, 2007, as amended, File No. 333-143648.
3.5	Amended and Restated Bylaws of Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 99.2 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2007 (File No. 000-30955).
4.1	Specimen Stock Certificate of Northern Oil and Gas, Inc.	Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form SB-2 filed with the Securities and Exchange Commission on June 11, 2007, as amended, File No. 333-143648.
10.1	Montana Lease acquisition agreement with Montana Oil Properties dated October 5, 2007	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K12G3 filed with the Securities and Exchange Commission on March 22, 2007 (File No. 000-30955).
10.2	North Dakota lease acquisition agreement with Southfork Exploration, LLC, dated November 15, 2006	Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K12G3 filed with the Securities and Exchange Commission on March 22, 2007 (File No. 000-30955).
10.3	Form of Principal Shareholders Agreement, including exhibits	Incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K12G3 filed with the Securities and Exchange Commission on March 22, 2007 (File No. 000-30955).
10.4	Form of Warrant	Incorporated by reference to Exhibit 10.2 to the current report on Form 8-K filed with the Securities and Exchange Commission on September 14, 2007 (File No. 000-30955).

Exhibit No.	Description	Reference
10.5	Form of Registration Rights Agreement	Incorporated by reference to Exhibit 10.3 to the current report on Form 8-K filed with the Securities and Exchange Commission on September 14, 2007 (File No. 000-30955).
10.6	Placement Agency Agreement	Incorporated by reference to Exhibit 10.4 to the current report on Form 8-K filed with the Securities and Exchange Commission on September 14, 2007 (File No. 000-30955).
10.7	Form of Lock-Up/Leak-Out Agreement	Incorporated by reference to Exhibit 10.5 to the current report on Form 8-K filed with the Securities and Exchange Commission on September 14, 2007 (File No. 000-30955).
10.8	Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Michael L. Reger, dated January 30, 2009	Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on February 2, 2009 (File No. 000-30955).
10.9	Amended and Restated Employment Agreement by and between Northern Oil and Gas, Inc. and Ryan R. Gilbertson, dated January 30, 2009	Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on February 2, 2009 (File No. 000-30955).
10.10	Irrevocable Proxy Provided by Joseph A. Geraci II, Kimerlie Geraci, Lantern Advisers, LLC, Isles Capital, LLC and Mill City Ventures, LP, dated February 21, 2008	Incorporate by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on March 19, 2008 (File No. 000-30955).
10.11	Agreement by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008	Incorporate by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on April 16, 2008 (File No. 000-30955).
10.12	Second Amendment to Agreement by and between Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008	Incorporate by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on September 29, 2008 (File No. 000-30955).
10.13	Registration Rights Agreement By and Among Northern Oil and Gas, Inc. and Deephaven MCF Acquisition LLC dated April 14, 2008	Incorporate by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on April 16, 2008 (File No. 000-30955).
10.14	Lease Purchase Agreement By and Between Northern Oil and Gas, Inc. and Woodstone Resources, L.L.C.	Incorporate by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on June 17, 2008 (File No. 000-30955).
10.15	Northern Oil and Gas, Inc. 2009 Equity Compensation Plan	Incorporate by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on February 2, 2009 (File No. 000-30955).
10.16	Credit Agreement dated as of February 27, 2009 among Northern Oil and Gas, Inc., as Borrower, CIT Capital USA Inc., as Administrative Agent, and The Lenders Party Hereto	Incorporate by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on March 2, 2009 (File No. 000-30955).

Exhibit No.	Description	Reference
10.17	Form of Note Under that Certain Credit Agreement dated as of February 27, 2009 among Northern Oil and Gas, Inc., as Borrower, CIT Capital USA Inc., as Administrative Agent, and The Lenders Party Hereto	Incorporate by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on March 2, 2009 (File No. 000-30955).
10.18	Guaranty and Collateral Agreement dated as of February 27, 2009 made by Northern Oil and Gas, Inc. in favor of CIT Capital USA Inc., as Administrative Agent	Incorporate by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on March 2, 2009 (File No. 000-30955).
10.19	Guaranty and Collateral Agreement dated as of February 27, 2009 made by Northern Oil and Gas, Inc. in favor of CIT Capital USA Inc., as Administrative Agent	Incorporate by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on March 2, 2009 (File No. 000-30955).
10.20	Warrant to Purchase Shares of Northern Oil and Gas, Inc. Common Stock Issued to CIT Group/Equity Investments, Inc. on February 27, 2009	Incorporate by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on March 2, 2009 (File No. 000-30955).
14.1	Code of Business Conduct and Ethics, effective as of November 30, 2007	Incorporated by reference to Exhibit 99.3 to the Registrant’s Current Report on Form 8-K filed with the Securities Exchange Commission on December 6, 2007 (File No. 000-30955).
23.1	Consent of Independent Registered Public Accounting Firm Mantyla McReynolds LLC	Filed herewith
31.1	Certification of the Chief Executive Officer 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	Filed herewith
31.2	Certification of the Chief Financial Officer 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	Filed herewith
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	Filed herewith